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CONTENTS
JUNE.14
in the news
13
Study calls for more research on shale gas development
regional news
21
British Columbia
33
Northeastern Alberta
45
Southern Alberta
Progress Energy begins ramping up LNG drilling
Statoil integrating new technologies into SAGD operations
Marquee drills three successful Michichi wells
27
39
49
Northwestern Alberta
Cequence hits new production record
Central Alberta
Tourmaline boosts 2014 capital budget
Saskatchewan
Crescent Point says Torquay discovery huge
tech news
55
Sweetening the deal on sour gas control
features
COVER
FEATURE
58 Hunting elephants Canadian explorers track big resources around the globe
every issue
10 70
Stats at a Glance Political Cartoon
63 Global push Canadian service companies finding increasing opportunities abroad, shale pushes growth
Cover design: Peter Markiw
OIL & GAS INQUIRER • JUNE 2014
7
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Editor’s Note Vol. 26 No. 6 EDITORIAL EDITOR
Unconventional oil and gas driving demand for workers
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Scott Carline, Scott Deyoung, Lynda Harrison, Jacqueline Louie, Richard Macedo, James Mahony, Brian Marr, Pat Roche, Elsie Ross, Paul Wells EDITORIAL ASSISTANCE MANAGER
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Peter Markiw
CREATIVE SERVICES
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If you are wondering where all the oilfield workers are, look no further than the various unconventional oil and gas plays scattered across western Canada, says a new Petroleum Services Association of Canada study. The study, headed by Dave Yager, national leader for oilfield services at MNP LLP, found that the drilling of just over 6,000 horizontal wells in three areas of western Canada created the equivalent of about 61,000 40-hour-week direct jobs last year. The study uses three representative well profi les—one in northeastern British Columbia, one in central Alberta and one in southern Saskatchewan. The assessment includes all on-site services from the lease survey to drilling and completion to preparing the well for production. The first well type was in the Montney, Duvernay or Horn River and was located in northeastern British Columbia or northwestern Alberta. It was drilled to a measured depth of 6,000 metres, had an 18-stage frac, involved 46 suppliers and 302 workers, and required 2,871 worker days. In the case of these shale-type wells, completion-related services generated the biggest share of the direct employment at 38 per cent because of the size of the frac. At 30 per cent, drilling-related services accounted for the second-biggest share of the work. Logistics accounted for 18 per cent, and location, or wellsite, services created 14 per cent of the direct employment. The second well type was a Cardium, Viking or Slave Point well in central Alberta. It was drilled to a measured depth of 3,800 metres,
had 16 frac stages, 45 suppliers and involved 270 workers. Estimated worker days totalled 1,534. Because of the smaller frac and shorter wellbore, logistics accounted for the largest single portion of the worker days (33 per cent), followed by drilling and related services at 32 per cent, completion and related services at 20 per cent, and location services at 15 per cent. The third well type was a Bakken or Shaunavon well in southern Saskatchewan. “This would be the smallest and again these are averages, 3,000 metres measured depth in this particular case for this study,” with a 25-stage frac consuming only 6,800 cubic metres of water, Yager says. That well required 239 workers to visit the wellsite and generated 1,390 worker days of employment. “These are big numbers,” observes Yager. “If you wonder why you can’t fi nd anybody, it’s because they’re all working. “That’s just the direct employment on those specific wells—we haven’t gone down the supply chain,” he adds. “We’re only taking a slice of the industry.” With expansion in all these plays and new plays coming on stream, demand for workers should grow rapidly. Add in competition from oilsands expansion and potential new pipeline construction, and the pressure builds. The next decade could be a very good one for oilfield workers in western Canada. That is, of course, if the industry can fi nd them. Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
In Canada, year $ plus GST, years $ plus GST Outside Canada, year $
Subscription Inquiries Telephone: ... Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com GST Registration Number RT. Printed in Canada by PrintWest. ISSN - | © JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number . Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.
N EXT I S S U E July 2014 Oilfield hauling: A look at how the revolution in unconventional resource development is affecting heavy haulers. Plus: How operators are developing their strategies to build tight oil, natural gas liquids and dry gas reserves in central Alberta.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.
OIL & GAS INQUIRER • JUNE 2014
9
FAST NUMBERS
Number of rigs Progress Energy Canada Ltd. operated last winter.
$ billion
Amount Progress Energy Canada Ltd. plans to spend in 2014 ramping up for LNG export decision.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
Apr
Jun
T O TA L
MONTH
OTHER
OIL
GAS
D RY
SERVICE
Apr
Jun
Jul
Jul
Aug
Aug
Sep
Sep
,
Oct
Oct
Nov
Nov
,
Dec
Dec
Jan
Jan
Feb
Feb
,
Mar
Mar
,
Apr
Apr
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS DRILLED
C U M U L AT I V E *
Apr
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
MONTH
*From year-to-date
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Jul
Signalling and Notification
Process Equipment
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JUNE 2014 • OIL & GAS INQUIRER
Liquid Level Controls
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STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, May 12, 2014 Source: Rig Locator
Alberta, April 2014 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
OIL WELLS
Alberta
GAS WELLS
Apr
Apr
Apr
Apr
%
Northwestern Alberta
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
%
Southern Alberta
%
British Columbia
WC TOTAL
TOTAL
Top 10 Operators
Drilling Activity: CBM & Bitumen
January - March 2014 Source: Daily Oil Bulletin
Alberta, April 2014 Source: Daily Oil Bulletin
WELLS RIG RELEASED
TOTAL METRES
AVER AGE DEPTH
Canadian Natural Resources Limited
,
,
Crescent Point Energy Corp.
,
,
Husky Energy Inc.
,
,
Encana Corporation
,
,
Cenovus Energy Inc.
,
,
Progress Energy Canada Ltd.
,
,
ARC Resources Ltd.
,
,
Bellatrix Exploration Ltd.
,
,
ConocoPhillips Canada
,
,
Lightstream Resources Ltd.
,
,
O P E R AT O R
C OA L B E D M E T H A N E
Alberta
BITUMEN WELLS
Apr
Apr
Apr
Apr
Northwestern Alberta
Northeastern Alberta
Central Alberta
Southern Alberta
TOTAL
OIL & GAS INQUIRER • JUNE 2014
11
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IN THE
NEWS Issues affecting Canada’s E&P industry
development
Study calls for more research on shale gas development By Elsie Ross
Photo: Joey Podlubny
Despite decades of experience fracturing wells, information on its environmental impact is lacking, says a new study.
A new study by an expert panel on the environmental impacts of shale gas extraction in Canada has found that more research and information is needed on the process, even though the technologies and techniques used in extracting shale gas are understood. “Currently, data about environmental impacts are neither sufficient nor conclusive,” said the multi-disciplinary panel assembled by the Council of Canadian Academies. The study was commissioned in 2012 by then Environment Minister Peter Kent, who asked the panel to look at the state of knowledge of potential environmental impacts from the exploration, extraction and development of Canada’s shale gas resources and the state of knowledge of associated mitigation options. For Canada, regional context matters, according to the study. “Environments, ecosystems, geographies and geologies are not uniform across the country,” it says. “Therefore, consideration of different potential regional impacts needs to be closely considered when determining the suitability for shale gas development.” Shale gas development has moved forward in British Columbia and Alberta, while potential development is still being explored in Quebec, New Brunswick and Nova Scotia, the study points out. “Unlike the United States, Canadian development has moved at a slower pace,” it says. “This slower pace of development
presents a unique opportunity for Canada to take the time to explore and determine the proper management practices to develop its shale gas resources responsibly.” The panel’s assessment focused on: • Water (groundwater and surface); • Greenhouse gas emissions; • Land impacts and seismic events; • Human health; and, • Monitoring and research. The assessment of environmental impacts is hampered by a lack of many key issues, especially the problem of fluids escaping from incompletely sealed wells, says the study. “If wells can be sealed, the risk to groundwater is expected to be minimal, although little is known about the mobility and fate of hydraulic fracturing chemicals and wastewater in the subsurface,” it says. “The pertinent questions are difficult to answer objectively and scientifically, either because the relevant data have not been obtained; because some relevant data are not publicly available; or because existing data are of variable quality, allow for divergent interpretations, or span a wide range of values with different implications.” According to the panel, the greatest threat to well integrity is gas leakage from wells for which even existing best practices cannot assure long-term prevention. “The degree to which natural assimilation capacity can limit the impacts of
well leakage is site specifi c due to variability in the magnitude of natural gas fluxes (or loadings) and aquifer hydrogeochemical compositions,” it says. “These potential impacts are not being systematically monitored, predications remain unreliable, and approaches for effective and consistent monitoring need to be developed.” On average, about one-quarter to half of the water used in a single hydraulic fracturing treatment returns up the well to the surface after stimulation. This return flow, or flowback, is a potentially hazardous waste because it typically contains hydrocarbons including variable amounts of benzene and other aromatics, fracturing chemicals, and potentially hazardous constituents leached from the shale (e.g., salts, metals, metalloids and natural radioactive constituents), according to the report. “Although flowback water is now commonly re-used in later fracturing treatments, a fraction eventually remains that poses technical challenges for treatment where deep wastewater injection for disposal may not be feasible.” The report notes that the technologies used by the shale gas industry have developed incrementally over several decades. “The gradual evolution of shale gas technologies has obscured the full implications of the large-scale deployment of these technologies,” it says. In most instances, shale gas extraction has proceeded without sufficient environmental baseline data being collected (e.g., nearby groundwater quality, critical wildlife habitat), says the study. “This makes it difficult to identify and characterize environmental impacts that may be associated with, or inappropriately blamed on, the development.” Some of the possible environmental and health effects of shale gas development OIL & GAS INQUIRER • JUNE 2014
13
In The News
may take decades to become apparent, it says. These include the creation of subsurface pathways between the shale horizons being fractured and fresh groundwater, gas seepage along abandoned wells, and cumulative effects on the land and communities. Monitoring that has been done indicates that gas leakage into aquifers and the atmosphere is frequent enough to raise concern, the panel found. “Given the likely future density of gas wells, shale gas development is expected to have a greater long-term impact than conventional oil and gas development,” the study notes. Appropriate environmental monitoring approaches for the anticipated level of shale gas development have not yet been identified, it says. Monitoring programs will have to be adapted to advances in technologies and to the location, scale and pace of future development. “To gain public trust, monitoring needs to engage both the people living in affected areas and independent experts,” it notes. “The public will have greater faith in monitoring if it can influence the design, can access the results and can comment.”
one per cent
PSAC ups well count by one per cent The Petroleum Services Association of Canada (PSAC) expects 11,170 wells to be rig released this year, about one per cent more than in 2013, the service company group said in its revised 2014 forecast on April 30. PSAC’s revised forecast includes 370 more wells than its original 2014 forecast released last October. The updated forecast assumes an average AECO natural gas price of $4 per thousand cubic feet, a West Texas Intermediate oil price of US$95 per barrel, and a Canada/U.S. currency exchange rate averaging 90 cents. “With a longer winter than normal across Canada this year and a breakup with continued activity in the second quarter, drilling activity is keeping on par with our original forecast in October,” said Mark Salkeld, president and chief executive officer of PSAC. “Activity remains steady for our member companies and many companies have been facing challenges with meeting demand as the shortage of skilled labour continues.”
11,170 Number of wells PSAC says will be drilled in Canada in 2014
PSAC now estimates 6,530 wells will be drilled in Alberta this year, representing less than a one per cent decrease from the original forecast. British Columbia rig releases are expected to rise to 623 wells from 550, a 13 per cent gain. Saskatchewan’s projected 2014 well count has been increased by 11 per cent to 3,562 wells. Manitoba is now expected to drill 45 fewer wells at 435 for the year, a nine per cent decrease. “The increase in activity in Saskatchewan can be attributed to the continued focus towards oil and the increasing use of rail to move product to market,” Salkeld said. — DAILY OIL BULLETIN
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JUNE 2014 • OIL & GAS INQUIRER
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pressure pumping
In The News
Low-ball bidding hitting pressure pumping sector By Paul Wells
Several pressure pumpers, including Canyon Services Group Inc., said undisciplined pricing by a couple of competitors upset the pricing-versus-cost dynamic during the first quarter of 2014. The current low-price/high-cost environment that is negatively affecting pressure pumpers in western Canada will continue in the short term; however, the situation is not sustainable and a market correction is likely to occur this summer. And some companies in the sector are pointing fi ngers at a small number of competitors who have low-balled work bids to the point that the level of overall pricing for pressure pumpers has been degraded. “There are companies out there bidding for work at cost. It’s not sustainable. It disrupts the market for everybody else who is trying to run a profitable business,” said Joe Peskunowicz, Canyon’s executive vicepresident, corporate. While he said there’s been a “modest” uptake in pricing of late, the company is
still feeling the effects, especially in light of rising costs. “The undisciplined pricing by a couple of competitors, coupled with the U.S. frac sand exchange rate [sand is sourced from the United States and paid for in U.S. currency] and fuel and labour costs, which have both gone up, has made it difficult. We managed to get some recovery in the latter half of the first quarter on the exchange rate and fuel, and the final quarter of 2013 was the bottom in pricing as far as we’re concerned,” he said. Fernando Aguilar, president and chief executive officer of Calfrac Well Services Ltd., agreed that a few low bidders upset the pricing-versus-cost dynamic. He noted that it’s not only U.S. competitors undercutting pricing, but also some of the smaller Canadian competitors that he believes, “in desperation,” were trying to nail down work toward the end of the year even at little to no margin. “They came with lower pricing. In fact, we had an example where one of our key
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customers tendered the work, and a smaller competitor came with a 43 per cent price differential. Even though this customer is very high in terms of quality and safety, they couldn’t defend that operational position when you have a competitor that claimed to do the work for 43 per cent less,” Aguilar said. “We can guarantee that that competitor is going to lose money in an operation like that. At the same time, some American competitors were trying to get work, they lowered their price as well. That happened in November. That’s why, when the industry talks about price increases, we don’t feel pricing is going to go up very quickly, because you still have people who are willing to do the work for lower pricing.” Dana Benner, managing director of institutional equity research, oilfield services, with AltaCorp Capital Inc., said that price cutting by some service companies late last year has carried over and contributed to the lower pricing reality pressure pumpers are contending with early in 2014.
Saskatchewan continues to experience rapid economic growth year after year. Potash mines are multiplying across the Province, construction cranes are rising above our cities, and power plants are increasing their capacities. Each mine, industrial site, refinery, or office building needs a dependable supply of natural gas to power its expansion and future operation. TransGas is strategically positioned to provide safe and reliable natural gas transportation and storage services to support this unprecedented growth in Saskatchewan.
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1-306-777-9900 OIL & GAS INQUIRER • JUNE 2014
15
In The News
“ As much as we love our relationship with producers and maybe signing long-term deals like three- to five- year contracts for so many wells, there’s all sorts of different strategies. It’s always like, who’s holding the gun now?”
— Mark Salkeld, president and chief executive officer, PSAC
“A lot of times you’ve got a good feel for how strong the winter season is going to be and that helps you set a floor on pricing, or you try to push through pricing increases, but there seemed to be a lack of clarity on the strength of the winter,” he added. “And I think amidst that lack of clarity, there were at least one or two fracturing companies that came in and took some incremental work at lower prices, and companies that wanted
to maintain their market share choose to match that pricing, even if it wasn’t across the board, for some of the work.” Petroleum Services Association of Canada (PSAC) president and chief executive officer Mark Salkeld said the current cost and pricing environment is indicative of the cyclical nature the service sector has historically grappled with. Sometimes the service providers hold the cards, other times it’s their customers that deal from strength. “The pressure is on. As much as we love our relationship with producers and maybe signing long-term deals like three- to fiveyear contracts for so many wells, there’s all sorts of different strategies. It’s always like, who’s holding the gun now?” he said. “This winter was busy and there was a while there that it seemed the fracturing/ pumping services market was a little bit overloaded with equipment. But a couple of outfits have shut down Canadian operations or they’ve taken equipment down to the U.S. where it’s busier and there’s better demand,” he added. “The market kind of balances itself out. It’s just the plain old principle of economics— supply and demand.”
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Canadian
Canadian pipelines reflect shifts in North American markets, says NEB
The dramatic shifts in North American natural gas markets and oil markets over the past eight years have had a significant impact on Canada’s pipeline systems, says a new study from the National Energy Board (NEB). Technological advances such as horizontal wells and hydraulic fracturing have made large-scale production of shale gas and shale oil economically viable even as Canadian oilsands production has continued to grow, said the board in its Canadian pipeline transportation system energy market analysis. “As a result, existing oil pipelines are generally full, new oil pipeline projects are under way and more oil has been moving by rail,” said the board. “New sources of natural gas are entering Canada through Ontario, reducing throughput on TransCanada Pipelines Limited’s mainline from Alberta to markets in the East.”
In The News
Photo: TransCanada Corporation
Oil pipeline constraints remain a serious problem despite recently added capacity, says the National Energy Board.
Energy markets have been responding to these changes, said the board. “Some adjustments happen quickly, while other adjustments take time.” In its assessment, the NEB detailed the significant displacement of western Canadian gas and sharply reduced volumes on the TransCanada Mainline due in large part to
the growth in Marcellus shale production to 12.3 billion cubic per day in 2013 from 2.1 billion cubic feet per day in 2008. Significant new pipeline capacity also was built in the United States during this period to transport new Marcellus production to markets, including those in Ontario. TransCanada’s Niagara export point was reduced to an import point,
further displacing the need for long-haul volumes through the Prairies segment. In the first nine months of 2013, throughput on the Prairies segment of the Mainline averaged two billion cubic feet per day for an average utilization rate of 29 per cent of capacity, down from 45 per cent in 2011 and 34 per cent in 2012. On the oil-pipeline side, overall capacity out of Canada was constrained as indicated by significant apportionment on the Enbridge Inc. Mainline and Kinder Morgan Canada Inc.’s Trans Mountain systems, says the study. “Rapid growth in western Canadian oilsands and U.S. tight oil production created a surplus of oil in the mid-continent since 2011, exacerbated by limited pipeline capacity to coastal markets.” Although oil pipeline capacity has recently been added out of western Canada, constraints on connecting pipelines and capacity reductions on major lines limited capacity from 2010 to 2013, it says. As a result, rail becomes an increasingly important alternative method for transporting western Canadian crude oil to higher value markets. Even if rail costs are double or triple the pipeline tolls, the
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17
In The News
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price discounts generally exceed the cost of rail transportation, according to the board. From January through November 2013, an average of 123,000 barrels per day of crude oil was exported to the United States by rail. The Enbridge Mainline and Lakehead systems combined are designed to export about 2.5 million barrels per day, but constraints on sections of the U.S. system have reduced the actual crude oil capacity out of western Canada to Superior, Wis., to about 1.9 million barrels per day, says the study. Appor t ion ment on t he E nbr idge Mainline system generally occurs downstream of Superior; Enbridge Line 5 from Superior to Sarnia, Ont., has consistently been under apportionment since September 2010, according to the board. Trans Mountain also has been under apportionment for the past several years, although it has proposed changes to nominations in an effort to reduce apportionment until a proposed pipeline expansion to 830,000 barrels per day. The pipeline transports crude oil, and refi ned and semi-refi ned petroleum products west from Edmonton to locations in both British Columbia and Washington. It also ships crude oil to offshore markets via its Westridge Marine Terminal in Burnaby. In 2012, average throughput on Trans Mountain was 290,000 barrels per day, averaging 297,000 barrels per day for the first half of 2013. TransCanada’s base Keystone Pipeline from Hardisty to Cushing, Okla., also has long-term contracts of most of its export capacity of 531,000 barrels per day. In 2012, throughput averaged 505,000 barrels per day, approximately 85 per cent of capacity, increasing to 515,000 barrels per day (87 per cent of capacity) in the fi rst half of 2013. The Express Pipeline system, owned by Spectra Energ y Cor p., transports crude oil from to markets in the Rocky Mountain region including Montana, Wyoming, Utah and Colorado. It connects with the Platte Pipeline at Casper, Wyo., for deliveries to refineries located in Kansas and Illinois. Although Express has a capacity of 280,000 barrels per day, the effective Canadian capacity is about 200,000 barrels per day due to constraints on the Platte system, increasing competition for capacity from Bakken tight oil production, and limited market demand in the Rockies.
BRITISH COLUMBIA WELL ACTIVITY APR/13
APR/14
Wells licensed
APR/13
APR/14
Wells spudded
APR/13
APR/14
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
B.C. British Columbia
Progress Energy begins ramping up LNG drilling By Pat Roche
Although Malaysia’s PETRONAS won’t decide until the end of this year whether to export liquefied natural gas (LNG) from Canada, the company is already pumping billions of dollars into the Canadian economy. During the past winter, Progress Energy Canada Ltd., a wholly owned subsidiary of PETRONAS, operated about 28 rigs, making it one of the busiest drillers in the country and a big reason British Columbia’s oilpatch has been busy so far in 2014. Progress typically ran two rigs in Alberta and 25 or 26 on its North Montney project in northeastern British Columbia through the past winter. Even though the number of rigs the company was running dropped to 12 due to spring breakup, it is still the third-busiest driller in the country. In an interview with the Daily Oil Bulletin, Progress president and chief executive officer Michael Culbert discussed why he believes PETRONAS’s proposed West Coast LNG project has an edge over more than a dozen competing projects. He also talked about what has to happen for the project to proceed and what that would mean in spending and activity through the decade and beyond. Just this year alone, Progress plans capital spending of $2 billion, Culbert said. That doesn’t include acquisitions such as the $1.5-billion purchase of Talisman Energ y Inc.’s interest in t wo Nor th Montney partnerships in the Farrell Creek and Cypress areas of northeastern British Columbia. That purchase closed in March. Progress is currently in appraisal mode, drilling to establish 15 trillion cubic feet of proved plus probable reserves by year-end 2014 when PETRONAS will decide whether to proceed with an LNG
project. Fifteen trillion cubic feet would provide a natural gas liquefaction plant with two billion cubic feet per day of natural gas feedstock for 20 years. The North Montney lands will feed the fi rst two trains of the proposed LNG project, called Pacific NorthWest LNG. Progress is already more than halfway toward its goal. In 2013, the company tripled the proved-plus-probable reserves at its North Montney project to more than eight trillion cubic feet. Culbert said all the gas that is being drilled is being brought on production, involving a huge midstream investment by Progress and third parties. He said 850 kilometres of gathering lines are to be built this year. Numerous compressor stations are to be built or expanded. A new gas plant is currently being commissioned in the Caribou area with initial capacity of 100 million cubic feet per day. In the third quarter of 2012, its last full quarter as an independent company, Progress reported average production of 43,045 barrels equivalent per day. Culbert said the company is now managing output of about 100,000 barrels equivalent per day, including production owned by minority interest holders in its North Montney project. “That includes about 12,000 barrels equivalent a day from Alberta, and includes the Talisman acquisition, which was about 12,000 barrels equivalent per day. The rest is coming out of the North Montney,” he said. T he t ranspor tat ion and processing agreements Progress has in place, combined with capacity the company is building itself, will meet short- and medium-term needs.
Top Montney gas drillers Horizontal Progress Energy Canada Ltd.
Vertical
Total
--
Encana Corporation
Royal Dutch Shell plc
--
Canadian Natural Resources Limited
--
Talisman Energy Inc.
ARC Resources Ltd.
--
Birchcliff Energy Ltd.
--
Tourmaline Oil Corp.
--
Paramount Resources Ltd.
--
Advantage Oil & Gas Ltd.
--
Source: Daily Oil Bulletin
“But sooner or later, sometime during 2015, we’ll maximize the available current capacity,” Culbert said. To handle longerterm growth, Progress has secured agreement from TransCanada Corporation to both extend its NOVA Gas Transmission system into the North Montney region and build an 850- to 900-kilometre pipeline to deliver North Montney gas to the Prince Rupert area on the coast. This obviously depends on PETRONAS’s LNG plans proceeding. The project has already received export approval from the National Energy Board and the federal government. Pacific NorthWest is currently going through an environmental assessment with the federal and B.C. governments for the proposed LNG facilities. OIL & GAS INQUIRER • JUNE 2014
21
British Columbia
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As Progress proves up the reserves, TransCanada is going through its engineering and environmental process, and Pacific Northwest LNG is doing its regulatory and engineering studies. All are to be fi nished in the fourth quarter in time for a year-end fi nal investment decision. So will the pace slacken once Progress has proved up 15 trillion cubic feet of proved plus probable reserves by year-end 2014? Not at all, said Culbert. “We really see ourselves, once a positive fi nal investment decision is made, maintaining this pace... from 2015 throughout 2019, even 2020, to increase our production up to two billion cubic feet a day.” That would mean running roughly 28 rigs pretty much yearround, with the exception of spring breakup, for about the next fi ve years. Matching the drilling intensity would be the pace of midstream construction as the company ramps up its capacity to process and transport two billion cubic feet per day. Once the LNG facility is operating and the fi rst shipments are exported, facility construction will be significantly reduced, but Progress will still drill about half as many wells each year just to offset natural declines, Culbert said. “So when you look at this in the scope of a 25-year project— five years ramping up and then 20 years maintaining—it’s a very large capital commitment.” If the LNG project goes ahead, Progress expects to spend an average of $2 billion to $2.5 billion per year for the next five years until LNG shipments begin. First exports are slated for late 2018 or early 2019.
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Based on field estimates, in the fi rst week of April Painted Pony Petroleum Ltd. exceeded 15,000 barrels equivalent per day of production weighted 86 per cent toward natural gas. Broken down, output included 79 million cubic feet per day of raw natural gas production and 2,050 barrels per day of crude oil and natural gas liquids production. The company has increased its second quarter 2014 production estimate by 17 per cent to 13,500 barrels per day (86 per cent natural gas) from previous estimates of 11,500 barrels per day, as a result of better than anticipated well results at Blair and Townsend. This represents increases of approximately 38 per cent over firstquarter 2014 estimated production of 9,750 barrels equivalent per day, and 70 per cent over second-quarter 2013 production of 7,928 barrels per day. Average annual production estimates for 2014 have now been increased to 13,000 barrels equivalent per day, a 50 per cent bump over average production in 2013 of 8,693 barrels per day. The company has drilled five Montney wells to date as part of a 17-net-well 2014 Montney drilling program. It has also completed four Montney wells to date in 2014, including two Montney wells at Townsend and two Montney wells at Blair. At Townsend, Painted Pony has recently completed the commissioning of its 100 per cent owned and operated natural gas processing facility at the 33-J pad with a design capacity of 25 million cubic feet per day.
British Columbia
Since April 1, 2014, field-estimated condensate yields at this facility have been 40 barrels per million cubic feet and receive a price that approximates the Edmonton Par reference price for light oil. Painted Pony anticipated reaching full capacity at this facility by the end of April 2014. The Townsend property is the site of the company’s highest liquids-yield production within its B.C. Montney assets. In addition, Painted Pony recently completed two 100 per cent working-interest Montney wells at Townsend. A Lower Montney well and an Upper Montney well have been flow-testing in line through the company’s new natural gas processing facility since April 1, 2014. These wells have flowed at a combined average raw-wellhead rate of 12 million cubic feet per day plus associated condensate of 480 barrels per day over three days. The company has undertaken a pre-engineering study with a third-party midstream company to build a refrigeration and natural gas plant facility with an expected capacity of approximately 190 million cubic feet per day. Final approval of the study is anticipated by the end of the second quarter of 2014. The plant is expected to be operational during the second half of 2015 and is anticipated to reduce transportation, processing and operating costs, and increase liquids yields. At Blair, Painted Pony drilled five Montney wells to date in 2014. The company completed two of the 100 per cent working-interest Montney wells on the 41-F pad drilled to date, and anticipates completing the remaining three 100 per cent working-interest Montney wells during the second quarter of 2014. Both of the completed wells are Upper Montney producers that have been testing in line since late March 2014. In the first week of April, these wells flowed at a combined average raw-wellhead rate of 20.8 million cubic feet per day with an estimated 312 barrels per day of liquids. The production results of the Montney wells have exceeded the company’s expectations in the Blair area and confirm the continued success of the open-hole ball-drop completion technology used by Painted Pony. These early indications from well performance have confi rmed the step-change in terms of both production volumes and reduced costs. Painted Pony is currently producing natural gas from the Blair property through a third-party midstream facility and is evaluating options for increasing processing capacity at this plant. — DAILY OIL BULLETIN
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Crew acquires Montney acreage Crew Energy Inc. has completed the acquisition of Montney liquidsrich natural gas properties in northeastern British Columbia for approximately $105 million. The acquired assets include 75-net sections of land that are either contiguous with existing Crew land or increase the company’s working interest in joint-interest lands. In a separate transaction, Crew has entered into an agreement to sell petroleum and natural gas assets (75 per cent natural gas) focused primarily in the Deep Basin of Alberta in exchange for approximately $222 million in cash before closing adjustments
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British Columbia
30,400
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plus approximately 400 barrels per day of heavy oil production. Upon completion of the disposition, Crew plans to expand its previously announced 2014 exploration and development capital program by $39 million to $285 million to accelerate the company’s Montney development. The approximately 75 sections of highly prospective Montney rights are in the Septimus and Groundbirch areas. Current production is 1,400 barrels equivalent per day (98 per cent natural gas) based on field estimates. Total proved reserves are 4.7 million barrels equivalent (94 per cent natural gas) and total proved-plus-probable reserves are 8.5 million barrels (93 per cent natural gas). Crew drilled 19 net wells in the first quarter. The company drilled five Montney wet gas wells, 7.6 net heavy oil wells at Lloydminster, six oil wells at Princess and one (0.4 net) oil well at Pine Creek. Crew currently has two rigs operating in northeastern British Columbia drilling a two-well pad at Groundbirch and a six-well pad at Septimus. Crew’s results at Septimus continued to be strong with two wells coming on production at the end of the quarter at six million to eight million cubic feet per day. Crew re-tested the fourth-quarter 2013, 01-24 oil well at Tower for 11 days with an average flow rate of 720 barrels equivalent per day (540 barrels per day of oil) validating light oil production 11 kilometres northwest of the company’s existing Montney oil production. This well is expected to be tied in during the third quarter. Current production based on field estimates is 30,400 barrels equivalent per day, which is inclusive of the 1,400-barrel-perday acquisition that closed in late March. Production in the first quarter is expected to average approximately 28,000 barrels per day as the majority of fi rst-quarter drilled wells came on production late in March. After spring breakup subsides, Crew’s northeastern B.C. plans include completing two Groundbirch wells, completing a six-well pad at Septimus, spudding a five-well pad at Septimus, spudding a six-well pad at Tower, and beginning construction of the Tower oil facility and the new Septimus gas facility. — DAILY OIL BULLETIN
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JUNE 2014 • OIL & GAS INQUIRER
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NORTHWESTERN ALBERTA WELL ACTIVITY APR/13
APR/14
Wells licensed
65
126
APR/13
APR/14
Wells spudded
52
111
APR/13
APR/14
97
126
Rigs released
▲
▲
Northwestern Alberta
▲
Source: Daily Oil Bulletin
Cequence hits new production record Cequence Energy Ltd. says output reached a record 14,000 barrels equivalent per day during the second half of April, following the start-up of the Ansell facility and the completion of its winter capital program. At Simonette, the fi nal two wells of its Montney winter drilling program were completed and are producing with much higherthan-average liquids yield in the area, the company said. Management believes the 13-35-06127W5 Montney well is an important step out on the northwestern flank of the field. The 2,289-metre lateral well was completed with a 26-stage frac. After 10 days of testing and production, the 13-35 well is now producing 1,540 barrels equivalent per day, comprised of 6.3 million cubic feet per day of natural gas and 345 barrels per day of free condensate. The company’s 16-10-061-01W6 Montney well, in the southwestern corner of the field, was drilled with a shorter-than-average lateral length of 1,860 metres and was completed with a 21-stage slickwater frac. After 18 days of testing and production, the 16-10 well has stabilized at a rate of 370 barrels equivalent per day, including 1.2 million cubic feet per day of gas and 138 barrels per day of free condensate. Management believes the 16-10 well extends a Montney oil trend south from the 15-12 well drilled in 2011.
Cequence is evaluating these results and the opportunity to improve potential recoveries with optimized completion techniques. The 16-10 well is currently tied-in to a third-party gathering system and is producing into the Keyera Corp. Simonette plant for test purposes prior to a tie-in to the Cequence gathering system. A Montney well drilled at 14-24 (was 10-24) on January 21 is outperforming the model rate and has now produced for 92 days with an IP90 of 1,275 barrels equivalent per day, comprised of 6.2 million cubic feet per day of gas and 86 barrels per day of condensate. Management believes the 14-24 well has successfully delineated an undrilled portion of the field. Cequence has a 65 per cent working interest in the 05-02-061-02W6 well, which has now produced for 93 days with an IP90 of 1,811 barrels per day, comprised of eight million cubic feet per day of gas and 147 barrels per day of free condensate. (All production volumes are gross.) Additional Dunvegan locations are planned for the second half of 2014 as model wells in this area would achieve payout in six months at current prices. Based on field estimates, 2014’s fi rstquarter output increased by about 10 per cent from the fourth quarter of 2013 to approximately 11,500 barrels equivalent per day despite production delays resulting
Cequence Energy Ltd. five-year plan Year
Average production
Wells
Capex ($million)
84
14
120
96
18
170
21,500
129
23
200
26,000
156
33
270
36,000
216
52
430
boe/d
MMcfe/d
2014
14,000
2015
16,000
2016 2017 2018
Source: Cequence Energy Ltd.
from mechanical completion problems on two wells completed in January. Remedial operations from these two wells are currently planned for the third quarter of this year. The results of Cequence’s winter program have confirmed management’s expectations over most of the existing field and have confi rmed a broad area with higher liquids yield on the western side of the field. Cequence is now ready to enter the development drilling phase in the Montney at Simonette and will be moving to a multiwell-pad drilling program starting this summer. Other operators have seen significant cost savings as they have transitioned to pad drilling, said Cequence, and it expects similar savings. The company said it has invested significant capital in its 100 per cent owned strategic infrastructure, which can be easily expanded to accommodate future volumes from multi-well-pad locations. At Ansell, the gathering system and compression facility at 12-31 was completed in early April and the start-up of new wells drilled in the first quarter began shortly afterward. In the past few days, Ansell production has reached 25 million cubic feet per day (12.3 million cubic feet per day net to Cequence, which owns a 49 per cent interest in the facilities and production) as six of the seven wells drilled to date are now on production. Its partner in the area has two remaining farm-in wells to drill to earn an interest in the balance of Cequence’s 100 per cent lands in the area. Cequence said it expects its partner at Ansell to propose an active drilling program in the second half of 2014 to continue to delineate “this exciting new discovery” and to begin a development drilling program. — DAILY OIL BULLETIN OIL & GAS INQUIRER • JUNE 2014
27
Northwestern Alberta
AER releases revised flaring and venting directive as a result of Peace River odour worries By Elsie Ross
The Alberta Energy Regulator (AER) has accepted all the recommendations within its jurisdiction of an independent panel that conducted a hearing into odours and emissions from cold heavy oil production with sand (CHOPS) operations in the Peace River area. “The AER is taking immediate actions on the recommendations, and there are a number of recommendations that we are implementing either immediately or very, very quickly,” Carol Crowfoot, vicepresident of the regulatory operations and economics branch, told a technical briefing in April. “The AER believes that the recommendations are certainly valid and will go a long way in hopefully eliminating the odour and emissions from that area.” All new licensed heavy oil and bitumen operations in the Peace River area will be required to capture produced gas by May 15,
28
JUNE 2014 • OIL & GAS INQUIRER
2014, while existing heavy oil and bitumen operations in the Three Creeks and Reno areas have until Aug. 15, 2014, to do the same. Operators in the Seal Lake and Walrus areas, which did not participate in the proceeding, must submit a report to the AER by June 15, 2014, outlining targeted actions to achieve a phased reduction and eventual elimination of venting in the two areas. The major players in the Peace River area are Baytex Energy Corp., Murphy Oil Corporation, Penn West Petroleum Ltd. and Shell Canada Limited. Jim Ellis, president and chief executive officer of the AER, ordered the proceeding in July 2013 to ensure residents had a chance to express their concerns in a public forum that included a review of industry practices and potential solutions to the issue. The regulator will be working to address odour issues in the area by conserving produced gas,
reducing and eventually eliminating venting of produced gas in the area. The AER also has released a revised version of Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, which follows a stakeholder consultation period that ran from May to July of 2013. The revised directive, which will become effective June 16, 2014, strengthens regulations to reduce impacts related to flaring, venting and incineration and increases opportunities for gas conservation in Alberta, said Crowfoot. Baytex, the focus of many of the public complaints, welcomed the AER’s response, adding that it has already been implementing a number of the panel’s recommendations. The company said its operations are compliant with existing regulations and it plans to comply with the new regulations within the specified timelines.
Photo: Joey Podlubny
Northwestern Alberta
“Baytex’s gas conservation activities and plans are consistent with the AER i n it iat ives announced today,” James Bowzer, president and chief executive officer of Baytex, said in a news release. In Three Creeks, an expansion to conservation facilities owned by Baytex and its partner Genalta Power Inc. is already underway, while in the Reno field, which Baytex acquired in 2011, excess natural gas is conserved through the connection of its recently constructed pipelines to the TransCanada PipeLines Limited system. “Work is underway to fulfi ll our commitment of capturing tank top vapours from all existing and future well sites,” said the company. “Through the AER’s regulatory initiatives announced today, Baytex believes all the conditions and regulations are in place to develop the resources in the Peace River area in a manner that will provide long-term benefits and well-being to the community and the people of Alberta,” said Bowzer. Ch r is Severson-Ba ker, ma nag i ng director of the Pembina Institute, also
Flaring during a well test. New gas conservation regulations will limit the practice in Alberta.
welcomed the A ER’s announcement, describing it as positive step toward responsible energy development by recognizing the odour-related health concerns around Peace River and by accepting all the recommendations made during the public investigation. “Though this decision is long-overdue— odours were fi rst reported by residents in 2009—it provides one tangible example where the Alberta Energy Regulator has established a transparent public process to deal with a major public concern,” he said. “We hope this represents the beginning of a new approach to addressing the environmental and health concerns of Albertans. “We now are looking for clarity from the Alberta government as to how those recommendations outside of the Alberta Energy Regulator’s jurisdiction will be addressed to ensure residents’ safety is paramount.” The new regulations, in conjunction with the revised Directive 060, will also include a focused surveillance compliance program for the Peace River area,
OIL & GAS INQUIRER • JUNE 2014
29
Northwestern Alberta
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JUNE 2014 • OIL & GAS INQUIRER
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and if non-compliance is found, enforcement action will be taken, said Crowfoot. That could result in the shut-in of a well or facilities. Other recommendations within the AER’s jurisdiction will take longer to implement, and it is currently developing a strategy to examine each one, said Crowfoot. For example, it is beginning to look at gas conservation in the Peace River area and will review the feasibility reports that come in from the industry on the options and timelines to conserve all gas at sites in the area. The reports from operators are to be submitted to the AER by Oct. 31, 2014, and then a project team will be formed to look at the issue. “Hopefully it won’t take very long.” The AER also will be looking at ways to deal with upset and emergency flaring and ways to reduce and eliminate fugitive emissions as well as emissions from truck loading in the Peace River area. Flaring will end as soon as gas conservation is in place and a well will be shut in if the operator cannot continue to capture gas, she said. In addition, the AER is initiating a project to look at play-based regulation in the Peace River area based on the particular risks of the Gordondale Formation–sourced bitumen, which has higher levels of sulphur and aromatic compounds. It will review regulatory requirements for operators in the Peace River area to collect and submit geochemical analysis of heavy oil from the formation. The regulator is collaborating with Alberta government ministries to establish and expand on a regional air monitoring program. One of the changes to Directive 060 is that the regulator has the ability to implement mandatory conservation of solution gases for specific areas and projects, regardless of economics. However, that provision will not be applied in all areas of the province, Gerald Palanca, technical specialist, said in the briefing. “It is going to be used at our discretion, and this regulatory tool is in place partially so that we can use it on a play basis, so it will be applied to the play in the Peace River area.” The driving force was actually to give the AER the tools for the whole concept of the social licence to operate, Palanca said. “We intend to use this tool where operations are occurring and affecting people,” he said. “In isolated areas, we may not use that conservation tool.”
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NORTHEASTERN ALBERTA WELL ACTIVITY APR/13
APR/14
Wells licensed
APR/13
APR/14
Wells spudded
APR/13
APR/14
Rigs released
▼
▲
▲
Source: Daily Oil Bulletin
N.E.
Northeastern Alberta
Statoil integrating new technologies into SAGD operations By Lynda Harrison
The 14 new technologies Statoil Canada Ltd. will test and deploy over the next five to 10 years will create a step-change in its steam assisted gravity drainage (SAGD) performance, said the company. The technologies are designed to reduce the amount of energy and water used to produce bitumen while improving overall bitumen recovery and sustainability at Statoil’s existing and planned SAGD operations. Statoil plans to employ flow-control devices, multilaterals, infi ll wells and solvent co-injection as an integrated system, plus it has a few more technologies up its sleeve that it is not yet ready to disclose. While none of the technologies are especially novel on their own, using them together is, Victor del Valle, Statoil’s heavy oil technology centre portfolio leader, said. The technologies were selected following two years of extensive analysis and model simulations to identify opportunities for Statoil’s next proposed oilsands development, the Corner project, as well as a major expansion of its Leismer demonstration project. If successful, they are expected to achieve a 10–15 per cent reduction in the steam to oil ratio (SOR). Similar SOR reductions are expected if the technologies are incorporated at Leismer. Some of the technologies are new, while others have been developed and implemented by other oilsands developers, said Statoil. Probably the most promising initial technolog y to increase production is aimed at oilsands deposits that are interbedded with shale barriers, where Statoil sees a huge opportunity to open up its
reservoirs and extract the trapped oil, said del Valle. This will be done through a mechanical breakthrough such as directional drilling (creating short-length multilaterals near the wellbore) and small-hole drilling, said del Valle. “Physically, mechanically breaking through, you know that you have broken through the layer, you know you can model the permeability changes very well and you can get a good feel for what the recovery process is,” said del Valle. “It’s really applying what we know in a new way to solve a problem.” He estimates this technology can provide about 20 per cent more production than would otherwise be possible. This won’t be done until toward the end of the project’s life, however, since the company goes after the most economic barrels, “the standard SAGD barrels,” first, he said. Infi ll wells and well-spacing optimization will also be introduced further along in the project, he added. The company is exploring outflow and inflow devices used during completions to better manage steam. Instead of using a stand-alone system that chokes the flow based on a pressure drop, Statoil is investigating automated valves it can control from surface to shut down and open up zones and control steam more “deterministically,” said del Valle. These flow-control devices should also help with solvents, he said. While steam loss is inefficient, solvent loss is even worse, so Statoil is investigating solvent co-injection and infill wells together. The use of rifle tubes, which Suncor Energy Inc. has been piloting in partnership
with Statoil, has the potential to improve steam quality, said del Valle. This is the same technology that makes a bullet spin as it exits a rifle, he explained. “A rifle gun is helixed to make the bullets spin and we want the same thing for the water; we want it to spin around the tube,” he said. “It’s tubes in the boiler that
“It’s really applying what we know in a new way to solve a problem.” — Victor del Valle, heavy oil technology centre portfolio leader, Statoil Canada Ltd.
have an etching that spiral around so that you can evenly wet the tube, because when you have thin and thick spots of water in a tube, you can get build up and deposit. If I can distribute the water evenly around the tube, I can go to a lower quality and reduce the amount of deposits.” Most of the technologies are already in use by other companies. A few are unique to Statoil, but del Valle would only say they relate to surface facilities and are not “earth shattering or groundbreaking,” but will fit into the puzzle. Statoil and Thailand-based exploration and production company, PTT Exploration and Production Public Company Limited (PTTEP), announced in January that they will divide their shared Kai Kos Dehseh (KKD) project so that Statoil will continue as operator and 100 per cent owner of KKD’s Leismer and Corner development OIL & GAS INQUIRER • JUNE 2014
33
Northeastern Alberta
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projects while PTTEP will own 100 per cent of the Thornbury, Hangingstone and South Leismer areas. The deal is expected to close by the third quarter of 2014. Leismer consists of four operating well pads with 21 operating SAGD well pairs. A fifth well pad with seven well pairs was added in the second quarter of 2013, with an expected first-steam date of second-quarter 2014. Leismer’s current facilities are designed to produce 20,000 barrels per day; however, the project has regulatory approval to produce 40,000 barrels per day. To increase production, Statoil has submitted construction, operation and environmental plans for Leismer Acceleration Phase 2 to the Alberta Energy Regulator (AER) and Alberta Environment and Sustainable Resource Development. Statoil also has regulatory approval to produce 40,000 barrels per day from its Corner lease area. Amendments have been submitted to the AER and Alberta Environment to modify the original, approved plans for developing Corner. The amendments do not increase production limits or the physical footprint of Corner, but will result in an improved design for its facilities and well pads.
Scientist optimistic about demise of tailings ponds By Lynda Harrison
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JUNE 2014 • OIL & GAS INQUIRER
Tailings ponds have become a lightning rod for oilsands critics, said a tailings pond scientist, and while he concedes there have been problems associated with them, he believes their future is “very, very bright” as technology development and implementation will solve their challenges. “There has been some tremendous progress in the past few years,” Randy Mikula, principal scientist at Kalium Research Inc., told the Canadian Energy Research Institute’s oil conference in Calgary. But the real question remains how soon will the oilsands mining area be returned to boreal forest, he said. There has been a great deal of reclamation, but that has been limited to either overburden dumps or sand areas, and only now is there some progress being made on fluid fine tailings, which are the reason for tailings ponds, he told the conference. The kind of engineering effort that went into building tailings ponds in the first place is exactly the same type of engineering and resources on hand that will clean them up, he said. Some people believe the problem with tailings ponds is that the fluid fine tailings don’t settle to the bottom, but that’s not accurate; they settle quite quickly, he said, and the settled volume can be controlled through water chemistry, additives or the way in which ore is processed. The problem is that they don’t consolidate, said Mikula. For every barrel of bitumen produced, another 1.5 barrels of fluid fine tailings are created. “Our ability to turn that into something that’s 45 per cent solids, or even 50 per cent solids, really depends on our understanding
Northeastern Alberta
of those clays at the nanoscale,” he said. But even at 55 per cent solids, the material is not strong enough to support mining trucks or reclamation equipment. According to Mikula, the most promising technologies are: mature fi ne tails (MFT) and overburden mixing, rim ditching, water capping, composite/non-segregated tailings process (CT); Suncor Energy Ltd.’s tailings reduction operations (TRO); Shell Canada Limited’s atmospheric fi nes drying (both subsets of thinlift drying) and centrifugation. Technologies to watch are the CT, thin lift and centrifugation, which are now full-scale operations, while others are under development, the conference heard. He said there have been many questions around whether water capping—the creation of an artificial lake—will work. Water capping has been tested on relatively small scales very successfully, but the question is whether it can succeed on a 200-million-cubic-metre scale, which is currently underway, said Mikula. “Unfortunately, in my opinion...we put MFT in the bottom of this test end-pit lake. Had we been able to put [in] centrifuge tailings...we would have been able to get twice as many tonnes of fines into that deposit,” said Mikula, who has been involved with centrifugation since 1998. He said that in October of this year, Syncrude Canada Ltd. will start up a $2-billion, full-scale commercial centrifuge plant to help dewater its tailings ponds. That’s ahead of the 2015 original target, he said. Syncrude would not confirm this. Mikula said Syncrude will treat 26 million cubic metres of fluid fine tails per year. The company has seven tailings ponds. Syncrude has been running a large pilot centrifuge project since 2008 and an eight-centrifuge commercial test plant since 2012. It had a commercial demonstration of the technology in 2011, he told the conference. Centrifugation involves putting tailings through vessels where a spinning action separates out the water. Released water will be recycled for plant operations, while the soil will be placed in deposits, then capped and reclaimed. Extensive field tests have been done on this technology with the support of CanmetENERGY at Devon, Alta. “In terms of the water recycle, the centrifuge process has a lot of advantages,” said Mikula. “Centrifuge provides the opportunity to deal with all of the accumulated fluid fi ne tails, so in fact, with full-scale commercial implementation of the centrifuge process, we’ll no longer be accumulating fluid fine tails.” He believes there is a lack of appreciation by the general public and even among newcomers to the oilsands industry about the high level of technical and scientific sophistication associated with tailings and water management. According to Mikula, the use of isotopic ratio differences to determine the source of tailings water emulsions and applications of state-of-the-art correlated electron and optical microscopy to understand the clays in tailings suspension illustrate the broad base of fundamental science underpinning the technological advancements that are being rolled out to manage tailings and water in today’s surface-mined oilsands extraction operations.
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When it comes to improving their carbon profile while cutting freshwater usage, Alberta’s in situ oilsands producers may find themselves between a rock and a hard place, an industry audience heard in April. Environmental critics often call on the industry to cut its greenhouse gas (GHG) emissions while at the same time arguing that the industry’s freshwater usage is excessive. However, achieving both goals might be a tough nut to crack, a panel discussion at the Canadian Energy Research Institute oil conference heard. Scientists who know the field readily acknowledge that water conservation is a major issue for thermal oilsands operators, especially in steam assisted gravity drainage. Among studies that have looked at the issue was one by Alberta Innovates – Energy and Environment Solut ions (A I E ES), a bra nc h of t he Alberta government. During the panel discussion, an Alberta government scientist who led the study recalled some of the lessons learned. “We looked at technologies that could allow you to recycle water, and found there was a trade-off between that and reducing GHG emissions,” said Duke du Plessis, senior adviser, energy technologies, for AIEES. The study, which involved nine Alberta in situ producers, examined the interplay between water recycling and GHG or life-cycle emissions, du Plessis said. W hile striving to recycle as much f resh water as possible, researchers found there’s a point where cutting water usage on in situ operations below a certain level actually increases carbon emissions, he said. Within the industry, experts typically refer to GHG emissions per unit of production as carbon intensity, arguing that efforts to improve environmental performance have borne fruit in the form of reduced emissions intensity. Environmentalists, though, typically dismiss those arguments,
Northeastern Alberta
calling for absolute, not relative, cuts in carbon emissions. Among the incentives for the industry to cut GHG emissions is Alberta’s $15-pertonne tax, although du Plessis said a charge of that level is “not going to change behaviour right now.” As for seeking solutions to the problems of water conservation and carbon emissions in the future, the industry needs to consider “radically new,” non-aqueous extraction technologies, he said. “We have to start looking at technologies that are harder to do but have a greater impact,” du Plessis told his audience. Following the panel discussion, du Plessis expanded on the dilemma faced by in situ producers. He said an in situ plant’s GHG emission intensity rises as more water is recycled because the plant has to evaporate more water to get rid of the solids, in order to recycle the water. “The more you evaporate, the more energy you use and, therefore, your greenhouse gas emissions go up. “If you’re going to recycle more, you’re going to have more emissions intensity. You can’t get away from that. But maybe you’re willing to pay the penalty because the benefit from recycling more and using less fresh water offsets the higher GHG emissions. That might be different for every company.” Producers that can cut their emissions intensity will produce fewer greenhouse gases for the same volume of oil produced. However, du Plessis said, “if you’re producing more oil overall, you’re invariably going to produce more greenhouse gases, even though you may bring your intensity down.” It ’s at that point that the industr y and its critics part company, because environmentalists’ demand for f lat or lower GHG emissions by the oilsands sector is unlikely to be met unless production is capped. “The end result of that argument is that you can reduce all emissions if you stop producing anything,” said du Plessis, adding that shutting down production would also shut down economic growth. Instead, the industry should be looking for ways to strike “a balance between the economy and the environmental impact,” he said.
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OIL & GAS INQUIRER • JUNE 2014
37
CENTRAL ALBERTA WELL ACTIVITY APR/13
APR/14
Wells licensed
APR/13
APR/14
Wells spudded
APR/13
APR/14
Rigs released
C.A.B.
▲
▲
Central Alberta
▲
Source: Daily Oil Bulletin
Tourmaline boosts 2014 capital budget Tourmaline Oil Corp. has boosted its planned capital expenditure budget to $1.1 billion from the previous estimate of $1 billion. The company is increasing financial estimates for 2014 due to stronger natural gas prices and providing 2015 preliminary guidance due to the combined effects of additional production arising from the Santonia Energy Inc. acquisition—which the company said has now closed—and anticipated higher natural gas prices. Estimated 2014 cash flow has been increased seven per cent to $1.09 billion, using an AECO natural gas price of $4.64 per thousand cubic feet and a West Texas Intermediate (WTI) oil price of US$97.40 per barrel. This represents 106 per cent growth over 2013 cash flow of $526.8 million. Cash flow in 2015 is estimated at $1.48 billion, based on estimated daily average production of 159,500 barrels equivalent per day, an AECO natural gas price of $4.43 per
thousand cubic feet and a WTI oil price of US$93.38 per barrel. Capital spending for 2014 is now estimated at $1.1 billion, with incremental spending anticipated to be incurred with the addition of one more rig in northeastern British Columbia, the Berland to Wild River pipeline lateral, and the acceleration of the Wild River plant expansion. Tourmaline reached the 117,000-barrelequivalent-per-day production level during the third week of April. The company has an additional 16,000 barrels equivalent per day of already tiedin production awaiting facility access or expansions. This 16,000 barrels of additional production capacity is primarily at Spirit River, Alta., Sunrise-Dawson, B.C., and Horse-Smoky, Alta., and is anticipated to come on stream during the second half of 2014 with the completion of ongoing facility projects in all three areas.
Tourmaline Oil Corp. first-quarter highlights • Record cash flow of $252.6 million, a 117 per cent increase over 2013. • First-quarter 2014 earnings of $89.9 million, a 72 per cent increase over the first quarter of 2013. • Record first-quarter 2014 average production of 102,563 barrels equivalent per day, a 49 per cent increase over average production for the first quarter of 2013 and a 19 per cent increase over the fourth quarter of 2013. • Record oil and liquids production at 8,690 barrels per day and 6,207 barrels per day of NGLs or 15 per cent of total production. • 20 of 21 first-quarter 2014 Deep Basin horizontals with 30 days of production history have a 30-day IP rate of 10.2 million cubic feet per day, compared to the current company template forecast of five million cubic feet per day. • Tourmaline drilled 34 gas wells, six oil wells and no dry holes in Q1/2014.
With current daily natural gas production of approximately 585 million to 600 million cubic feet per day, Tourmaline is now one of the top five largest natural gas producers in Canada. Tourmaline remains on track to achieve average production for 2014 of 120,000 barrels equivalent per day, representing 60 per cent growth over the average 2013 production of 74,796 barrels per day. The company’s facility projects at Spirit River, Alta., Doe, B.C., and Musreau, Alta., remain on schedule for a late third-quarter or early fourth-quarter 2014 start-up and are anticipated to increase corporate daily production by approximately 25,000 barrels per day in aggregate. The company also expects to complete a large pipeline lateral connecting the Smoky-Berland complex to the Wild River plant during the third quarter, which will allow currently shut-in volumes at Smoky to flow to the Tourmaline facility at Wild River. Tourmaline is currently operating two drilling rigs in northeastern British Columbia, with the remaining 15 rigs shut down for breakup. The company is planning to operate 18 drilling rigs during the second half of 2014, with 12 rigs in the Alberta Deep Basin, three rigs pursuing Montney gas condensate in northeastern British Columbia, and three rigs pursuing the Triassic Charlie Lake oil play on the Peace River High. First-quarter 2014 drilling results in the Alberta Deep Basin were the best in the company’s history. The company drilled and completed 30 horizontal wells targeting the Wilrich, Notikewin and Falher formations in the Deep Basin, tying in 28 of these wells during the first quarter. Of the 17 wells that have been on production for greater than one month, 16 of them have 30-day initial production (IP) rates in excess of the company’s production/ economic template of five million cubic feet per day. The actual 30-day IP average OIL & GAS INQUIRER • JUNE 2014
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of these 17 wells is 10.4 million cubic feet per day. As longer-term production performance data becomes available on the remaining wells, the company will consider updating its internal economic template to reflect revised average production rates. The future horizontal drilling inventory has been increased substantially thus far in 2014 both through the additions at Crown land sales and the Santonia acquisition. One of the Deep Basin rigs will focus on a series of high potential locations already identified on the Santonia land base during the second half of 2014. Production in northeastern British Columbia reached a record 35,000 barrels equivalent per day in mid-April, with an additional 6,000 barrels per day shut-in awaiting the planned third-quarter facility expansions at Doe and Sundown. The company has drilled two successful follow-up wells to its previously announced fourth-quarter 2013 Lower Montney gascondensate discovery and will disclose further information once these wells are brought on stream. The company is adding an additional rig in northeastern British Columbia to pursue this new and expanding opportunity. Tourmaline has also drilled an extended reach horizontal in the Doig Formation at Sundown, and will complete this well after breakup. Production from the overall Peace River High complex was expected to reach the 13,000-barrel-equivalent-per-day level in April with the start-up of the initial battery at Mulligan. Drilling operations are expected to restart in June with an additional 30 horizontal wells planned to be drilled, completed and on stream by year-end. The company’s new sour gas injection gas plant at Sprit River remains on schedule for an early October 2014 start-up, allowing Tourmaline to bring on stream approximately 5,000 barrels equivalent per day of production that is currently shut-in. Completion operations on the company’s two potential Paleozoic gas discoveries will begin as soon as access is possible after breakup. There are a total of seven prospective new pay zones in the Paleozoic to complete between the two cased exploration wells. — DAILY OIL BULLETIN
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Ferus NGF acquires Encana’s share in Alberta LNG plant Ferus Natural Gas Fuels, Inc. (Ferus NGF), a North American leader in liquefied natural gas (LNG) and compressed natural gas (CNG) fuelling solutions, says it has completed the purchase of Encana Corporation’s 50 per cent interest in the LNG production facility at Elmworth, Alta. The company will retain key Encana technical and management personnel. The first phase of the 190,000-litre-per-day facility, which was constructed as a 50/50 joint-venture partnership between Ferus NGF and Encana, will be operational in May 2014. It is in close proximity to the Alberta–British Columbia Deep Basin oil and gas region and will produce LNG fuel for use in drilling rigs, pressure pumping services and heavy-duty trucks.
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“Our experience with LNG has demonstrated significant cost savings and environmental benefits,” David Hill, Encana’s executive vice-president, exploration and business development, said in a news release. “Encana remains a key customer of Ferus and has committed to a multi-year LNG supply agreement to service our field operations.” The sale of its interest in the plant allows Encana to focus on its core business and the execution of its new strategy, he added. “We are pleased to continue working closely with Encana as we jointly lead the adoption of LNG fuel by the western Canadian oil and gas industry,” said Richard Brown, president and chief executive officer of Ferus NGF, formerly Ferus LNG. “In addition to Encana’s commitment to using LNG fuel, we are adding experienced Encana personnel to our team to ensure a seamless transition and exceptional service to our customers in the region.” As a result of the transaction, Ferus NGF is the 100 per cent owner and operator of the newest and largest merchant LNG plant in Canada and has significant plans to expand beyond that. Ferus NGF is focused on supplying domestically produced LNG and CNG fuel, which provides cost savings and environmental advantages to the oil and gas, trucking, mining, rail, marine and remote power generation markets.
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Talisman wants partner to develop Duvernay lands By Richard Macedo
A joint-venture partner would help Talisman Energy Inc. appraise and develop a larger percentage of its Duvernay shale gas acreage, according to Hal Kvisle, president and chief executive officer. The company currently holds interests in approximately 352,000 net acres of land in the liquids-rich Duvernay play located in central Alberta. During 2013, Talisman drilled three wells in the Duvernay play. To date, 10 wells have been drilled, including two wells drilled in the fi rst quarter of 2014, primarily to retain acreage. The company plans to pursue third-party funding, possibly through a joint venture, to develop the play going forward. “We hold this enormous land position and we literally have locations to drill several thousand horizontal wells; you can
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calculate how many billion dollars of capital that would work out to at roughly $10 million or more per well,” Kvisle told the company’s annual general meeting after it reported net income of US$491 million for the fi rst quarter of 2014, a reversal from a US$213 million loss during the same period of 2013. Kvisle later told reporters that the magnitude of the Duvernay play is “not as understood as it should be.” “This is one of the most enormous things to have hit us,” he said. “It’s comparable to the Montney. I don’t know whether it’ll be as big, or bigger, or almost as big as the Montney. It’s very liquidsrich and we—and all of our industry competitors—have to contend with deep horizons. “The whole idea of the Duvernay is not that it’s a stinker of an asset that we’re trying to get out of; it’s rather we can either afford to fully appraise and develop 30 per cent of the land ourselves or, with a partner, we can appraise and develop 60 per cent,” Kvisle added. “As in any play, there’s probably a third of the land that would fall outside of the fairway that you want.” In March 2013, Talisman set a 12- to 18-month target to realize $2 billion to $3 billion of value through the sale of non-core assets that were generating little or no short-term cash flow. The company achieved this target within 12 months and asset sales agreed to in 2013 and in the first quarter of 2014 will total over $2.2 billion. Talisman said in its 2014 guidance released in February that it planned to dispose of approximately $2 billion of additional assets (primarily long-dated, capital intensive) over 12–18 months. The majority of the proceeds will be directed toward maintaining a strong and flexible balance sheet.
RMP achieves record production
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An expansion of its Ante Creek battery, commissioned on March 1, enabled RMP Energy Inc. to report record production in the fi rst quarter of 2014 and increase its production guidance for the year. With the facility expansion, RMP began delivering light oil and associated natural gas into the downstream sales receipt point through its Ante Creek–to-Waskahigan pipeline, achieving average daily production of 9,229 barrels of oil equivalent per day, weighted 60 per cent light oil and natural gas liquids. This represents a 27 per cent increase over the fourth-quarter 2013 production of 7,266 barrels per day. As a result of a stronger fi rst-quarter production level, RMP is increasing its fi scal 2014 average daily production forecast to approximately 10,500 barrels equivalent per day, with production exceeding 12,000 barrels per day in the second half of the year. In April, RMP’s corporate average daily production has exceeded 12,000 barrels per day with only six of 12 Ante Creek wells on production for the majority of the month. As a result of downstreamsales pipeline capacity constraints, the company continues to truck a significant portion of its crude oil from its Ante Creek battery in addition to the deliveries though its pipeline. Notwithstanding favourable surface field conditions in April, the company is tempering a larger increase in its forecasted annual average production volumes pending the end of spring breakup through June. — DAILY OIL BULLETIN
42
JUNE 2014 • OIL & GAS INQUIRER
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SOUTHERN ALBERTA WELL ACTIVITY APR/13
APR/14
Wells licensed
APR/13
APR/14
Wells spudded
APR/13
APR/14
Rigs released
▼
▲
▲
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
Marquee drills three successful Michichi wells During the first quarter of 2014, Marquee Energy Ltd. drilled three 100 per cent working interest wells focused on the Banff zone within its Michichi core area. After 20 days on production, the three wells are producing more than 200 barrels equivalent per day (75 per cent oil and liquids) per well on average based on field estimates, comparing favourably to Marquee’s type curve for Michichi that is based on a 30-day initial production rate of 165 barrels per day (70 per cent oil and liquids).
The three wells are offset and in close proximity to Marquee’s 03-03-03217W4 discovery well, which had a 90-day initial production rate of more than 200 barrels equivalent per day (80 per cent oil and liquids) compared to the type curve 90-day initial production rate of 154 barrels per day (70 per cent oil and liquids). The four wells were drilled with the use of 3-D seismic and are all producing in excess of the expected type curve.
According to management, the results from these wells further validate Marquee’s geologic and seismic models as the company continues to high grade its drilling opportunities. Marquee has a significant undeveloped land base in Michichi with a multi-year inventory of analogous drilling opportunities. The company plans to drill at least nine more wells at Michichi in 2014, starting in June or earlier if surface conditions permit. — DAILY OIL BULLETIN
Encana spin-off to be called PrairieSky In April, Encana Corporation said that its spin-off royalty interest entity will be called PrairieSky Royalty Ltd., and that PrairieSky has fi led and obtained a receipt for a preliminary prospectus in respect of its initial public offering of common shares with the securities regulatory authorities of all provinces and territories in Canada. The offering is being conducted by way of a secondary offering by Encana, which will receive the net proceeds of the offering. Consistent with its strategy announced in November 2013, Encana said it is establishing PrairieSky to provide investors with the opportunity to invest directly in a royalty business, which includes approximately 5.2 million acres of fee simple mineral title lands in central and southern Alberta, with petroleum and/or natural gas rights. T he creation of PrairieSk y, f rom Encana’s fee simple mineral title lands and associated royalty interests that formed part of its Clearwater business unit, gives Encana “the opportunity to unlock value
from its royalty business,” the company said in a press release. According to Encana, PrairieSky does not intend to directly conduct operations
5.2
million acres
Amount of fee simple mineral title lands Encana Corporation is spinning off
to explore for, develop or produce petroleum or natural gas. Instead, the company will focus on attracting third-party capital investment to develop PrairieSky’s
properties, which is expected to provide PrairieSky with royalty revenues as petroleum and natural gas are produced from those properties. Upon closing the offering, Encana said it expects to hold a majority interest in PrairieSky. Although Encana will provide certain day-to-day administrative services on a transition basis until Dec. 31, 2014, the company intends to act only as an investor in, and not as a manager of, PrairieSky. The board of directors of PrairieSky has been appointed and will be led by James Estey as chair and includes Sherri Brillon, Brian Shaw, Sheldon Steeves, Bruce Waterman and Andrew Phillips. The executive management team of PrairieSky is led by Phillips as president and chief executive officer and includes Geoffrey Barlow as vice-president, finance, and chief financial officer, and Cameron Proctor as vice-president, legal and corporate services, and corporate secretary. — DAILY OIL BULLETIN OIL & GAS INQUIRER • JUNE 2014
45
Southern Alberta
DeeThree continues Alberta Bakken, Belly River success DeeThree Exploration Ltd. continues building out its two resource plays in central and southern Alberta. DeeThree has now received extended production data on the first round of down-spaced wells drilled on its Brazeau Belly River property, each off setting significant oil-producing wells that were drilled in 2013. These new wells had an average 30-day initial production rate of 818 barrels equivalent per day (ranging from 535 to 1,102 barrels per day) and in combination with positive pressure data, continued to further prove the size and potential of the resource. Wit h t hese new data poi nt s, t he company is strongly encouraged by the development possibilities and subsequent risk profile of its development plan in all of the sands in the area on a go-forward basis. With previous years’ drilling efforts in the region concentrated on proving up
the multi-zone potential and areal extent of the reservoir, the company will primarily focus on the development of its Brazeau Belly River property in 2014 with one rig drilling “C sand” development wells, one rig drilling “D sand” development wells and the third rig proving up future drilling opportunities. Two wells drilled on the property earlier this quarter will be completed post–spring breakup, providing new production additions as soon as weather permits. One of these wells is unique in that it is the fi rst horizontal well to be drilled in the “BBR A sand.” The company currently has two rigs drilling wells on its Lethbridge Bakken property, with two wells drilled and completed this quarter and two additional wells in the latter stages of drilling the horizontal production legs. Operations on this property have not been delayed due to spring breakup conditions in the area.
DeeThree has recently significantly expanded its land position in this core area by acquiring rights to more than 70 additional sections that are believed to include both lower-risk development and exploration opportunities. Acquisition highlights include an agreement with a senior producer pursuant to which DeeThree may earn a 100 per cent working interest in up to 34.5 contiguous sections (22,080 acres) of land located directly on trend and between existing company production within its Lethbridge Alberta Bakken property. In consideration, DeeThree has committed to drill one vertical well and one horizontal well by the third quarter of 2014. The company has the right to acquire any lands that are not earned by the third quarter of 2014 in exchange for a cash payment and a further drilling commitment. — DAILY OIL BULLETIN
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SASKATCHEWAN WELL ACTIVITY APR/13
APR/14
Wells licensed
APR/13
APR/14
Wells spudded
APR/13
APR/14
Rigs released
▲
▲
Saskatchewan
▲
Source: Daily Oil Bulletin
Crescent Point says Torquay discovery huge Crescent Point Energy Corp. says it has made a “significant” Torquay discovery in its core Flat Lake area of southeastern Saskatchewan, which is an extension of its Three Forks resource play in North Dakota. Over the past 12 months, Crescent Point has delineated the Torquay discovery in the Flat Lake area, where the company has more than 220 net sections of core-area Torquay land and 400 low-risk Torquay drilling locations on the Canadian side of the border. To date, the company has drilled 36 (35.2 net) horizontal wells targeting the Torquay formation at Flat Lake, growing net production from zero to approximately 5,100 barrels equivalent per day in just 12 months. “We’re very excited about the results we’ve seen in the Torquay so far,” president and chief executive officer Scott Saxberg said. “These are high rate-of-return wells at low capital costs relative to North Dakota that complement the Bakken production from our core Flat Lake area. To put it in context, this play has the potential to be the equivalent size of our Viewfield Bakken play.” In 2013, the company added provedplus-probable reserves of 11.2 million barrels at Flat Lake in the Torquay and Bakken formations combined. Finding and development costs were $11.46 per barrel of oil equivalent, excluding changes in future development capital, which represents a recycle ratio of 6.4 times per proved-plusprobable barrel for this area. “The recycle ratio for Flat Lake is more than double the 2.8 recycle ratio we achieved corporately in 2013 and more than triple a recycle ratio of two times,
which is considered very good in our industry,” Saxberg said. At year-end 2013, the company’s independent reserve engineers booked estimated ultimate recoveries on producing Torquay wells as high as 275,000 barrels per mile-long well. Crescent Point’s internal 275,000-barrels-per-mile-long type well, which has a $3.35-million capital cost, generates rates of return of approximately 300 per cent and payouts of approximately seven months. In 2014, Crescent Point expects to spend approximately $200 million of its 2014 budget in Flat Lake, including drilling approximately 48 net wells. The company’s total capital expenditures budget for 2014 remains unchanged at $1.75 billion. In addition to its core Flat Lake Torquay land position, over the past 18 months Crescent Point has continued to accumulate a significant exploratory land position of more than 400 net sections in the southern part of southeastern Saskatchewan, targeting the Torquay and Bakken formations. These lands are in addition to the delineated core-area lands discussed above. The company has drilled six wells testing the Torquay zone on these exploratory lands to date and has plans to drill five more wells over the coming six months. In related news, Crescent Point continues to bulk up as it is set to acquire privately held CanEra Energy Corp. and its southeastern Saskatchewan assets for total consideration of $1.1 billion. In mid-April, Crescent Point said it will acquire all of the issued and outstanding shares of CanEra, which has a large Torquay land position and production of approximately 10,000 barrels per day.
The CanEra assets include more than 260 net sections of land with Torquay potential, of which more than 200 net sections are exploratory land and 60 net sections are in Crescent Point’s core Flat Lake area. In total, Crescent Point now has exposure to more than 880 net sections of land with Torquay potential, of which more than 280 net sections are in the core Flat Lake area. T he Ca n E ra a sset s a lso i nc lude high- qua lit y, long-life sout heaster n Saskatchewan conventional production of approximately 10,000 barrels per day. The successful completion of the CanEra arrangement is also expected to Crescent Point Torquay snapshot* • Extension of the North Dakota Three Forks play • >880 net sections of Torquay potential land • >280 net sections in delineated core area • 5,200 barrels equivalent per day of production • 36 net wells drilled to date • 480 net low-risk, high rate-ofreturn locations • $3.35 million all-in well cost on a one-mile horizontal • >$73.00/boe operating • 45 Torquay wells planned for 2014 *Pro forma of CanEra takeover
drive a seven per cent reduction in Crescent Point’s total payout ratio in 2015, due to the strong cash flow–generating capability of the acquired assets and low associated maintenance capital requirements. “There are two major aspects of this deal that fit really well with our business plan for stable, long-term growth,” said Saxberg. “The assets consolidate and complement our conventional assets and will generate significant free cash flow, and the 260 net sections of Torquay land we gain provide further exposure and upside potential in a play that we’re very excited about.” OIL & GAS INQUIRER • JUNE 2014
49
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JUNE 2014 • OIL & GAS INQUIRER
Strategic rationale The successful completion of the CanEra arrangement is expected to increase Crescent Point’s Torquay exposure in its core Flat Lake area by 27 per cent to more than 280 net sections. Combined with the CanEra assets, Crescent Point has identified more than 480 low-risk Torquay drilling locations. “This acquisition adds to our low-risk drilling inventory in the Flat Lake area and provides increased exposure on the greater exploration trend,” said Saxberg. “We have a successful track record of finding and developing new resource plays that have enhanced our growth, and we are excited about the potential we see in the Torquay.” “The low decline rate of CanEra’s assets should work in tandem with our successful waterflooding programs in the Bakken and Shaunavon to continue lowering our corporate decline rate and to enhance the dual-track growth plan we’ve implemented,” said Saxberg. The CanEra arrangement further consolidates Crescent Point’s Viewfield Bakken light oil resource play and is expected to facilitate the company’s waterflood plans in the area. CanEra is the largest remaining working-interest partner in the Viewfield Bakken waterflood project. — DAILY OIL BULLETIN
Gear acquiring heavy oil assets for $85 million Gear Energy Ltd. has entered into an agreement to acquire heavy oil assets focused near the company’s core producing areas of Wildmere, Alta., and Maidstone, Sask., for $85 million in cash. The assets include over 2,000 barrels per day of high working interest, operated heavy gravity crude oil production (98 per cent oil). The effective date of the acquisition is March 1, 2014, and the closing of the acquisition is expected to occur on or about May 1, 2014. Gear said the assets fit the company’s strategy of targeting under-exploited,
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This will increase Gear’s drilling inventory to approximately 400 locations. The company has also identified approximately 60 net recompletion opportunities on existing vertical wells. Based on current 2014 drilling pace, Gear’s drilling inventory will now be greater than five years. The company intends to fund the acquisition with existing lines of credit and existing cash flow. After the acquisition closes, Gear is estimating that it will have a relatively low net debt to cash flow ratio of less than one times projected 12-month cash flow. In conjunction with the acquisition, Gear has approved an increase in the 2014 development capital budget to $85 million from $70 million. The incremental development capital will be directed primarily toward the acquired assets. The company expects to drill an incremental seven horizontal wells and seven vertical wells on the acquired assets, along with 20 recompletions and multiple infrastructure projects that will result in lower operating costs.
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JUNE 2014 • OIL & GAS INQUIRER
The latest land sale is pushing the boundaries of the Bakken westward.
Saskatchewan land sale produces $47.94 million By Richard Macedo
A swath of exploration licences in the area around 004-27W2 and 004-30W2 that combined for $26.81 million helped to power Saskatchewan’s April sale, which produced $47.94 million in revenue. After just two sales so far in 2014, the province has already eclipsed the $67.37 million collected for all of 2013. The industry acquired 72,819 hectares this week at an average of $658.30 per hectare. Year-to-date, the province has attracted $98.62 million in bonus bids on 100,727 hectares at an average price of $979.13. Of particular interest in this sale was a cluster of exploration licences between Assiniboia and Rockglen. Drilling in the early 1950s proved the presence of Bakken oil in the area, but the technology did not exist to develop the resource, the government noted. “With interest in this area rekindled after 50 years, we are hopeful that the technological advances made in the interim
Photo: Joey Podlubny
FAST
FIND IT
Saskatchewan
can be applied to produce significant amounts of oil,” Energy and Resources Minister Tim McMillan said. “Industry has again voted with their pocketbooks that Saskatchewan is a great place to invest and drill for oil. We look forward to seeing these new dispositions begin development and provide new jobs and prosperity for the province.” While the western edge of the Viewfield Bakken Sand Pool is 160 kilometres east of the exploration licences that sold south of Assiniboia, there is a smattering of successful Bakken wells between Viewfield and the Roncott area, just a few miles east of the exploration licences that sold in this week’s sale, noted Paul Mahnic, director of the Petroleum Tenure Branch in Saskatchewan. “Regarding the zone of interest for these exploration licences, it is reasonable to expect that the Bakken is the main zone of interest, but there is the potential for shallower Mississippian plays in the area as well as the deeper Red River, and multiple targets always help when determining the economics of drilling a well,” he said. In addition to the oil shows in Bakken core and oil cut mud recovered from the Bakken in two wells drilled and tested in the 1950s, the area has seen limited exploration activity over the past five years, with a few leases and exploration licences being sold and a couple of exploration wells drilled that tested the Bakken without success. “Just west of these exploration licences is an active special exploratory permit that was acquired in the August 2012 land sale for a work commitment bid, and the ministry has been actively promoting this area at industry trade shows and conferences, so it’s not really a surprise that these lands were requested for this sale,” Mahnic said. The exploration licences are issued for two-year terms and have a drill-to-earn-leases requirement, so the province should know shortly whether the Bakken is commercial with today’s technology. The top purchaser of acreage in the province at its April sale was Prairie Land & Investment Services Ltd., which spent $20.36 million to acquire two lease parcels and six exploration licences. The top price paid for a single licence was $5.54 million and it was acquired by Prairie Land for two identical 5,179.98-hectare blocks located 35 kilometres west of the Roncott Bakken Sand Pool, 30 kilometres south of Assiniboia. Each parcel, part of the swath of licences between Assiniboia and Rockglen, produced average prices of $1,069.72 per hectare. One of the parcels started at section 19 of 004-28W2, while the other started at section 20 of 004-28W2. The highest lease bonus of $2.63 million, paid by Stomp Energy Ltd., was for a 518-hectare parcel situated 10 kilometres southwest of the Tableland Winnipegosis Pool, 17 kilometres southwest of Estevan. The lease, which generated an average price of $5,080.74, included sections 13 and 14 at 001-11W2. The highest dollar per hectare in this sale was generated by Silver Hawk Resources Ltd., which paid an average of $9,312.56 for a 16.19-hectare lease parcel located adjacent to the Lashburn West Sparky Sand Oil Pool, 28 kilometres south of Lloydminster. The broker paid a bonus of $150,770 for legal subdivision 07 of section 14 at 047-26W3. There were no gas prone parcels featured in this sale. Parcels offering only deeper rights brought in $2.9 million (6.05 per cent of the sale) for an average price of $1,395.87.
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Sweetening the deal on sour gas control By Brian Marr, Scott Carline and Scott Deyoung, Weatherford
Sour gas is nothing new to western Canada’s oil and gas producers, but keeping it at bay in reliable and cost-effective ways remains an ongoing challenge. Any gas that contains hydrogen sulphide (H2S) in quantities of 5.7 parts per million or greater is typically considered sour, and roughly 30 per cent of the natural gas in western Canada falls under this category. Sour gas can be highly corrosive to the steel, comprising the downhole production tubing and surface equipment. If this gas should escape from the production system through a corrosion-induced leak, it can be extremely harmful—even lethal— if breathed in small concentrations. Producers commonly rely on injecting corrosion inhibitors and other chemical treatments downhole to protect the production infrastructure and neutralize the H 2S in the gas stream. An operator of a sour gas well in the Leduc Formation in central Alberta employed chemical injection to the bottom of the well to keep corrosion rates down and avoid the need to take the well offline to repair severely corroded downhole tubing. With an H 2S content of approximately 34 per cent, this well was one of the most sour in the operator’s production portfolio. It was also critical to the operation of adjacent wells, as it was the most prolific producer in the field. If this well had to be shut in for an extended period, there would not be sufficient production going into the field’s H 2 S treatment plant to maintain efficient operation, which would lead the operator to effectively shut in the entire field. This possibility became a critical concern when the capillary line used to continuously inject corrosion inhibitor into
the well became plugged, leaving the downhole tubing unprotected from severe corrosive attack and raising the likelihood of elemental sulphur forming and blocking off the tubing. The operator quickly moved to the short-term fix of batch treating the well with corrosion inhibitor, an expensive and time-consuming process that required scheduling pumps, tank trucks and work crews to go to the wellsite to perform a batch treatment every two weeks. This option not only presented logistics challenges due to adverse weather conditions that interrupted regular access to the well, but it also required detailed safety protocols while treating this highly sour well. Batch treatments also call for shutting production down on the well, which raises the risk of formation damage or reduced production rates once the well is brought back online.
Restoring continuous injection Weatherford collaborated with the operator to devise a solution that would re-establish continuous chemical injection, but without the cost and complexities associated with a workover operation. Depending on the location, the cost of a workover can exceed US$10 million. The solution used Weatherford’s Renaissance safety-valve technology, which is designed to revive safe operations in wellbores through a simpler and less t i me - con su m i ng wel l i nter vent ion. The system is designed for installation by standard wireline and capillary via a small-footprint, skid-mounted unit that can run 1/4- or 3/8-inch capillary. The installation is achieved without having to pull the tubing. In addition, the system’s design allows for small
plat for m c ra ne s to ma ke requ i red lifts, without the need for additional crane capacity. Arriving at the right design and selecting suitable materials of construction for the chemical injection system began with a careful review of the well conditions—run history, flow conditions, exact composition of well f luids and so on. Weatherford’s materials and elastomers experts worked with their counterparts on the operator side to arrive at the optimal set of metallurgies and elastomers for the entire valve assembly that would withstand the harsh corrosive environment downhole. This was followed by careful review of the safety, running and pulling procedures with both the operator and other vendors, who would provide on-site slickline and capillary services. Once all parties were in full agreement, the installation process began by running a chemical injection valve to 15,275 feet (4,656 metres) via a 3/8inch injection line, while attached to a seven-inch wireline-retrievable subsurface safety valve (SSV). This safety valve was run to provide positive shut-off protection in case of a catastrophic loss of well control. The safety valve was put into the profile of the existing tubing-retrievable SSV, which enabled the continued use of the existing control line to function the flapper of the new safety valve. The new chemical injection line was then continued from the safety valve to surface using a wet-mate connector attached to a control-line hanger, which was seated in the existing tubing hanger. All equipment was installed using only a slickline unit and a capillary line unit. OIL & GAS INQUIRER • JUNE 2014
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Te c h N e w s
With the new valve and capillary line installed and all connections fully secured, normal continuous chemical injection was restarted. The entire installation process took two days, a significant improvement over even a simple workover, which might require two to three weeks of downtime. The well has been back up and running without incident since September 2013, with a new chemical injection line affording reliable and continuous chemical delivery and corrosion control. The full functionality of a safety valve has been maintained and controlled using the existing control line and full production has been restored, allowing the sulphur treatment plant to maintain optimal operations. Weatherford has conducted similar installations in the North Sea, the Middle East and Asia Pacific, and to date more than one million feet of capillary string has been run via the Renaissance method. However, this Canadian chemical injection restoration represented one of the deepest capillary runs to date, and the first conducted in the Western Hemisphere. This successful installation in a highly sour
gas well has proven the concept to the operator, who now plans to run further jobs both in Canada and other regions where chemical injection challenges are common.
Ceramic coating new corrosion fighter Corrosion accounts for over 25 per cent of failures, according to a recent NACE International report. NACE also estimates pipe repair or replacement costs at more than $7 billion per year. This figure can double based on lost revenue and spill/leak clean-up costs. “Corrosion is a major challenge in our industry for external floating roof tanks, tank interiors, to above- and below-grade piping systems,” said Scott Justice, tank inspection division manager of Bolin Enterprises Inc. While traditional corrosion protection involves short-lived, physically bonded coverings of substrate surfaces such as tapes,
three-part coating systems (zinc, epoxy and urethane) and cathodic protection, these merely lengthen the time before steel inevitably rusts. The alternative is a new category of chemically bonded phosphate ceramics from EonCoat LLC that can stop corrosion with minimal downtime for application. Shane Bartko, director of sales at Tko Specialty Surfaces Inc., a Calgary-based tank, pipeline, and structure maintenance contractor, has used the ceramic coating as well. “With a typical corrosion coating, you have to blast to white metal to prepare the surface,” said Bartko. “With the ceramic coating, you typically only have to do a NACE 3 commercial brush blast.” Bartko explained that many polyurethanes or epoxies require days’ worth of cure time for each coat applied. With the ceramic coating, return to service can be in as little as one hour. “That kind of speed in getting an oil and gas facility producing again can potentially save millions per day in reduced downtime,” said Bartko.
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In February 2014, the company announced the results of five well tests conducted on five Lokhone pay intervals in Etuko-1. Light 36 degree API waxy crude oil was successfully flowed from three zones at a combined average rate of over 550 barrels of oil equivalent per day. In September 2013, the company announced a new oil discovery at Ekales-1 located in the Basin Bounding Fault Play between the Ngamia-1 and Twiga South-1 discoveries. Logs indicated a potential pay zone of 60 –100 metres to be confirmed by flow testing. In November 2013, the company announced a new oil discovery at Agete-1 located seven kilometres north of the Twiga South-1 discovery along the Basin Bounding Fault Play in Block 13T. Logs indicated a significant oil column with an estimated 100 metres of net oil pay in good-quality sandstone reservoirs. In January, Africa Oil announced two more discovery wells at Amosing-1 located seven kilometres southwest of the Ngamia-1 discovery along the Basin Bounding Fault Play in Block 10BB. Logs indicate 160–200 metres of potential net oil pay in good-quality sandstone reservoirs. A new oil discovery at Ewoi-1 located four kilometres to the east of the Etuko-1 discovery in the Basin Flank Play on the eastern side of the South Lokichar Basin in Block 10BB was also announced. Logs indicate potential net pay of 20–80 metres to be confirmed by well testing. This year is expected to be a big one for the company, president and chief executive officer Keith Hill said. The near-term focus of exploration is to continue drilling and testing wells in the South Lokichar Basin in Northern Kenya, improving on recent cost efficiencies realized while continuing to grow the company’s contingent resource base, and to drill potential basin-opening wells in the Turkana, Chew Bahir, Kerio and Anza basins within Kenya and Ethiopia. “We have a very exciting exploration and appraisal program set out for 2014 which will see us complete over 20 wells,” Hill explained. “Currently we have seven rigs running, and after releasing one in mid-year and will have six rigs running full time through the remainder of the year. Our program has three objectives, to appraise the existing key discoveries, to drill out the remaining prospects in the
South Lokichar Basin and to open at least one of the four new basins being tested along trend. Additionally, we are pushing hard to move the development studies along with the aim of sanctioning a pipeline development for the South Lokichar Basin in the period 2015-2016.” Four of the seven rigs are targeting the Lokichar Basin, one rig is on Block 9 in the Cretaceous Anza rift in Northern Kenya, one rig in the South Omo Block in the Tertiary Basin in Southern Ethiopia and one rig is in Block 8 in the Jurassic-Triassic Basin in the Somali region of Ethiopia. So far, reserve evaluators say the South Lokichar Basin in Northern Kenya contains gross contingent resources of 368 million barrels of oil in the first three of seven discoveries in the basin, an increase of 557 per cent over the assessment conducted in mid-2012. In addition, gross risked prospective resources of 1,213 million barrels of oil are estimated for the South Lokichar Basin. Net contingent resources for the company are estimated at 231 million barrels of oil. Net unrisked prospective resources are estimated at 9,647 million barrels of oil.
West Africa offshore continues delivering Across the continent in West Africa, Canadian Natural Resources Limited continues reporting success offshore Côte d’Ivoire. In April, Canadian Natural announced its Saphir-1XB well has encountered an accumulation of light oil in the deepwater frontier exploration play in Block CI-514 offshore Côte d’Ivoire. The well was drilled by a semi-submersible rig in a water depth of 2,300 metres and reached a total depth of 4,655 metres. The well encountered a series of thick sands of approximately 350 metres, containing a hydrocarbon column of approximately 40 metres of light oil with 34 degree API gravity. The well was plugged and the data gathered will now be evaluated to determine the extent of the accumulation and the forward plan for appraisal. David Bell, vice-president of exploration for Canadian Natural’s subsidiary, CNR International (U.K.) Limited, said, “Saphir-1XB is an important discovery in a frontier part of deepwater offshore Côte d’Ivoire and has demonstrated a working petroleum system.”
Total E&P Côte d’Ivoire operates Block CI-514, with a 54 per cent working interest, along with CNR International at 36 per cent and PETROCI at 10 per cent.
Big hits drive South American exploration Canadian explorers have long been active in South America with companies like Pacalta Resources Ltd. in the 1990s opening up the region for future explorers. Pacific Rubiales is the leading Canadian operator, with acreage in both Colombia and Peru. As 2013 wound down, Pacific Rubiales announced it was in a state of transition as it moves to replace production from the Rubiales heavy oil field where the company’s production contract with the Colombian government will soon expire. “For the first time, we have provided a five-year forecast of net production that establishes a clear path beyond the Rubiales Field, and the visible barrels to completely replace the current net production of approximately 70,000 barrels per day from the Rubiales Field by the time the primary contract expires in mid-2016,” said Ronald Pantin, the company’s chief executive officer. “It is important to understand that by the time the contract expires, the Rubiales Field will be in steep natural decline. The replacement production will come from the development of our 50 per cent operated interest in the CPE-6 Block and our 100 per cent working interest in the Rio Ariari Block (acquired through the Petrominerales acquisition), which we expect will provide lower-cost, highervalue barrels. “In December, two drill rigs were moved onto the CPE-6 Block to commence the exploration and development appraisal program, and in early 2014, one drill rig was moved onto the Rio Ariari Block,” he added. “The company will employ additional rigs during the year to complete multi-well programs planned in each block. As the leading producer and developer of heavy oil production in Colombia, we have the track record and the expertise to rapidly ramp up the development of these heavy oil fields. “Over the last two years, the company has made a number of strategic acquisitions in Colombia. These acquisitions have provided us with a secure supply of light oil, which we can use as diluent to mix OIL & GAS INQUIRER • JUNE 2014
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Cover Feature
African proved oil reserves and production ()
South American proved oil reserves and production ()
Proved reserves (thousand million barrels)
Production (thousand barrels per day)
Reserve/ production ratio
Algeria
.
,
.
Angola
.
,
.
.
.
Chad
Proved reserves (thousand million barrels) Argentina Brazil
Production (thousand barrels per day)
Reserve/ production ratio
.
.
.
,
.
Colombia
.
.
Ecuador
.
.
Republic of Congo (Brazzaville)
.
.
Egypt
.
.
Equatorial Guinea
.
.
Peru
.
.
Gabon
.
.
Trinidad & Tobago
.
.
Libya
.
,
.
Nigeria
.
,
.
.
,
--
.
.
.
,
--
South Sudan
.
--
Sudan
.
.
Tunisia
.
.
.
.
.
,
.
Other Africa TOTAL AFRICA
Venezuela Other Central & South America TOTAL CENTRAL & SOUTH AMERICA
Source: BP Statistical Review of World Energy
Source: BP Statistical Review of World Energy
with our growing heavy oil production and replace the need to purchase and import more expensive less secure supplies of distillate. Through exploration and development activities, we have already increased production from the acquired assets and have realized additional value through midstream assets obtained as part of these acquisitions.” Pacific Rubiales is also enjoying exploration success in Peru. Well-test results on its Los Angeles-1X well in Block 131 in the onshore Ucayali Basin found 62 feet of net pay in the Cretaceous-aged Cushabatay Formation. Three separate tests have now been conducted across different net-pay intervals in the Cushabatay Formation under swabbing and natural flow conditions, and through variable choke sizes over 22–60 hour test periods, said Pacific Rubiales. Final flow rates from the three test intervals were 135 barrels per day, 936 barrels per day and 2,351 barrels per day respectively of 44–45 degree API light, sweet oil. Water cuts ranged from 10 per cent in the lowest interval to 0.3 per cent to nil in upper intervals. “The company is very encouraged by the test results in the Los Angeles-1X well in Block 131, and is looking forward to progressing this discovery and the earlier Sheshea-1X oil discovery in Block 126 through an evaluation phase and future development and production,” Pantin said. “These light oil discoveries support our confidence in the potential of the under-explored onshore basins in Peru.” 60
JUNE 2014 • OIL & GAS INQUIRER
Talisman Energy and its partner Ecopetrol S.A. are advancing development of the giant Akacías Field in Colombia, the company announced late last year. The co-venturers are completing a successful nine-well appraisal program following the Akacías discovery in 2010, and are now ready to move forward with field development. A Declaration of Commerciality has been submitted to the regulator, and a conceptual field development plan following that will be filed within 90 days. Eight successful appraisal wells were drilled in the Akacías Field in 2013. Current production of 7–9 degree API oil from three wells on long-term test is 5,300 barrels per day, which will ramp up as the remaining wells are put on long-term test. To date, 1.5 million barrels of oil have been produced from the Akacías-1 discovery well, which commenced long-term test in May 2011 with average production in excess of 2,000 barrels per day. The original oil in place mapped with the currently producing wells is 1.3 billion barrels. Assuming a 10 per cent recovery factor, a 2C contingent resource of 130 million barrels of oil is indicated. Structurally deeper wells drilled but yet to be placed on long-term test indicate greater oil in place; recoverability is yet to be determined. Upon receipt of the required environmental licence, additional appraisal and development drilling will commence to determine the full extent of the Akacías field, said Talisman.
“We will now move forward to agree on a development plan and obtain the necessary environmental permits. This milestone reflects a material step towards realizing the potential of our Colombian business and will bring significant benefits to Colombia,” said Hal Kvisle, president and chief executive officer of Talisman. “Akacías constitutes one of the major exploration achievements in recent years in Colombia, and clearly shows the heavy crude potential in the Llanos area, the target of Ecopetrol’s exploration campaign to reach its goals of producing one million barrels of clean oil equivalent in 2015 and 1.3 million barrels of oil equivalent in 2020. We will continue working together with our partner, Talisman Colombia, in the assessment and development not only of Akacías, but also of the potential existing across all the licensed area,” said Ecopetrol’s chief executive officer Javier Gutiérrez Pemberthy. Ecopetrol is the operator of Block CPO-9 and has a 55 per cent interest in the licence, while Talisman has a 45 per cent interest.
Is shale the next frontier in South America? While Colombia is a hotbed of activity for Canadian operators, an emerging shale play in Argentina could be the biggest elephant in the South American pack. Argentina’s giant Vaca Muerta shale oil and gas field could have as much 661 billion barrels of oil and 1,181 trillion cubic feet of natural gas resources, according to YPF, Argentina’s state oil company.
Cover Feature
Calgary-based Madalena Energy Inc. is targeting the Vaca Muerta, along with conventional targets in Argentina. In April, it released a resource estimate for its lands in the play, with a best estimate P50 total pet-roleum initially in place of 34.8 billion barrels of oil equivalent (51 per cent crude oil and natural gas liquids) net to Madalena. In late 2013, Madalena successfully implemented its fi rst use of horizontal drilling technology focused initially at its Coiron Amargo block in the Neuquén Basin in Argentina. Horizontal technology was applied to the Sierras Blancas Formation, which is a conventional light oil reservoir, sourced from the Vaca Muerta shale across the Coiron Amargo block. The CAN.xr-2(h) well was reentered and drilled horizontally and has produced approximately 63,000 barrels of oil in the fi rst three months of 2014. The results to date on the CAN.xr-2(h) horizontal have exceeded management’s expectations and as a result, Madalena has commenced a multi-well horizontal drilling program in Sierras Blancas for 2014. To kick off 2014, the CAN-15(h) well was recently drilled horizontally, and during testing operations the highest rates were achieved on a 12-millimetre choke setting, when the well flowed at a rate of 1,393 barrels of oil with 3,301 thousand cubic feet of associated natural gas for a total of 1,943 barrels equivalent per day (72 per cent oil) over a five-hour period. The next Sierras Blancas horizontal in the multi-well program for 2014 is expected to commence drilling in the second quarter of 2014. Madalena has a 35 per cent working interest in the Coiron Amargo block. Madalena has intensified its focus on the Vaca Muerta shale given the unconventional prize across the Coiron Amargo block. The block is positioned within the Neuquén Basin in the shallower portion of the Vaca Muerta oil window and in an area where over 150 Vaca Muerta shale wells have been drilled over the last 12–14 months. Industry activity continues to increase offsetting the Coiron Amargo block where Madalena drilled the CAS.x-14 and the CAS.x-15 vertical wells in Coiron Amargo Sur for the Vaca Muerta shale in 2013. The CAS.x-14 and CAS.x-15 wells were drilled and cased encountering approximately 105 and 114 metres respectively of Vaca Muerta shale on logs. Completion (stimulation work and/or multistage fracking) activities on these wells are expected to commence this summer.
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Feature
GLOBAL
PUSH
Canadian service companies finding increasing opportunities abroad, shale pushes growth By Carter Haydu
Photo: Joey Podlubny
G
lobal opportunities for Canadian oilfield service companies are on the rise, especially as jurisdictions outside North America start developing their shale opportunities requiring the hydraulic fracturing expertise that domestic pressure pumping providers already possess. “It’s definitely a significant area of growth,” Ron Gusek, vice-president of corporate engineering and technology at Sanjel Corporation, said late last year. “I think from an unconventional resource development standpoint, we are probably a good decade or more ahead of international opportunities, and so countries such as Saudi Arabia are just starting to search for their shale deposits.” Outside of Canada and the United States, Sanjel has operations in Latin
America, predominantly in Mexico, as well as in the Middle East in Saudi Arabia, northern Iraq, Kurdistan and United Arab Emirates, with regional headquarters located in Dubai, said Gusek. “We could envision a time when commercial development of unconventional resources starts internationally at a scale maybe not exactly like in North America, but certainly at a scale far beyond where they are today.” Gusek said shale developments will play a big factor in his company’s Middle East growth, even though there is lots of conventional production still to be tapped in the region. He said unconventional operations are so much larger than conventional ones, that when shale development hits the Middle East full steam, it should spell good times for service companies invested in the region.
“From our standpoint, in a place like Saudi Arabia, we see growth even from just a conventional standpoint, but the real growth in opportunities, specifically from something like hydraulic fracturing, will come with development of an unconventional resource.” Gusek said Australia is also definitely exploring shale opportunities, as are Russia and South American countries such as Argentina, Columbia and even Venezuela. Further, he said, Sanjel is seeing a move toward shale development in China. “Our completions division [Sure Tech Tool Services Inc.] sells into China. We don’t have pumping-service operations there yet, but that is certainly an area of interest.” Russia is the largest foreign market for Trican Well Service Ltd., said company chief executive officer Dale Dusterhoft. The company also has operations in Kazakhstan, Algeria and Australia, as well as operations opening up in Columbia and Saudi Arabia in 2014. “If you look at the evolution of it, we have seen growth in the Russian market, but it has not grown rapidly in the last year or so in our international operations.” In Russia, Dusterhoft said, conventional oilfields drive much of Trican’s business, although there is also an emerging shale play that could tap into his company’s pressure pumping expertise. In Australia, he said, Trican is mainly involved with coal-associated natural gas, as well as an emerging liquefied natural gas export industry. In Algeria, he said, business mostly revolves around conventional oil and gas, while in Kazakhstan it appears to be mainly conventional oil. “I would say that for the most part, most regions of the world are not yet being driven by shale. In the future, we believe OIL & GAS INQUIRER • JUNE 2014
63
Feature
Taking Alberta technology overseas By Jacqueline Louie Robotics from Japan, and software development and engineering know-how from Alberta. For Automated Tank Manufacturing Inc (ATM), it’s a formula for success as it competes in North America’s ultra-competitive tank-manufacturing market. ATM specializes in manufacturing storage tanks and vessels for the oil and gas industry. Based in Kitscoty in east-central Alberta, 20 kilometres west of Lloydminster, ATM was established in 2008. It introduced automation and robotic welding systems to its tank manufacturing process in 2010. “A lot of industries use robotics. In our industry, it has just started,” says ATM co-founder, president and chief executive officer Joe Bowser. For ATM, turning to automation was a way to deal with a chronic shortage of journeymen welders and to increase the efficiencies of the welding processes it uses. “The way we manufacture has increased quality, while greatly reducing the cost of labour,” Bowser notes. “We have reduced the labour costs in building tanks by 50 per cent or more through automation. We have half the amount of staff and produce nearly twice as many tanks as most manufacturers.” With 62 employees, ATM can build up to four 1,000-barrel tanks per day, with the capacity to produce up to 1,100 tanks per year. (On average, it produces 700–850 tanks per year, depending on the size of tank). Automation has allowed ATM to compete continent-wide. The company ships its tanks throughout western Canada and into the United States, including the Dakotas, California and Montana. “We are highly competitive,” Bowser says, noting that ATM’s average price for a 750-barrel tank is $35,000, and $120,000 for a 2,000-barrel tank. “We offer significant planning and manufacturing cost savings to all our clients through just-in-time manufacturing.” As a just-intime manufacturer, ATM’s turnaround time on new tank orders is under 10 days.
it’s just going to be unconventional overall. Shale and tight rock will become a much bigger part, and in particular [there will be] growth in horizontal wells and multistage horizontal fracturing as well. “A lot of these regions already have good-quality reservoirs, and so they don’t have to be into the tight rock that we have to be in here in North America. So they haven’t gotten to it yet, but they will at some point in time, because in all areas of the world you start out with your best rock and you work yourself down to the shales. A lot of these areas are not yet at shales, but they will over time.” Dan Themig, president and chief executive officer at Packers Plus Energy Services Inc., told the Daily Oil Bulletin 64
JUNE 2014 • OIL & GAS INQUIRER
For oil companies, rather than having to pre-order storage tanks at the beginning of the year, “we take their drilling program and start manufacturing tanks when they’re needed,” Bowser says. “I can literally set up our manufacturing for drilling programs for up to 35 oil companies at a time.” All of ATM’s systems design, software and processes are patented. The company has created an in-pit lifting rotating system that goes 32 feet into the ground, which allows it to avoid the use of scaffolding. ATM builds tanks in an in-ground lined silo, complete with an elevating system that allows tanks to be easily lifted in and out of the silo. “It’s far, far safer to utilize automation,” Bowser says, noting that ATM has removed the majority of trip hazards in its work processes; and by avoiding the use of scaffolding, welders’ feet never leave the floor. Using laser tracking systems, two robotic welders can do a 48-foot horizontal seam and eight-foot vertical seam in 22–24 minutes—a task that would take two human welders, in comparison, approximately four hours to complete. Quality also improves, Bowser says: robotic welding greatly eliminates the amount of porosity in the weld structure, for a more consistent, deeper welding process. ATM is continuing to add new automation methods to enhance its tank design and manufacturing process. Later this year, it’s adding robotic plasma cutting, which Bowser expects will decrease costs by another 20 per cent long term, and further reduce human error in the welding process. “Our business growth has been incredible,” says Bowser, who regularly takes calls from companies looking to purchase ATM. The company is now licensing its automation process, and Bowser’s long-term goal is to expand the technology overseas. “We’ve taken a potentially $10-million-a-year business and grown it to between a $30-million to $40-million business over the last four years.”
that open-hole multistage fracturing equipment seems to be the most popular service his company provides to markets outside Canada and the United States. “We are working in a lot of areas around the world. We’re working in the Middle East in Saudi Arabia, and some work in Kuwait. We have done a considerable amount of work in both western China and southcentral China. As well, we currently have ongoing work in Russia, North Africa, we worked in the North Sea and offshore in West Africa, the Black Sea and Australia. “We’ve done quite a bit of work in Argentina and Brazil, and Mexico. We cover a lot of the basins internationally.” According to Themig, much of Argentina’s hydrocarbon development would mirror
what is happening in Canada, with tight oil and gas and a shift to shale reservoirs such as the Vaca Muerta. “I don’t think that is the only place, but that seems to be the one that is drawing the most interest right now.” As for Mexico, Gusek said Sanjel believes the country holds much growth opportunity as the nation opens up its petroleum sector to more foreign investment. “They have been in a decline for quite a few number of years now, and they recognized they needed a bit of a change in how things were being done down there to turn that picture around. “So they have laid out a new roadmap for development of the next five to 10 years in Mexico, and we see significant
Feature
opportunities there both onshore and ultimately offshore.”
Why working abroad makes sense for Canadian service companies Although Canada and the United States certainly represent an extremely large opportunity for service companies, Gusek said the North American market is also somewhat volatile and the international market is an opportunity to “smooth out those bumps” a bit. “We see this as an opportunity to balance out our business a little bit. We like to refer to it as the three-legged stool. We have Canada and we have the U.S., and those are two very large business units for us. However, they are both very similar in terms of the ups and downs. We want another leg [on] that stool to help stabilize things a little bit, and of course for us that is the international market.” In many cases, Gusek said, foreign countries simply do not have adequate access to their own pressure pumping companies, although many are already served by one of those larger global companies such as Baker Hughes Incorporated or Halliburton. However, he noted, even
though the industry’s big players might already be working in these regions, that does not mean there is not a lot of business for Canadian service companies such as his. “As that market continues to grow, like everybody, [foreign customers] like to have options for their supply, and we see ourselves as a smaller and slightly more nimble player with a little bit more flexibility, and I think that offers us a spot in those markets and separates us from the incumbents who are already there and have been there for some period of time.” Dusterhoft said in a lot of countries there is also a current lack of infrastructure to push shale development to the same extent as has been accomplished in Canada and the United States. He believes this North American experience with shale oil will bode well for Canadian service companies such as Trican as they develop into the international markets over the years ahead. “I think if you look at the regions of the world, they will all eventually develop their shale at some point in time. Australia is starting to do some shale work, and so we’re starting to see a little bit of shale work in its infancy there.
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“I would say that in South America we see some opportunities, and we would probably see some in Mexico at some point in time as well.... Some countries in South America and Mexico will probably start working on shale in the next three to four years.” Expanding internationally is important for Trican, Dusterhoft said, because the company has a long-term plan of continued growth over the next decade, and domestically if the growth opportunities halt for some reason, it would be good to have options beyond the continent. “We also think the technology we bring and the service attitude we bring is something that is valued in these countries and would allow us to compete with anybody,” he said. From the perspective of Packers Plus, the best reason to expand into international markets is to ensure the company’s technology solutions reach potential customers before another service company is able to do so, Themig said. “If we don’t fill the void for technology internationally, then they will find someone else to do it. So it’s either that you go forth and figure out how to get
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Top 10 countries with technically recoverable shale oil resources 9 9 75
13
13 18
345
26
billion barrels 27
58 32
1 2 3 4 5 6 7 8 9 10
Russia United States China Argentina Libya Australia Venezuela Mexico Pakistan Canada
Top 10 countries with technically recoverable shale gas resources 245 1,115
390 437
7,299
802
1 2 3 4 5 6 7 8 9 10
285
545
trillion cubic feet
707
573 665
China Argentina Algeria United States Canada Mexico Australia South Africa Russia Brazil
Source: U.S. Energy Information Administration
involved internationally, or probably one of the bigger international companies will come and try to duplicate your technology and take it to the international markets,” he said, adding the worst scenario is for a foreign oil and gas company to end up using the wrong technology resulting in unsuccessful development. According to Themig, while shale development internationally is still fairly new, international markets are adapting shalecompletion technology for use in a variety of reservoirs and high-cost completion areas.
“So we’re exporting shale technology, but the uptake has been fairly universal.”
The challenges of foreign opportunities The political risks for service companies working abroad are numerous, Themig said, as many countries lack the businessconducive stability of Canada or the United States. “If you were to look back [approximately] 10 years ago at Venezuela, it was a great place for western companies and Canadian companies. Then the political
landscape changed and along with it political risk really destroyed a lot of people’s business and ongoing business. “That would be one case, but another from a political standpoint is how we were really just beginning to make some massive traction in areas such as Libya that are perfect for our technology. Then, of course, the political events really took what was a couple of years of groundwork and really sort of put it on hold for... well...we don’t really know how long it will be.”
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Themig said there are numerous areas around the world where geopolitical risk exists, including West Africa, throughout Latin America, as well as Russia and China to a degree. “Even areas like France can have political risk, where they have outlawed fracturing, and there are some Canadian companies that were utilizing that technology in France, and so they’re on hold. We’ll see how that goes.” Canadian service companies working abroad find many challenges unlike what is found in North America, Gusek said, especially in countries without experience in unconventional resource extraction. “First off, unconventional development happens on a different scale than these countries have typically been used to. Where I would say the operations are slower and more methodical when compared to North America, developing unconventional resources means getting very, very good at this efficient factory approach to drilling and completing wells like we have seen in North America. “That’s not a business model that exists, at least in my knowledge, anyplace else in the world. So that’s a bit of a change
in mindset of how companies operate. In conversations we have had with some of our partners overseas, part of [the challenge] is just an education process to help them understand exactly the scale and scope of these operations.” When talking about development of unconventional resources in the Arabian Desert, Gusek said the obvious logistical challenge is water. “Making sure you have access to those commodities in large, large volumes is very, very important. When you look at a place like Saudi Arabia, development is likely going to take place in the middle of the desert, and we pump 2,000 cubic metres a stage in some of these gas wells for a frac, and there could be 15 stages. “When you’re in the desert that is a huge amount of water to source, and it is likely to come from a sea of some place. So you need to think about things like that.” According to Dusterhoft, a challenge with working internationally is the pace of operations. He said usually it takes longer for work to get underway in some of these countries, “so you have to be patient developing an international market.” Further, he said, service companies need to deal with a lack of
appropriate infrastructure in many regions, as well as a company needs to understand particular cultures and peoples associated with a specific area of operations. “You want to hire as many locals as possible, but you also want them to fit into your culture, and that is quite often a challenge. You also have to understand the customer-base, and that can be a challenge as well. There are a number of things you have to be good at.” Gusek said other challenges with operating abroad include getting equipment and people into some of these countries, dealing with visa issues, as well as finding new sets of suppliers. “In North America, we have a standard set of vendors who provide us with proppant and cement and treating iron, frac pumps and all those sorts of things. We have to sort out a whole new supply chain in many of these international places where business has not existed on this sort of scale before. So we have issues like that to work through as well.”
Companies hope to grow international business According to Gusek, while international business only makes up a small portion
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of Sanjel’s current customer portfolio when compared to Canada and the United States, it nonetheless represents the fastest-growing piece of the company’s business, and is set to continue growing into the foreseeable future. “We would love to see it get to a point where it represented a meaningful portion. It would be great if it was 35 per cent and we were kind of split equally, but it is hard to say what it will look like over the long term. However, that is certainly our goal and certainly where we see some of the largest opportunities for growth right now.” When Packers Plus formed about a decade ago, Themig said, the company saw its ideal business split at 40 per cent Canada, 40 per cent the United States and 20 per cent international. Currently, the company has a range of about 10–20 per cent international business in its portfolio. “It was expected that hydraulic fracturing would become significantly larger as a percentage of worldwide fracturing, but it hasn’t happened, mostly because North America has grown massively over the past eight years or so in both Canada and the United States. “And so the international market has grown as was expected, but I don’t think anyone had anticipated North America would grow the way it has.” Although it will not be for another eight to 10 years, Themig said he still expects the portion of Packers Plus business that is international will come closer to being on par with Canadian and U.S. operations. He added there are “a lot of moving pieces” in the international market that require a lot of work for smaller companies such as his to get set up in these foreign jurisdictions. “So it is a slow and steady process for us, but it is very complicated to work internationally in a large variety of markets. We kind of knew that going in, and it has proven to be every bit as difficult as we thought it might be.” As for Trican, in the short term, the company plans to continue building its business in the regions in which it has already invested. In the long term, Dusterhoft said, the company would expand its global reach until it comprises a more equal portion of the company’s portfolio. “Currently, only about 12 per cent of our revenue is international. Over a long, long term I think we could see that reach the 20 per cent range.”
CARTOON
advertisers' index Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . 37 Annugas Compression Consulting Ltd . . . . . . . . 38 Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 32 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 22 Brews Supply . . . . . . . . . . . . . . . . . . . . . . . . 47 & 57 Brother’s Specialized Coating Systems Ltd . . . . 46 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 22 CENTA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 CG Industrial Specialties Ltd. . . . . . . . . . . . . . . . 69 Chase Operator Training . . . . . . . . . . . . . . . . . . . 37 Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . 42 Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Dow AgroSciences Canada Inc . . . . . . . . . . . . . . . 8 DPS Microbial Solutions . . . . . . . . . . . . . . . . . . . 42 Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . 25 DSI Thru-Tubing Inc . . . . . . . . . . . . . . . . . . . . . . . 46 easyFairs UK Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 48 Eclipse Rentals Inc . . . . . . . . . . . . . . . . . . . . . . . . 53 Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . .61 Edmonton Exchanger & Refinery Services Ltd . . 68
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ENTREC Corporation . . . . . . . . . . . . . . . . . . . . . . . 3 Environmental Refuelling Systems Inc . . . . . . . . 65 FaciliOp Experts Corp . . . . . . . . . . . . . . . . . . . . . .18 Farrow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Globalstar Canada Satellite Co . . . . . . . . . . . . . . . 5 Hazloc Heaters . . . . . . . . . . . . . . . . . . . . . . . . . . .41 HSBC Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . 44 Industrial Training International . . . . . . . . . . . . . 26 Infosat Communications LP . . . . . . . . . . . . . . . . 35 League Pipeline Services Ltd . . . . . . . . . . . . . . . 52 Lloydminster Heavy Oil Show . . . . . . . . . . . . . . . 44 Mainland Machinery Ltd . . . . . . . . . . . . . . . . . . . 48 MaXfield Inc . . . . . . . . . . . . . . . outside back cover Meridian Manufacturing . . . . . . . . . . . . . . . . . . . .14 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 40 NAIT Corporate and International Training . . . . . 24 NCSG Crane & Heavy Haul Services . . . . . . . . . . 23 Netzsch Canada, Inc . . . . . . . . . . . . . . . . . . . . . . . 50 Norseman Structures . . . . . . . . . . . . . . . . . . . . . . 17 Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . 50
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 23 Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . . 10 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51 Phoenix Fence . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Platinum Energy Services ULC . . . . . . . . . . . . . . .19 Platinum Grover Int. Inc . . . . . . . . inside front cover Pumps & Pressure Inc . . . . . . . . . . . . . . . . . 36 & 66 RedGuard . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 & 67 Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . 29 Rush-Overland Manufacturing . . . . . . . . . . . . . . 56 STEP Energy Services . . . . . . . . . . . . . . . . . . . . . 31 Strad Energy Services-Matting . . . . . . . . . . . . . . 43 Tank Gauging Systems . . . . . . . . . . . . . . . . . . . . . 41 Tervita . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . . . 15 Tundra Process Solutions Ltd . . . . . . . . . . . . . . . 20 U F A . . . . . . . . . . . . . . . . . . . . . . . inside back cover V J Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 11 Vortex Drilling Ltd . . . . . . . . . . . . . . . . . . . . . . . . 28 WashCars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Zeeco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
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