OIL&GAS September 2014 ~ $6.00
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CONNECTING
THE DOTS SAGD operators combine technologies, strategies to wring out more value from reservoirs
PLUS: Peace River Arch continues providing stellar opportunities for disciplined explorers
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CONTENTS
SEPTEMBER.
in the news
9
Canadian light crude discount may widen, says report
regional news
15
31
British Columbia
Central Alberta
Apache may exit both upstream and downstream Kitimat LNG project
Penn West planning 83 light oil wells
21
35
Northwestern Alberta
in third quarter
Southern Alberta
Delphi cracks Montney using
Pine Cliff buys shallow gas assets
slickwater fracs
from Nexen for $100 million
25
39
Northeastern Alberta
MEG reports record volumes
Saskatchewan
Surge Shaunavon drilling success continues
features
COVER
FEATURE
40 43 46
Connecting the dots SAGD operators combine technologies, strategies to wring out more value from reservoirs
every issue
6 50
Northern lights Peace River Arch continues providing stellar opportunities for disciplined explorers
Getting it done Managing drilling and completions supply chain key to resource play success
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OIL & GAS INQUIRER • SEPTEMBER 2014
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The process of drilling extended-reach horizontal wells and stimulating them with multistage fractures has allowed the industry access to tens of billions of barrels of oil and hundreds of trillion cubic feet of gas trapped in tight rock and shale. The challenge now is to produce that resource economically and wring out as much profit as possible. Unconventional resource developers are relentlessly improving their techniques and processes, and, as a result, are gradually bending the cost curve downward. Advances in drilling technology are part of the story, Trent Yanko, president and chief executive officer of Legacy Oil + Gas Inc., told a recent TD Securities conference. In the Spearfish play in Manitoba, Legacy has cut drilling times from nine days to six. Yanko said it’s been a step-by-step process. “It’s been a lot of small wins. We attack it from bit selection, motors, staying in the zone more consistently,” he said. “The more you’re in the zone, the less you’re steering. It’s like on a racetrack. The more times your wheels are pointing forward, the faster you can go.” These improvements are coming across the industry. In its year-end report, Precision Drilling Corporation said the average rate of drilling reached 189 metres per day in 2013, up from 168 metres per day in 2012. Improvements in well stimulations are also bending the curve as operators match fracturing technologies to reservoir conditions. An example of this is Delphi Energy Corp.’s Montney program in northwestern Alberta. Delphi is using a 30-stage slickwater hybrid completion in the Montney, and it is
reporting huge improvements in well performance in the play compared to the smaller conventional program it had previously used. An initial 30-day comparison between two wells 400 metres apart shows the slickwater technique is almost doubling production. “Longer term, production tripled after 30 days and wellhead condensate yields have also improved by two to three times,” reports the company. In situ oilsands producers are also bending the cost curve. A combination of infill drilling and injection of methane has reduced the steam to oil ratio to 1.3 on well pairs at MEG Energy Corp.’s Christina Lake operations. MEG is producing 60 per cent above the design capacity of its Phase 1 and Phase 2 operations at Christina Lake as a result of these efforts, says company president and chief executive officer Bill McCaff rey. The success in driving down costs comes at a time of great market uncertainty as oil export pipelines remain stalled and liquefied natural gas export terminals to the West Coast await corporate approval. Right now, western Canada’s oilpatch is a price-taker, not a price-maker. Controlling development costs, while always important, is crucial in this environment. If the cost curve continues to bend downward, expect a windfall when export markets open up and prices improve. Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
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N EXT I S S U E October 2014 Operators continue to fine-tune fracturing programs to optimize production We’ll look at where they’re at on a play-by-play basis Plus, an update on the Lloydminster heavy oil belt, including a review of production advances and
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how operators are finding markets OIL & GAS INQUIRER • SEPTEMBER 2014
5
FAST NUMBERS
Average metres drilled per day per rig in 2012, according to Precision Drilling Corporation.
Average metres drilled per day per rig in 2013, according to Precision Drilling.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin T O TA L
MONTH
Aug
Sep
Oct
M O NTH
OIL
GAS
Aug
Sep
Oct
OTHER
OIL
GAS
D RY
SERVICE
T O TA L
,
Nov
Nov
,
Dec
Dec
Jan
Feb
,
Jan
Feb
Mar
Mar
,
Apr
Apr
May
May
Jun
Jun
Jul
Jul
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 *
MONTH
OIL
GAS
Aug
Aug
Sep
Sep
Oct
Oct
Nov
Dec
Nov
Jan
Dec
Feb
Jan
Mar
Feb
Apr
Mar
May
Apr
Jun
May
Jul
Jun
Jul
*From year-to-date
OTHER
TOTAL
www.bcri.ca Our team of scientists and engineers are ready to bring your
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chemical products and processes PROOF FEASIBILITY OF CONCEPT STUDY Custom Research
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SEPTEMBER 2014 • OIL & GAS INQUIRER
Preliminary Engineering
PILOT PLANT
COMMERCIAL SCALE
Design, Construction and Operation
Detailed Engineering
from concept to commercialization
STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, August 11, 2014 Source: Rig Locator
Alberta, July 2014 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E (Per cent of total)
Western Canada Alberta
OIL WELLS
Alberta
GAS WELLS
Jul
Jul
Jul
Jul
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
%
Southern Alberta
%
TOTAL
WC TOTAL
Top Active Drillers in Canada
Drilling Activity: CBM & Bitumen
Western Canada, August 11, 2014 Source: Rig Locator
Alberta, July 2014 Source: Daily Oil Bulletin
O P E R AT O R
ACTIVE RIGS
DEV
EXP
OTHER
Canadian Natural Resources Limited
Progress Energy Canada Ltd.
Crescent Point Energy Corp.
Husky Energy Inc.
Tourmaline Oil Corp.
Cenovus Energy Inc.
Encana Corporation
ConocoPhillips Canada
Bellatrix Exploration Ltd.
C OA L B E D M E T H A N E
Alberta
BITUMEN WELLS
Jul
Jul
Jul
Jul
Northwestern Alberta
Northeastern Alberta
Central Alberta
Southern Alberta
TOTAL
OIL & GAS INQUIRER • SEPTEMBER 2014
7
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IN THE
NEWS Issues affecting Canada’s E&P industry
Photo: Joey Podlubny
Canadian light crude discount may widen, says report The growing glut of light oil in the United States, coupled with tight pipeline capacity out of western Canada, could result in widening discounts for Canadian light oil that reflect rail versus pipeline transportation costs for getting it to export markets, said a new report. “It’s almost becoming a bit of a new world for our Canadian light producers,” David McColl, an equity analyst with Morningstar, Inc. and author of the report, said in an interview. “It might take time for things to kind of shake out, but at the end of the day, we need to find ways to close that gap.” Canadian differentials—Edmonton Par versus Brent—are expected to widen to between $17 and $21 per barrel from the historic $2 per barrel, according to the report on market access from the independent investor research firm. Heavy differentials, meanwhile, are expected to increase to between $23 and $29 per barrel from $19 per barrel. However, new pipelines such as TransCanada Corporation’s Energy East (1.1 million barrels per day) and Kinder Morgan Inc.’s Trans Mountain Expansion (590,000 barrels per day)—both anticipated to be in service in 2018—should provide increased access to tidewater and new global markets by the end of the decade. In the meantime, producers have looked to rail to gain access to refineries in Montreal and the Irving Oil Limited refinery in Saint John, N.B., in advance of new pipelines, reducing the risk that light crude will be locked in Alberta, according to McColl. Rail loading capacity, which is expected to reach one million barrels per day by the end of this year, should be more than sufficient to accommodate an expected peak of 850,000 barrels per day in 2017 for shipment to markets in the United States, Quebec and Canada’s East Coast, said the report. “With our export terminals in Canada and throughout the entire U.S., we do have
the potential to get Canadian crude to international markets faster than we ever thought possible and as long as the U.S. keeps its export restrictions on crude oil,” said McColl. Reflecting its view of the expected cost to ship crude by rail to Atlantic Canada, Morningstar suggested that Canadian light will require a discount of $19 per barrel to Brent or $9 per barrel to West Texas Intermediate to make U.S. refiners “agnostic” between Canadian and U.S. light crudes. Dilbit and heavy grades of Canadian crude, including Western Canadian Select, are expected to require differentials off Brent of $27 per barrel. If Canadian light crude can reach ports and be loaded onto tankers for markets in Asia and Europe, producers are potentially looking at higher netbacks, according to McColl. The report estimates that up to 500,000 barrels per day of Canadian light and 400,000–700,000 barrels per day of
Canadian differentials—Edmonton Par versus Brent—are expected to widen to between $17 and $21 per barrel from the historic $2 per barrel.
heavy could be available for export to international markets through 2017. In the near term, rail exports to Atlantic Canada then on to Europe or to British Columbia on to Asia support higher netbacks—of $82 per barrel and $80 per barrel, respectively—than if the crude were sold into Cushing, Okla., at $75 per barrel or the U.S. East Coast at $72 per barrel, according to the report. Because of the lower pipeline costs of $7–$9 per barrel, once Energy East comes on after 2018, crude to Saint John then on to Europe would yield superior netbacks of $94 per barrel compared to $85 for sales into the U.S. East Coast, it says. “Energy East could very well become Canada’s gateway to the world; that’s a huge potential I think we need to recognize in Atlantic Canada,” said McColl. “We will reach a point where we fill up the Canadian refineries, and then we will just be putting out light oil into the Atlantic Basin.” Morningstar’s first thought was that initially Energy East would likely flow mainly light oil, McColl said. “Over time, we imagine the pipeline will start getting heavier— roughly 50/50. It’s a short distance [from Saint John] to get it right into the Gulf Coast.” Canadian light oil producers also stand to gain from selling crude into the Asian market through rail-to-tanker or pipeline-to-tanker, with the assumed export terminal at the Westridge Marine in Burnaby, B.C., said the report. “Largely a result of transportation distances, we find this an appealing option for producers,” it said. W hen it comes to heav y crudes, Morningstar said it continues to believe that the U.S. Gulf Coast will be the primary market for Canadian bitumen, backing out U.S. imports of foreign heavies from countries such as Mexico, Saudi Arabia and Venezuela. — DAILy OIL BULLETIN OIL & GAS INQUIRER • SEPTEMBER 2014
9
In The News
Operators across Canada rig released 11.23 million metres in the first half of 2014, up nearly 13 per cent from 9.97 million metres drilled from January to June last year. That’s the most metres drilled in the first half since 2006, when 13.14 million metres were drilled. That year, operators rig released 10,609 wells. This year’s 11.23 million metres were drilled with only 4,961 wells. In western and northern Canada, the average length of development and exploratory holes for the half lifted to 2,260 metres, up from 2,060 metres in the same period a year ago. In 2006, the average length of a well was 1,238 metres. In British Columbia, total metres drilled increased 34.58 per cent in the first half of 2014 to 1.32 million metres compared to 980,548 metres from January to June in 2013. Metres drilled in the first half
increased 12.71 per cent in Alberta to 7.27 million metres versus 6.45 million metres of hole in the comparable period last year, while Saskatchewan’s metres drilled rose 16.31 per cent to a record 2.38 million metres from 2.05 million metres last year. Manitoba’s metres-drilled tally declined 44.84 per cent to 257,643 from 467,073 metres a year ago. The 4,961 wells drilled across Canada during the first six months of 2014 was an increase of 2.58 per cent from the 4,836 wells drilled in the comparable period a year ago. Drilling counts were flat in Alberta compared to last year, but up in British Columbia and Saskatchewan and down in Manitoba. Alberta’s rig release count remained steady, dipping slightly to 3,086 in the half versus 3,105 in the first six months of 2013—a change of only 0.61 per cent.
Operators across Canada rig released 11.23 million metres in the first half of 2014, up nearly 13 per cent from 9.97 million metres drilled from January to June last year.
In British Columbia, the rig count increased 33.08 per cent to 346 wells from 260 in last year’s first half, while in Saskatchewan the count lifted 14.91 per cent during the half to 1,387 from 1,207 a year ago. Manitoba’s count declined by 44.8 per cent to 138 wells drilled from 250 to the end of June last year. In comparing Alberta and Saskatchewan, the former’s overall count for the half included four new field wildcats, while the latter’s included 19. Saskatchewan’s rig release total also included 125 outpost holes versus 95 in Alberta, while the Wild Rose province drilled 45 new pool wildcats compared to 39 for its eastern neighbour. Of the wells drilled across Canada to the end of June, 644 still have no final status (oil, gas, dry or service). Of those with a status designation, 3,157 (72.93 per cent) were reported as an oil well. There were 713 wells listed with a gas status, up from 674 a year ago. In June, operators drilled 650 wells across the country, compared to 525 rig releases in the same period the year prior, with increases in all western provinces except Manitoba. Saskatchewan’s drill count increased 60 per cent to 272 wells rig released compared to 170 in June 2013. Operators working in British Columbia rig released 30 wells in June compared to 22 the prior year (an increase of 36.36 per cent), while the count in Alberta lifted to 337 in June from 302 a year ago (an increase of 11.59 per cent). In Manitoba, 11 wells were rig released in June versus 26 a year ago. — Daily Oil Bulletin
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SEPTEMBER 2014 • OIL & GAS INQUIRER
Photo: Aaron Parker
Metres drilled in first half at eight-year high
In The News
More gas development wells being completed Data reported by the Daily Oil Bulletin show that 4,886 wells were completed in the fi rst half of 2014, for 11.02 million metres of hole, with a greater number of gas development wells completed compared to a year ago. In western Canada, operators completed 876 gas development wells in the fi rst six months of the year compared to 586 a year ago, an increase of 49.5 per cent. Industry also completed 3,186 oil development wells, about even with 3,189 a year ago. Overall, there have been 4,110 wells assigned a development completion fi nal status to the end of June, up from 3,813 a year ago. There is a focus on development wells at the expense of exploratory drilling in western Canada, however. Operators completed only 345 exploratory wells in the first half, off from 480 a year ago. Including both development and exploratory holes, 961 gas wells have been completed compared to 714 from January to June in 2013. Excluding experimental wells, Alberta had 2,067 oil wells completed in the fi rst six months of 2014, down from 2,197 a year ago, while gas well completions rose to 634 from 482. Operators in British Columbia completed 327 gas wells in the first half, up from 231 in the comparable period of 2013. In Saskatchewan, industry has completed 1,191 oil wells to the end of June versus 1,036 a year ago. — DAILy OIL BULLETIN
Horizontal drilling at record high A record 3,773 horizontal wells were drilled in the first half of this year, excluding experimental and test wells, with the three most western provinces at record highs for the period, led by significant percentage hikes in British Columbia and Saskatchewan. The 3,773 horizontal wells rig released represent a 13 per cent increase from 3,340 wells a year ago, and the number is up about 18 per cent from 3,186 horizontal wells drilled in the first six months of 2012. British Columbia, Saskatchewan and Alberta are setting new highs for horizontal drilling this year. In British Columbia, operators fi nished drilling 331 horizontal wells in the first half, up 36.21 per cent from 243 wells last
year. This year’s count beats the previous record of 315 horizontal wells drilled in the first six months of 2004. Saskatchewan operators rig released 1,093 horizontal wells during the first half of 2014, up 27.69 per cent from 856 last year, while operators rig released 2,230 new horizontal wells in Alberta to the end of June compared to 2,006 a year earlier (up 11.17 per cent). In Manitoba, 119 horizontal wells were drilled in the first half compared to 234 last year (down 49.15 per cent). As for directional wells (excluding experimental and test wells), a total of 759 were rig released in the fi rst half of 2014, down from 861 a year ago. — DAILy OIL BULLETIN
PSAC ups drilling forecast In response to stronger-than-anticipated drilling performance in the first half of the year, the Petroleum Services Association of Canada (PSAC) has increased its 2014 Canadian drilling activity forecast by six per cent over its original outlook. In its third update to its forecast, released this month, PSAC said it now expects to see 11,460 wells drilled (rig released) in Canada this year. That’s 660 more wells than in the original forecast, released in late October 2013, that called for 10,800 wells to be drilled in 2014. In January 2014, PSAC increased its forecast by 1.2 per cent (130 wells) to 10,930 wells and, in April of this year, forecast 370 more wells for 2014 than initially expected.
PSAC’s updated 2014 forecast is based on average natural gas prices of $4.75 per thousand cubic feet at AECO, crude oil prices of US$100 per barrel (West Texas Intermediate) and the Canadian dollar averaging 90 cents. “PSAC has revised its figures based on a stronger-than-anticipated performance during the first two quarters, with 245 more wells drilled during that period,” Mark Salkeld, PSAC president and chief executive officer, said in a news release. “We are confident this performance trend will continue, and we are forecasting an additional 415 wells to be drilled in Q3 and Q4.” On a provincial basis, the updated forecast includes increasing activity across most of western Canada.
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OIL & GAS INQUIRER • SEPTEMBER 2014
11
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Alberta is expected to see an additional 207 wells drilled for a total of 6,762 wells, representing a three per cent change from the October outlook. Additionally, PSAC said it expects an uptick in activity in British Columbia with 157 additional wells for the year, or a 28 per cent increase, to a total of 707 wells in that province. In Saskatchewan, PSAC is forecasting a new total of 3,544 wells, which represents an increase of 348 wells, or 11 per cent, over the initial numbers. However, PSAC has reduced the activity expected in Manitoba by 10 per cent to 430 wells from the initial forecast of 480 wells.
“PSAC has revised its figures based on a stronger-thananticipated performance during the first two quarters, with 245 more wells drilled during that period.” — Mark Salkeld, president and chief executive officer, PSAC
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SEPTEMBER 2014 • OIL & GAS INQUIRER
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In terms of well type, in the first six months of 2014, the trend of drilling for oil rather than natural gas continued with 2,862 oil wells versus 509 gas wells drilled. Additionally, 84 per cent of all wells drilled in the first half of the year were horizontal and directional wells compared to 16 per cent for vertical wells. Salkeld said that a number of factors are driving the better-than-expected activity this year. A key factor is the increase in natural gas prices, which is partially being driven by low gas reserves, which are at their lowest level in more than 10 years, resulting in a corresponding increase in demand, he said. “Beyond that, well completions continue to gain efficiencies, and that is speeding up activity levels in key formations.” — DAILy OIL BULLETIN
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BRITISH COLUMBIA WELL ACTIVITY JUL/13
JUL/14
Wells licensed
JUL/13
JUL/14
Wells spudded
JUL/13
JUL/14
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
B.C. British Columbia
Apache may exit both upstream and downstream Kitimat LNG project By Richard Macedo
Image: Apache Corporation
During its second-quarter results call in early August, Apache Corporation signalled that the Kitimat Upstream division’s assets could also be part of its exit from the proposed Kitimat LNG export project. The company announced in late July that it intends to completely sell its stake in the proposed multi-billion dollar Kitimat LNG project.
“Certainly, we have two businesses in Canada. We have a business, which is a base business that we have with respect to the Duvernay shale, the Montney…and some of the other things that we’re working on there,” G. Steven Farris, chief executive officer and president, said during the conference call. “We also have the Kitimat/Horn River/Liard. Kitimat, Horn
River and Liard is part of our LNG [liquefi ed natural gas] project that we indicated—and re-indicated—that we intend to exit.” An Apache spokesperson later said that “it’s too early now to know how any deal or deals will be structured.” Under a deal that closed in early 2013, Chevron Canada Limited and Apache Canada Ltd. each became a 50 per cent owner of the K itimat LNG plant, the Pacific Trail Pipeline and 644,000 gross undeveloped acres in the Horn River and Liard basins.
Apache is looking for someone to take over its 50 per cent share in the Kitimat LNG facility and possibly its Horn River and Liard Basin assets.
OIL & GAS INQUIRER • SEPTEMBER 2014
15
British Columbia
In mid-2012, Apache grabbed headlines across North America for its results on a prolific Liard shale validation well, but analysts noted that the resource would likely languish in the absence of a gas price revival or the construction of an LNG plant on British Columbia’s north coast. The company’s D-34-K horizontal well had a vertical depth of 12,600 feet and a lateral length of 2,900 feet with six frac stages. The 30-day initial production rate was 21.3 million cubic feet per day and 3.6 million cubic feet per day per frac, and the estimated ultimate recovery is 17.9 billion cubic feet. During its second-quarter earnings call, George Kirkland, vice-chair and executive vice-president of upstream with Chevron Corporation, said the company needs to “get [their] partnership resolved. “That means Apache needs to move through the issues, and we need to get a new partner in. That needs to happen; that’s, I think, quite obvious,” he said. “As long as we keep moving forward in the assessment of the resource in Liard, I feel very good about the resource assessment.”
The company, Kirkland added, said its confidence level at Horn River is high. “The focus on the resource side is really drilling in Liard, some appraisal work there and getting some production,” he said. “We think we’ll have those fi rst wells that we need to get some production data. We’re going to be complete with them somewhere near the end of the year, so that’s a really important step for us.” The other piece the company is spending money on with respect to Liard is its handling of initial production, the pipeline and pipeline corridor. “We’re putting some money into that to try to finalize a pipeline routing, get all our clearances,” Kirkland said. “And then we’ve got…some FEED [front-end engineering design] work on the LNG plant itself. We have to understand costs and schedule on that plant.” He estimated spending of “hundreds of millions.” “It’s critical for us to have all that, where we can deal knowledgeably with buyers. We have to understand costs, we
have to understand resource where we can deal with the particulars of pricing,” Kirkland said. “We’re not going to do a project unless it’s economic. We’ve always told you we’re not going to go to FID [fi nal investment decision] on a project until we have 60 per cent of the gas sold. “I think we could easily step in and be operator of the upstream,” he added. Kirkland said Chevron is not looking to increase its stake in the Kitimat LNG project above its current 50 per cent. “That’s right in the middle of the sweet spot where we like to be on working interest,” he noted. “I don’t want any more than the 50 per cent, and we do have available some small amount of working interest that we would provide to an LNG buyer. There’s always been a plan for us and Apache to have some volumes, some working interest, that could be sold down to buyers where they would be a part of the development, and they would be in the full value chain. “That has not changed, and I’m not looking to increase our working interest beyond the 50 per cent.”
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SEPTEMBER 2014 • OIL & GAS INQUIRER
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British Columbia
Pressure on to get LNG moving, says new report A new report by the University of Calgary’s School of Public Policy has criticized a proposed B.C. liquefied natural gas (LNG) tax, arguing it could negatively affect both “the cost of fi nancing and the ability to access the market in a timely fashion.” The report was released by The School of Public Policy at a press conference and business lunch in Vancouver. It provides an analysis of the overall business case for LNG export from British Columbia. The authors of the report—Michal C. Moore, Dave Hackett, Leigh Noda, Jennifer Winter, Roman Karski and Mark Pilche—
noted that the market for LNG is becoming increasingly crowded and competitive. “Producers around the world—including in the newly gas-rich U.S.—are racing to lock up market-share in the Asia-Pacific region, in many cases much more aggressively than Canada,” says the report. “While this market is robust and growing, the nature of the contracts for delivery will favour actors that are earliest in the queue…. As supply grows, so too does the likelihood of falling gas prices in the Asia-Pacific region, making later projects less lucrative.”
British Columbia LNG plant proposals Facility
Proponents
Capacity (bcf/d)
Aurora LNG
Nexen Energy, INPEX, JGC Exploration
3.12
BC LNG
LNG Partners, Haisla Nation
0.24
Kitimat LNG
Chevron Canada, Apache Canada
1.28
Kitsault Energy
Krishnan Suthanthiran
2.64
LNG Canada
Shell, KOGAS, Mitsubishi, PetroChina
3.23
Pacific NorthWest
PETRONAS, Japan Petroleum
2.74
Prince Rupert LNG
BG Group
2.91
Triton LNG
AltaGas Group, Idemitsu, Kosan Global
0.31
WCC LNG
ExxonMobil Canada, Imperial Oil
4
Woodfibre LNG
Woodfibre Natural Gas
Total
20.76
0.29 0
0.5
1
1.5
2
2.5
3
3.5
4
Source: Oilweek
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17
British Columbia
The authors also noted a troubling “lack of policy and regulatory coordination” in Canada. Disagreements between governments over standards, processes and compensation in the potential LNG industry are stalling the approval of projects, such as pipeline rights-of-way and agreements with First Nations. The authors reserved strong criticism for the B.C. government’s proposed LNG “special taxes,” arguing that they could very well kill the prospect of Canadian LNG export entirely. Unless Canada wants to be “shut out [of the LNG market], stuck relying on a single U.S. gas-export market that, increasingly, does not need us,” it has some serious work to do. — DAILy OIL BULLETIN
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SEPTEMBER 2014 • OIL & GAS INQUIRER
B.C. July land sale lowest of the year By Richard Macedo
The B.C. government attracted $3.07 million—the lowest earnings at a single auction this year—at its land sale on July 16. The provincial government sold 4,536 hectares this week, which produced an average price of $677.65, the second-lowest average price of the year. Through seven auctions, British Columbia has collected $92.94 million on 62,233 hectares at an average price of $1,493.48. Up to the same point in 2013, the industry had paid $133.85 million for 75,715 hectares at an average price of $1,767.75. Highlights of the July sale included a bonus bid high of $1.12 million. Standard Land Company Inc. paid an average of $1,010 for the 1,113-hectare licence. The broker acquired the rights to two tracts. The fi rst tract included units 76-79, 86-89, 98 and 99 at I-94-G-08 and units eight and nine at A-94-G-09. The second tract included units 54, 55, 64 and 65 at I-94-G-08. This 16-unit parcel, which includes all petroleum and natural gas (P&NG) rights (12 units) and P&NG rights below the Triassic Baldonnel (four units) is located at the northwestern corner of the Laprise Creek field. It is north of Saguaro Resources Ltd.’s horizontal drilling activity, noted Steve Hager, senior exploration analyst with Canadian Discovery Ltd. “Saguaro is a relatively new player in the Montney resource play,” he said. Buffalo Hill Resources Ltd., meanwhile, paid the land sale perhectare high price of $1,515 for a 279-hectare licence. The broker submitted a bonus of $422,685 for units 54, 55, 64 and 65 at F-94-H-05. Buffalo Hill picked up another 279-hectare licence for $403,155, which generated an average price of $1,445. The parcel included units 71 and 81 at F-94-H-05 and units 80 and 90 at G-94-H-05. These are located on the eastern side of the Laprise Creek field. The two four-unit parcels, which include all P&NG rights and P&NG rights below the Cretaceous, are off set by two horizontal Gething development locations recently licensed by Polar Star Canadian Oil and Gas Inc., and are on trend to the northwest of Progress Energy Canada Ltd.’s horizontal Montney locations at Nig Creek. All three parcels highlighted above posted deeper rights, including Montney, on the northeastern fringe of the Montney
British Columbia
development fairway, said Brad Hayes, president of Petrel Robertson Consulting Ltd. “This looks like part of the continued push outward for the Montney fairway as development potential is proven up along the edges,” he said.
Quicksilver files for LNG export licence Quicksilver Resources Canada Inc. has filed an export licence with the National Energy Board to send the chilled gas overseas from its planned Discovery LNG project on Vancouver Island, B.C., to points in Asia. The filing was made on July 28 and is for a 25-year term. Subject to the annual tolerance, the quantity of liquefied natural gas (LNG) that may be exported in any 12-month period shall not exceed 20 million tonnes per annum, which corresponds to a natural gas equivalent of roughly 960 billion cubic feet. The point of export of LNG from Canada will be at the outlet of the loading arm of the natural gas liquefaction facility located on the northern side of Campbell River, B.C. Quicksilver is investigating options to build and operate natural gas liquefaction, storage and on-loading facilities. The planned multi-billion dollar project will be designed to take delivery of gas, mainly from western Canada, and liquefy it for export to Asia. “Given the integrated nature of the North American gas markets and pipeline network, gas supply could also potentially come from other Canadian or North American basins over the life of the project,” the application stated. The contemplated project site, just north of the city of Campbell River, was formerly occupied by the Elk Falls mill owned by Catalyst Paper Corporation. As a result, the project would be built on an existing industrial site. The project is expected to provide facilities for natural gas liquefaction, LNG storage and carrier on-loading, and would be operated by a downstream partnership between the applicant and a third party that’s yet to be finalized. Quicksilver said the project is expected to include four liquefaction trains and LNG storage; a marine berth and related bulkhead, dock and mooring infrastructure to support docking and loading of LNG carriers; and shore-side facilities, including power supply, condensate storage, water supply and return, cooling water system, feed-gas pipeline, and metering and support buildings. The LNG production will be off-loaded through a loading arm to LNG carriers for transport to export markets. The volumes sought under the licence represent the capacity of the project at or near full build-out. Quicksilver is currently in the project feasibility phase. Subject to the completion of the feasibility study, consultations with aboriginal groups and local communities, regulatory approvals and facility construction, the proposed exports could begin as early as 2021. The full capacity volumes of 20 million tonnes per annum could be on stream as early as 2024. The company said it is currently working with potential jointventure partners.
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O I L & G A S I N Q U I R E R • S E P T E M B E R 2 0 113.08.14 4 19 08:50
NORTHWESTERN ALBERTA WELL ACTIVITY JUL/13
JUL/14
Wells licensed
JUL/13
JUL/14
Wells spudded
JUL/13
JUL/14
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Delphi cracks Montney using slickwater fracs
Photo: Aaron Parker
Delphi is using 30-stage fracs in the Montney.
Delphi Energy Corp. says slickwater hybrid fracturing has significantly improved well performance at Bigstone in northwestern Alberta, where it has completed and tested its eighth and ninth horizontal Montney wells using 30-stage slickwater hybrid completions, compared to smaller, conventional frac methods. The eighth and ninth horizontal Montney wells, the 08-21-060-22W5 (8-21) and 02-07060-22W5 (2-7), were drilled from a common surface pad. The 8-21 well was drilled to a total depth of 5,580 metres with a horizontal lateral length of 2,692 metres and stimulated with a 30-stage slickwater hybrid completion. The well was produced on cleanup over eight days, recovering about 45 per cent of the initial load frac water and was then shut in to equip and pipeline-connect the well for production. After running production tubing, the well produced, over the final 24 hours, an average of 4.9 million cubic feet per day of raw gas and 449 barrels per day of wellhead condensate (92 barrels per million cubic feet of raw gas). Total production for the 8-21 well over the final 24-hour period was approximately 1,347 barrels equivalent per day, with an estimated plant natural gas liquids
(NGL) yield of 36 barrels per million cubic feet of raw gas. Field condensate and plant NGLs represented 46 per cent of the total production. The 2-7 well was drilled to a total depth of 5,614 metres with a horizontal lateral length of 2,702 metres and stimulated with a 30-stage slickwater hybrid completion. The well was produced on cleanup over 5.5 days, recovering around 30 per cent of the initial load frac water and then shut in to equip and pipeline-connect the well for production. After running production tubing, the well produced, over the final 24 hours, an average of 9.5 million cubic per day of raw gas and 498 barrels per day of wellhead condensate (53 barrels per million cubic feet of raw gas). Total production for the 2-7 well over the final 24 hours was approximately 2,240 barrels equivalent per day, with an estimated plant NGL yield of 36 barrels per million cubic feet of raw gas. Field condensate and plant NGLs represented 37 per cent of the total production. Both wells are now on production and, consistent with the previous slickwater fracture stimulated wells, will continue to recover load frac water over the next few months. The company said slickwater hybrid frac technology has had a significant impact on well performance in comparison to smaller conventional frac methods. For instance, volumes in the 15-30 and 16-30 wells, approximately 400 metres (one spacing unit) apart, almost doubled during the initial 30 days of production. Longer term, production tripled after 180 days. Wellhead-condensate production and yields have also improved by two to three times. Longer term, the 10-27 well produced at an average rate of 1,019 barrels equivalent per day for the first year.
Output during the second quarter averaged approximately 10,200 barrels equivalent per day (based on field estimates), exceeding guidance of 9,500–10,000 barrels per day as a result of continued strong Montney well performance and less downtime from scheduled facility-maintenance outages. — DAILy OIL BULLETIN
Strategic announces early results of summer drilling Strategic Oil & Gas Ltd. announced its fi rst horizontal Muskeg well drilled after spring breakup, 11-24, produced at an average test rate of 545 barrels equivalent per day (77 per cent oil) over the first seven days. Costs to drill and complete the well were $3.9 million, down 25 per cent from the company’s average well costs in the play, Strategic said. Strategic began its summer drilling program on June 13 and has since drilled two wells and spudded a third. The company intends to drill a total of five to six horizontal Muskeg wells as a part of its 2014 capital program. Strategic is encouraged by its recent success in this program and reaffirms its 2014 exit production guidance of 4,000 barrels equivalent per day. “We remain focused on proving up the Muskeg at Marlowe. With more than 100 sections with Muskeg potential identified to date, the company is positioned with a multi-year drilling inventory of more than 400 economic prospects,” president and chief executive officer Gurpreet Sawhney said in a news release. “As with any new resource play, we continue to move along the learning curve identifying opportunities to drive efficiencies, grow returns and increase well performance. We have built the necessary production infrastructure OIL & GAS INQUIRER • SEPTEMBER 2014
21
Northwestern Alberta
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to handle our expanding drilling program, enabling us to connect a well within days of completion, which results in shorter payback on our invested capital.” The Muskeg 11-24 well was drilled and completed with a 13-stage frac and was the fi rst well drilled on the western rim at Marlowe after breakup. Over the first seven days, the well produced an average of 420 barrels a day of 37-degree-API oil and 75 thousand cubic feet per day of raw solution gas or an oil equivalent rate of 545 barrels a day. The well was tied in to Strategic’s production infrastructure after a five-day test. By comparison, the previous Muskeg 10-24 well was drilled and completed with a 15-stage frac before spring breakup. Average production rates over the first 30 and 90 days were 560 and 420 barrels equivalent per day, respectively. This well has produced 38,600 barrels equivalent (60 per cent oil) in three months and continues to outperform Strategic’s pre-drill estimates, the company said. Strategic has significantly decreased drilling days and other associated well costs. The Muskeg horizontal well 11-24 was drilled in 22 days, a decrease of seven days from the wells drilled in the first quarter of 2014. The company drilled the 11-24 well for $3.9 million, a reduction of over $1 million from the average cost of the wells drilled during the first quarter of 2014. Muskeg horizontal well 2-26, the second well drilled after breakup, was drilled in 15 days, 14 days less than the wells drilled in the fi rst quarter of 2014. The well is scheduled to be completed with a 14-stage frac. — DAILy OIL BULLETIN
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SEPTEMBER 2014 • OIL & GAS INQUIRER
Yoho finding Duvernay success at Kaybob Yoho Resources Inc. operated the drilling and completion of one well, and participated in the drilling and completion of a second well in the company’s Duvernay program at Kaybob, the company reported in late July.
Northwestern Alberta
T he f irst well, located at 16 - 04 062-21W5 (50 per cent working interest), was drilled to a measured depth of 4,740 metres. The horizontal lateral is roughly 1,300 metres in length within t he Duver nay sha le for mat ion. T he well was drilled and cased at a cost of approximately $5 million. The well was subsequently fracture stimulated, the pumpdown bridge plugs were drilled out with a coiled tubing unit, production tubing was snubbed in and a f low test was conducted. The total gross estimated cost of the completion is roughly $7 million, bringing the total gross estimated cost to drill, complete and test the well to $12 million. During initial cleanup conducted upcasing, the 16-04 well flowed at rates up to 4.6 million cubic feet per day (roughly 1,200 barrels equivalent per day including condensate and natural gas liquids). The well was also flowing completion fluid at rates of 60–120 barrels per hour. At the end of the 117-hour total flow period, the well was producing up-tubing at a restricted rate of 2.5 million cubic feet per day (approximately 670 barrels equivalent per day including condensate and natural gas liquids) at flowing tubing pressures of 8,500 kilopascals and casing pressure of 19,800 kilopascals. In addition to the natural gas production at the end of the flow period, the well was producing fi eld condensate at a rate of 230 barrels per day or 92 barrels of field condensate per million cubic feet of raw gas. The second well, located at 16-02-06019W5 (33.33 per cent working interest) and operated by a third party, was drilled to a measured depth of 4,710 metres. The horizontal lateral was roughly 1,300 metres in length within the Duvernay shale formation. The well was drilled and cased at a cost of roughly $5 million. During initial cleanup, the 16 - 02 well f lowed at rates up-tubing of up to 3.6 million cubic feet per day (roughly 900 barrels equivalent per day including condensate and natural gas liquids). In addition to the natural gas production during the f low period, the well was producing field condensate at rates of up to 300 barrels per day or 83 barrels of field condensate per million cubic feet of raw gas.
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23
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NORTHEASTERN ALBERTA WELL ACTIVITY JUL/13
JUL/14
Wells licensed
JUL/13
JUL/14
Wells spudded
JUL/13
JUL/14
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
N.E.
Northeastern Alberta
MEG reports record volumes
Photo: Joey Podlubny
By Paul Wells
MEG Energy Corp. enjoyed a stellar second quarter as it reported record production and funds flow from operations during the period. Bill McCaff rey, president, chief executive officer and director, said at the company’s second-quarter conference call that while MEG is focused on long-term growth, the strong results are noteworthy as the Christina Lake project continues to perform well. “When building a strategy that is fundamentally about long-term value, you try not to get caught up in any individual quarter. However, this quarter might be an exception. During this quarter, we saw record production of nearly 69,000 barrels per day, all while undertaking the planned maintenance for Phases 1 and 2,” he said. “This record level of production was supported to a large degree by Phase 2B, which reached design capacity in just seven months. As a result of this strong performance, we are now increasing our 2014 production guidance by eight per cent,” he added. “We are looking to a strong second half and have raised our production guidance to 65,000–70,000 barrels per day for the year.” Second-quar ter out put increased nearly 115 per cent to 68,984 barrels per day, compared to second-quarter 2013 production of 32,144 barrels per day. The increase in production volumes in the second quarter of 2014 compared to the same period in 2013 is due to the start-up of Christina Lake Phase 2B and the implementation of RISER on Christina Lake Phases 1 and 2. The implementation of the RISER initiative within Phases 1 and 2 has expanded the steam generation capacity and improved reservoir efficiency, thereby
MEG production could average 70,000 barrels per day by year-end.
enabling the company to place additional wells into production. MEG achieved first production from Phase 2B in the fourth quarter of 2013. As a result of the successful ramp-up of Phase 2B, in combination with the success achieved from applying RISER to Phases 1 and 2, the company anticipates reaching a near-term production target from Christina Lake Phases 1, 2 and 2B of 80,000 barrels per day by 2015. The company’s average steam to oil ratio (SOR) was 2.4 for the three months ended June 30, 2014, compared to an SOR of 2.3 for the same period last year. The SOR averaged 2.4 during the six months ended June 30, 2014, and June 30, 2013. The average SOR in the first half of 2014 has decreased from an SOR of 2.9 for
the fourth quarter of 2013, as more Phase 2B well pairs have been converted from steam circulation to production. Average bitumen price realizations increased approximately 17 per cent in the second quarter of 2014 compared to the previous quarter, and were approximately 35 per cent higher than price realizations in the second quarter of 2013. McCaff rey said that continued logistics enhancements, including increased crudeby-rail transportation, pipelines connecting the U.S. mid-continent to the U.S. Gulf Coast and refinery modifications in the U.S. Midwest contributed to improved pricing. The anticipated completion of the Flanagan South Pipeline and the Seaway Pipeline in the second half of 2014 is expected to further enhance transportation logistics and pricing. Funds f low from operations in the second quarter of 2014 reached a record $261.71 million compared to $79.18 million for the same period in 2013. The increase in cash flow from operations was primarily due to higher production volumes and increased netbacks per barrel. “Exceptional operating performance and higher realized pricing drove record cash flow in the quarter,” McCaff rey said. “This step-change in our cash flow represents the beginning of a new chapter for MEG. Internal cash flow is now poised to be the major contributor to our future capital funding plans, with this past quarter being an important milestone.” MEG turned a second quarter profit of $248.95 million versus a loss of $62.31 million during the prior-year period. Year-todate earnings increased to $145.51 million from a loss of $133.61 million during the first half of last year. McCaffrey said that MEG’s next phase of production growth will be primarily driven by the application of RISER on Phase 2B. RISER 2B includes the application of a combi nat ion of propr ietar y reser voir OIL & GAS INQUIRER • SEPTEMBER 2014
25
Northeastern Alberta
technologies, redeployment of steam and a major brownfield expansion of the existing Phase 2B facilities. Using the results of recent production testing of the Phase 2B facility, the company is in the early stages of designing a series of brownfield expansions of Phase 2B. Given the attractiveness of this strategy, MEG has prioritized RISER 2B ahead of its next greenfield expansion. The company has also filed regulatory applications for the Surmont project. Surmont, which is situated along the same geological trend as Christina Lake, has an
anticipated design capacity of approximately 120,000 barrels per day over multiple phases. MEG also holds a 50 per cent interest in the Access Pipeline, a strategic dual pipeline system that connects the Christina Lake project to a large regional upgrading, refining, diluent supply and transportation hub around Edmonton. The Access Pipeline currently has a gross capacity of approximately 260,000 barrels per day of blended bitumen and approximately 140,000 barrels per day of condensate.
The company is currently undertaking the expansion of the Access Pipeline, which includes the construction of a 42-inch blend line from Christina Lake to Sturgeon to accommodate anticipated increases in production and prov ide expansion capacity for future production volumes that are expected to be produced from the Christina Lake project, the Surmont project and MEG’s growth properties. The initial capacity of the expanded 42-inch blend line will be approximately 400,000 barrels per day of blended bitumen.
Oilsands projects getting more expensive, says CERI By Lynda Harrison
The supply cost for oilsands producers rose last year—by 4.4 per cent for a steam assisted gravity drainage (SAGD) producer, 1.6 per cent for a stand-alone mine and 5.9 per cent for an integrated mining and upgrading project—according to a new Canadian Energy Research Institute (CERI) report.
CER I is seeing continuous escalation of prices, and that’s what worries both producers and the government, said Dinara Millington, vice-president of research and principal author of the report that loosely compares field gate costs from CERI’s 2013 update with this
year’s supply costs after adjusting for inflation. “Producers can’t lock in this increase, this escalation of cost inflation, and this is driven by various factors,” she told the Daily Oil Bulletin, suggesting that the complexity of oilsands projects places their costs about
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SEPTEMBER 2014 • OIL & GAS INQUIRER
Northeastern Alberta
one and a half to two times higher than comparable projects in the Gulf of Mexico. Supply costs in the study are calculated using an annual discount rate of 10 per cent (real), which is equivalent to an annual return on investment of 12.5 per cent (nominal) based on the assumed inflation rate of 2.5 per cent per annum. Based on these assumptions, the supply costs of crude bitumen using SAGD, surface mining and extraction, integrated mining and upgrading, and a stand-alone upgrader have been calculated for a hypothetical project. According to CERI, the plant gate supply costs, which exclude transportation and blending costs, are $50.89 per barrel for SAGD, $71.81 per barrel for a stand-alone mine, $107.57 per barrel for integrated mining and upgrading, and $40.82 per barrel for a stand-alone upgrader. A f ter adjust i ng for blendi ng a nd t ra nspor tat ion, t he West Texas Intermediate (WTI) equivalent supply costs at Cushing, Okla., are US$84.99 per barrel for SAGD projects, US$105.54 per barrel for a stand-alone mine, US$109.50
per barrel for integrated mining and upgrading, and US$41.44 per barrel for a stand-alone upgrader. CERI defines supply cost as the constant dollar price needed to recover all capital expenditures, operating costs, royalties and taxes, and earn a specified return on investment. At WTI prices of US$100 per barrel, the only project that would be economic is a SAGD in situ project, which is consistent with oilsands projects currently being developed, Millington wrote. The greenfield projects, being built are mostly in situ projects, while the mines and integrated mines being developed are expansions of existing projects, and this can provide some cost savings and economies of scale. The report is CERI’s ninth annual edition of its long-term outlook for Canadian oilsands production and supply and examination of oilsands supply costs. As in previous versions, several scenarios for oilsands developments are explored. In the high-case scenario, production from mining and in situ thermal and
solvent extraction (excluding primary recovery) is set to grow from 1.9 million barrels per day in 2013 to 3.8 million barrels per day by 2020 and 5.7 million barrels per day by 2048.
“The problem with solvents, what they’ve been finding, is the lab results are great; the field results are not so great.” — Dinara Millington, vice-president of research, Canadian Energy Research Institute
In the low-case scenario, production rises to 4.2 million barrels per day by 2030 and 4.3 million barrels per day by the end of the 2048 forecast period. CERI’s reference-case scenario, which provides a more plausible view of oilsands
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production, projects volumes will increase to 3.4 million barrels per day by 2020 and 4.8 million barrels per day in 2048. Cold bitumen production from primary and enhanced oil recovery wells is forecast to increase from 270,000 barrels per day in 2013 to a peak of 350,000 barrels per day by 2020 and then slowly taper off to just above 200,000 barrels per day by the end of the forecast period. In each of the three scenarios, the annual sustaining capital required for the oilsands (excluding royalty revenues, taxes, and fixed and variable operating costs) exceeds $6 billion by 2048. The reference-case scenario projection shows an annual investment of $9.2 billion in 2048 and is estimated to average $8.7 billion over the projection period. While capital costs and the return on investment account for a substantial portion of the total supply cost, the province of Alberta stands to gain $9.40 to $13.60 on average in royalty revenues for each barrel of oil produced, over the life of an oilsands project. Under the high-case scenario, the sustaining costs reach an all-time high of $10.7 billion in 2048, averaging $9.9 billion over the 35-year window. In the lowcase scenario, $8.2 billion will be spent on sustaining costs in 2046, with an average of $7.5 billion over the projection period. The amount of natural gas required to sustain the oilsands industry is substantial, said CERI. CERI projects that by 2048, natural gas requirements will be two to three times the current levels. Given its robust production projection, natural gas use is estimated to rise from 1.47 billion cubic feet per day in 2013 to 3.75 billion cubic feet per day in 2046 under the high-case scenario, to 3.17 billion cubic feet per day in the reference-case scenario and to 2.87 billion cubic feet per day under the low-case scenario. This year’s forecast of natural gas demand is 0.5 per cent lower overall for the reference-case scenario. Though not a significant change, there are substantial prospects for technology to improve in efficiency and to use less natural gas, said CERI. In its yearly study, CERI considered the list of available technologies and it believes the current alternative to using natural gas in SAGD is solvents, said Millington. “The problem with solvents, what they’ve been fi nding, is the lab results are
Northeastern Alberta
great; the field results are not so great,” she said. “The recovery of solvent is not as high as the lab results promised and the cost of solvent itself is very prohibitive, and given how cheap natural gas currently is, there’s a sort of, I guess, delay in switching the technology.” According to CERI, production and capital investment forecasts for the oilsands industry are estimated to continue to increase well into the future, and there are some major projects still to be constructed, but currently many producers are reporting a bit of a backlog and a pause in new contract awards. However, this may be a function of the change of the pace of development more than an indication of downward pressure on the sector, it said. The nature of new project development in the oilsands has changed, CERI noted. Ten years ago, the industry was dominated by megaproject mines and upgraders, each
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built by several thousand people; the sector is now transforming into more manageable phased in situ growth, said Millington. Although there are uncertainties around market access and competition from U.S. tight oil projects, oilsands production is expected to reach three million barrels per day around 2017. This means the industry is expected to add approximately one million barrels per day of production in less than five years, from both mining and in situ operations, says the report. In addition to several in situ projects and phases currently underway or expected to get the necessary approvals in the near term, the study considered at least three mining projects for major growth. This included the 100,000-barrel-perday second phase at Kearl, which is under construction, the staged integrated mining and upgrading expansion to 250,000 barrels per day at Horizon, and the longawaited 190,000-barrel-per-day greenfield installation at Fort Hills.
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CENTRAL ALBERTA WELL ACTIVITY JUL/13
JUL/14
Wells licensed
JUL/13
JUL/14
Wells spudded
JUL/13
JUL/14
Rigs released
▲
▲
▼
Source: Daily Oil Bulletin
C.A.B. Central Alberta
Photo: Aaron Parker
Penn West planning 83 light oil wells in third quarter Penn West Petroleum Ltd. said it plans to spend $215 million in the third quarter of 2014 to spud 83 light oil development wells and put 52 on production. The quarter is the first in which it plans to increase development activities in the Cardium and Viking formations, and the goal is to do so while maintaining the competitive cost and cycle-time measures it has achieved in its core areas over the past six months, said the company in its production update for the second quarter of 2014. Production in the quarter averaged 108,130 barrels equivalent per day (64 per cent oil and natural gas liquids). Net production averaged 105,702 barrels equivalent per day after adjustments resulting primarily from closing amendments on asset divestitures completed earlier in the year. “Our solid second-quarter production reflects a significant improvement in the reliability of our base volumes and continued strong development in our core light oil areas,” David Roberts, president and chief executive officer, said in a news release. “We remain confident that we are on track to deliver on 2014 production guidance, and we continue to build on the substantial operational and structural improvements we have made to the business in the past year.” Penn West maintained its production guidance of 101,000 –106,000 barrels equivalent per day for the year. “Improving cycle times and increasing pace in our core areas remain our key focus for the remainder of 2014,” said Roberts. “Looking beyond 2014, we continue to create processes that streamline our drilling inventory build-out from idea generation to ready-to-drill. We now have our 2015 development plan largely in place and expect to have our 2016 drilling inventory plans completed by year-end 2014.” The Cardium will attract the largest share of development capital in the third
the Viking, one (one net) was drilled in the quarter of 2014 with $87 million allocated for 24 wells to be spudded and seven put on Cardium and one (one net) in the Slave Point. production. Taking advantage of favourable weather In the Viking, plans call for $64 million conditions in the field, Penn West said it to be spent on spudding 45 wells and putkicked off its development program for the ting 40 on production. Another $44 million second half of 2014 early in July with eight will be spent on spudding seven Slave Point rigs currently operating in its light oil areas. wells and putting five on production. Management said the company remains The company has also budgeted $20 milon track to complete the planned 210-well lion to spud an additional eight wells, with development program for 2014. none planned to go on production this quarter. Penn West has reduced the number of Development activities for the third quardays to drill a Cardium well from 22 to ter, and in particular production activity, eight days on average, which it said it are weighted toward September, in which believes is the best among its competitors 31 of the 52 planned wells are expected to be tied in, said the company. Consequently, its drilling and completion efforts early in the third quarter will have a greater impact on fourth-quarter production volumes than on third-quarter production volumes, it said. Operations were l i m ited du r i ng t he second quarter of 2014 due to spring breakup, allowing it to further assess per for mance from the first-quarter drilling program and eva luate addit iona l opportunities to continue reductions in cost structures and cycle times, said Penn West. The company drilled 10 (10 net) light oil wells with a success rate of 100 per cent. Of the 10, eight (eight net) Penn West has reduced the number of days to drill a Cardium well from wells were drilled in 22 to eight days on average. OIL & GAS INQUIRER • SEPTEMBER 2014
31
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SEPTEMBER 2014 • OIL & GAS INQUIRER
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in the play. The drilling program in the second half of 2014 will feature more multiwell pads that will provide cost efficiencies and drive incremental cost savings. In the second quarter of 2014, Penn West secured operatorship of the Pembina Cardium unit number 11 in the Pembina field, which it believes has significant potential for the company. This is a substantial field in the Cardium that has not had any meaningful capital investment over the past several years, the company noted. Penn West is currently in the process of completing a technical evaluation of the unit and expects to have an initial six-well development program beginning in 2015. In July 2014, the company began a 30-well program in the Willesden Green area and is currently operating three drilling rigs. The development plan for the second half of 2014 adds a fourth drilling rig in August and a fi fth rig in October to complete all drilling activity for the year. In the Pembina area, activities for the second half of 2014 are planned in the Lodgepole and Pembina Cardium unit number 9 areas. Drilling activity began on a seven-well program in Lodgepole with one rig in July. Once completed, the rig is scheduled to move to Pembina Cardium unit number 9 to begin a nine-well program later in the year. Waterflood activities are scheduled to continue in Willesden Green and Pembina during the second half of 2014 as Penn West continues to assess the expansion of its waterflood program in 2015. Generally, the progress of waterflood programs throughout the Cardium area is consistent with the company’s long-term plan, and the programs are performing as expected, it said. Over time, Penn West expects these programs will have the potential to mitigate natural declines and increase the ultimate recovery of light oil resource in its Cardium areas. During the second quarter of 2014, the company drilled eight wells in the Viking as it continued to benefit from what it believes is its industry-leading operational results in the area. Penn West plans 100 Viking wells in the second half of this year with approximately 75 wells scheduled to be on production by the end of the year. In southwestern Saskatchewan, recent wet weather has caused a minor delay in the Viking program, where the company currently has two rigs operating.
Central Alberta
Leveraging the positive results of a 16-well-per-section down-spacing program earlier in the year, Penn West will continue to test down-spacing programs across the play. As the largest acreage holder in the core of the Viking play, an expanded down-spacing program would significantly increase the existing 400–500 drilling locations it has estimated, said Penn West. In its program for the second half of the year, the company said it also plans to reduce its cost per well to below $800,000 from what it believes to already be a bestin-class cost of $840,000. Penn West said it continues to test various drilling and completions techniques in the Slave Point carbonates as it focuses on optimizing production performance, recoveries, cycle times and per-well costs. Throughout the second quarter of 2014, it continued to monitor the results of the drilling program from earlier in the year. At Otter, production performance on the company’s first 3,200-metre long-reach lateral wells is in line with expectations, and Penn West is now monitoring these wells for longer-term performance before broader implementation of the design. In the Red Earth area, the two wells drilled in the first quarter of 2014 continue to perform above its expectations, said the company. At Sawn Lake, Penn West’s fi rst nitrogen fracture wells experienced average 30-day initial production rates that significantly exceeded the type curve. As at Otter, Penn West is monitoring the wells for longer-term performance. Development activities in the second half of 2014 in the Slave Point include a selective seven-well drilling program, which began in July 2014 with fi ve wells anticipated to be on production by the end of 2014. The goal of the program is to continue to assess each of the areas within the Slave Point, testing various drilling and completions techniques. To be competitive internally, per-well drilling and completions costs need to be $4.5 million or lower, said Penn West, noting that average per-well drilling and completions costs in its Slave Point program are running in the $5.1-million range. The company said it believes the required 12 per cent reduction in costs is achievable and that the Slave Point will be a significant component of its development program in future years.
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SOUTHERN ALBERTA WELL ACTIVITY JUL/13
JUL/14
Wells licensed
JUL/13
JUL/14
Wells spudded
JUL/13
JUL/14
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
Pine Cliff buys shallow gas assets from Nexen for $100 million By Paul Wells
Photo: Joey Podlubny
The Nexen assets bought by Pine Cliff are producing around 5,300 barrels equivalent per day, all natural gas.
Pine Cliff Energy Ltd. has struck a deal with Nexen Energy ULC to acquire shallow natural gas assets in Alberta and southern Saskatchewan for $100 million, prior to any adjustments. The majority of the Alberta assets are located east of Medicine Hat with some minor assets in central Alberta near Wetaskiwin. The Saskatchewan assets are located near the town of Maple Creek. “Additional approvals and negotiations for the assets are required prior to close, which is expected in early November,” Nexen spokeswoman Diane Kossman confirmed in an email. Nexen is a subsidiary of CNOOC Limited. Although natural gas prices have remained relatively strong in recent months and the forward strip is in the $4.50-per-thousand-cubic-feet range, executive chairman George Fink said that Pine
Cliff is not focused on a short-term boost in production and cash flow but is taking a long-term view of the acquired asset base. “First off, we always look at, say, over a five-year period—we really don’t sweat it too much as to what’s currently happening. We look at it more long-term to start with, and right now we look at gas prices being higher than $4 more often than lower than $4 over the next five years. So it really does work out pretty well,” he said. In determining the metrics of the deal, Fink said the company and its adviser used a gas price of $4.55 per thousand cubic feet “because that’s what the forward strip is right now.” However, even at a natural gas price in the $4-per-thousand-cubic-feet range, he said the acquisition still makes good business sense. “In hindsight, we probably should have picked our own number, which would be
that $4-per-thousand-cubic-feet mark. But even if you go to $4, it’s still very good from the standpoint of a lot of metrics for us,” Fink said. The cash consideration to be paid by Pine Cliff is expected to be fi nanced by a combination of working capital and debt, details of which will be subsequently announced. The proposed transaction will have an effective date of July 1, 2014, and is presently expected to close on or before Nov. 1, 2014. Although the agreement is binding between the parties, completion of the deal is subject to numerous conditions, including negotiation and execution of definitive agreements, due diligence, title and environmental review, and board of directors and regulatory approvals. The assets possess a predictable production profile, long reserve life and a geographically focused asset base that is 100 per cent weighted to natural gas. The assets are 85 per cent operated, high workinginterest properties (averaging 93 per cent) and include ownership in key strategic infrastructure. Production (May 2014 average provided by vendor) is currently 5,300 barrels equivalent per day (100 per cent natural gas). The assets have proved reserves of 10.7 million barrels equivalent and proved-plusprobable reserves of 15.5 million barrels equivalent. Because the assets to be acquired were non-core for the senior producer, Fink said “this property has had a lot of neglect” over the past few years. “So we can’t obviously guarantee that we can do some things pretty quickly to change the production levels, but internally we feel pretty strongly that we can.” Fink said Pine Cliff will assess the current production as best it can before determining its short-term plan. “We’ll see what wells need to be swabbed—something as simple as that. If OIL & GAS INQUIRER • SEPTEMBER 2014
35
Southern Alberta
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SEPTEMBER 2014 • OIL & GAS INQUIRER
they’ve got water in the casing, we will certainly swab, and that generally increases production,” Fink said. He noted that because of flooding in the area in 2010, some wells have been shut in and could soon be reactivated. “You’re certainly going to get some flush production when they’ve been shut in for that length of time. When they were shut in, obviously the water from the flooding was a lot higher, and a lot of that has now evaporated,” Fink said. “So it’s pretty easy to turn them on.”
Greater sage grouse saga continues By CARTER HAYDU
The Federal Court of Canada has ruled that a judicial review of an emergency protection order for the greater sage grouse can proceed. The court denied a federal government motion that would have limited the ability of the City of Medicine Hat and LGX Oil + Gas Inc. to present arguments related to the review. In January 2014, the city and LGX filed a Notice of Application for a judicial review related to the protection order, which came into effect in February. The order is the first emergency order under the federal government’s Species at Risk Act. It includes measures such as prohibitions on equipment higher than a barbed wire fence in the Manyberries oilfield of southeastern Alberta in which LGX and the city have partnered. “What we are really trying to do is get the federal environment department to work with us, because we feel that ultimately we have the same objectives in mind, and that is to see this species preserved,” Medicine Hat Councillor Bill Cocks, chairman of the city’s energy committee, said. “Nobody wants to be the author of the demise of a species.” He said the city is pleased with the court’s ruling, as he believes the “right to be heard” is a concern for all stakeholders. Prior to the emergency protection order, he said, the city was taking several steps toward protecting the sage grouse, which he believes would be better achieved without the federal order. “We have long had a sensitivity and awareness for and to the delicate balance that would have to be maintained in that area. It’s very dry, it’s strictly sagebrush and prairie grass, and there are impacts of human civilization on that topography—we recognize that, and we were trying to minimize that. Is the federal government telling us that we must abandon ship and just shut down the whole operation?” Cocks said the city and LGX were working with Alberta Environment prior to the emergency protection order, closing wells, moving roads and trying to minimize impacts on the landscape for the sage grouse as much as possible. With the federal order, though, he said it is uncertain whether some of those efforts are legally permissible. “We are really required to not do a lot of things out there, and so one of the things we really wanted to do was talk to the federal department,” he said, adding that there are questions as to
Southern Alberta
whether such actions as moving equipment and consolidating storage would be allowed. “However, we just haven’t been able to get any two-way conversation going.” The city and LGX will now begin to undertake the legal work for the judicial review. Cocks said he does not know when the case might go before the court. Cliff Wallis, vice-president of the Alberta Wilderness Association, said that his organization would likely participate in any legal proceedings as “friends of the court” on the side of the federal government. He said it is unfortunate the city and LGX are challenging the whole notion of federal government responsibility and jurisdiction regarding sage grouse protection. “I just see this as a waste of shareholders’ money, and taxpayers’ money in the case of the City of Medicine Hat, by going after this when they could be productive going out into the field and doing things for sage grouse, but that is their decision.” However, Cocks said the city would be seeking compensation for its financial losses resulting from the federal government’s actions that have affected its investment in the oilfield.
“Our initial investment in that oilfield, I believe, was in excess of $40 million. That’s not just
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pocket change.” — Bill Cocks, Medicine Hat Councillor
“Our initial investment in that oilfield, I believe, was in excess of $40 million. That’s not just pocket change. We made an investment, we saw a potential return on that investment by operating that field in partnership with LGX, and now the whole operation of that field is placed in some doubt. “Our investment in that oilfield is in jeopardy, and we didn’t buy it to create parkland. We bought it as a working oilfield, and so we need to know what is going to happen to our initial investment.” According to the federal environment department, the greater sage grouse depends on the unique prairie ecosystem of southeastern Alberta and southwestern Saskatchewan. Its population has declined by nearly 98 per cent since 1988 and there are fewer than 150 birds now remaining in Canada. The intent of the federal order is to impose obligatory restrictions designed to protect the sage grouse and its habitat on provincial and federal Crown lands in Alberta and Saskatchewan. There are no restrictions on activities on private land, nor are there restrictions regarding grazing on provincial or federal Crown lands. South of the 49th parallel, other jurisdictions are also grappling with the best ways of protecting greater sage grouse within their borders in light of energy-sector development. For example, in Wyoming, which houses approximately 37 per cent of remaining sage grouse, the state government instituted a conservation strategy based on the designation and management of large areas of core habitat.
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Conference Focusing on innovation, expertise, business and technology, the Canadian Heavy Oil Conference will build your knowledge and network in Canada’s growing heavy oil and oilsands industry. Concurrent sessions will feature presentations on the following topics:
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Surface – Facilities and Upgrading
Subsurface
Business, Economics and Issues
Treatment and steam generation, partial upgrading and project execution.
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S.K.
SASKATCHEWAN WELL ACTIVITY JUL/13
JUL/14
Wells licensed
JUL/13
JUL/14
Wells spudded
JUL/13
JUL/14
Rigs released
▼
▼
Saskatchewan
▼
Source: Daily Oil Bulletin
Surge Shaunavon drilling success continues Surge Energy Inc. reported record production and operating netbacks of $54 per barrel equivalent in the second quarter. During the quarter, the company increased its oil and natural gas liquids production weighting to 87 per cent from 74 per cent in the same period last year. Oil and natural gas liquids (NGL) production accounted for about 95 per cent of Surge’s revenue in the second quarter of 2014. Based on continued development drilling success across its asset base, Surge said its 2014 production exit rate of 21,350 barrels equivalent per day is being maintained. In the second quarter, Surge had betterthan-anticipated development drilling results, drilling seven (4.6 net) wells, with reduced drilling activity levels relating to normal spring breakup conditions. This successful drilling program consisted of two (two net) Upper Shaunavon development wells, one (one net) well at Valhalla, one (one net) Sparky well at Provost and three (0.6 net) Viking wells as part of Surge’s strategic farmout of exploration lands in this area. Production from only one (one net) well was included in the quarter, with six wells (3.6 net) to be brought on in the third quarter. As a follow-up to Surge’s successful firstquarter Upper Shaunavon discovery well at 191/16-36-005-19W3, the company drilled two additional step-out Upper Shaunavon wells (100 per cent working interest) in the second quarter. These successful new wells were drilled off a pad about 400 metres west of the initial discovery well. Surge said both wells encountered excellent reservoir throughout the Upper Shaunavon. The first well extended the width of the fairway a mile to the south of the discovery well. The second well was a
direct off set to the discovery well, and its original reservoir pressure did not indicate any depletion as a result of the production from the discovery well, which has cumulative production to date of over 33,000 barrels. These two new wells were brought on production in mid-July and are currently each producing more than 325 barrels of oil per day with low water cuts. Mea nwh i le, t he or ig i na l Upp e r Shaunavon discovery well is still producing about 300 barrels of oil per day at a low water cut after 4.5 months, Surge said. It said this well’s netbacks exceed $65 a barrel, and it paid out in less than 100 days. The company now believes this discovery contains more original oil in place than the 125 million net barrels announced on April 8 and is updating its estimate. The company now expects there will be more than 64 net additional drilling locations on this large, medium-gravity, conventional sandstone oil pool. Surge plans to drill up to six more Upper Shaunavon wells before the end of the year—two in the third quarter, stepping out from the previous drills to expand the current trend, and up to four in the fourth quarter, including a significant step-out well on a separate trend that has been identified using the same geophysical parameters as the ones used to drill on the current successful trend. Also at its Shaunavon property, the company brought on production four (three net) Lower Shaunavon wells in the second quarter that were drilled in the first quarter. These wells have now been optimized for production and are exceeding average type curve expectations.
Macoun-Midale Early in the third quarter, Surge completed a frac of an existing horizontal light oil well in the Midale Formation in southeastern Saskatchewan. The well was open-hole stimulated using an inflatable straddle assembly with six fracs at three tonnes per stage on July 11. The company reported “excellent” initial inflow and expects this well to stabilize at nearly three times the pre-stimulation production rate of 38 barrels of oil per day. Surge plans to drill three more Midale wells prior to the end of the year—two in the third quarter and one in the fourth quarter, stepping out from the previous locations to expand the current Midale trend. The company also plans to optimize the Midale waterflood by adding source water and converting one or two wells to injectors. Late in the second quarter, Surge hydraulically fractured an existing Midale well at 13-16. Due to wet weather in the Pinto area, this well did not come on production until July 10. Surge intends to drill two more wells before the end of the year within the current Midale trend. At the Viking play, the farm-in operator on Surge’s land drilled three (0.6 net) wells late in the second quarter. Two of these wells were completed and brought on production in July. Subsequent to the second quarter, the operator successfully rig released six (1.2 net) wells. Surge anticipates having a further 12 (2.4 net) Viking farm-in wells drilled and on production in the third quarter. Surge expects to have more than 75 per cent of its producing assets under waterflood by year’s end. The company said the waterf lood pilots are integral to its strategy of increasing recovery factors across its oil portfolio—lowering corporate decline rates, continuing to improve sustainability and maximizing shareholder value. OIL & GAS INQUIRER • SEPTEMBER 2014
39
Cover Feature 4
3
2
5
1
14
33
15 29
16 27
34
7 8
35 30
28 25 26 24
6
CONNECTING
THE DOTS SAGD operators combine technologies, strategies to wring out more value from reservoirs
19
10
13 9
23
By Darrell Stonehouse with notes from the Daily Oil Bulletin
20
11
21
18
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17 12
hermal oilsands operators are combining a variety of technologies—including infill drilling, multilateral wells, co-injection of methane or solvent with steam, and new flow-control devices—in an effort to cut operating costs and capture more resources from bitumen deposits in northeastern Alberta. The introduction of the new technologies is already showing results at a number of the more mature developments like MEG Energy Corp.’s Christina Lake operations and Cevonus Energy Inc.’s Foster Creek complex. Other companies, like Statoil Canada Ltd., are looking to implement many of these new processes upfront early on in the development phase of operations. MEG calls enhanced recovery efforts at its Christina Lake operations its RISER initiative. RISER largely consists of using a combination of infill drilling and methane coinjection to cut the steam to oil ratio at its operations while capturing more resource through infill drilling. The company calls its co-injection scheme enhanced modified steam and gas push (eMSAGP).
40
SEPTEMBER 2014 • OIL & GAS INQUIRER
“It’s a technology we talked about at the [annual general meeting] last year. It was fairly new at the time, but we’re seeing some exciting results,” Bill McCaff rey, president and chief executive officer, told shareholders in May at the company’s annual meeting for 2014. MEG fi rst piloted co-injection of natural gas with steam on three steam assisted gravity drainage (SAGD) well pairs at Phase 1 of its Christina Lake project starting in January 2012. In addition to the pilot pad, which has been in operation since early 2012, MEG added eMSAGP to three other well pads last year. “And throughout 2013, because of the results we saw, we expanded the use of eMSAGP across the entire Phase 1 and 2 field operations at Christina Lake,” McCaff rey said. “And to date, we’ve seen some very compelling results. The steam to oil ratio is now sub-two in the patterns eMSAGP was implemented on. “And as a result, Phase 1 and 2 are now producing nearly 40,000 barrels a day, which is about 60 per cent above the initial design capacity of the plant,” he said.
MEG’s approach to natural gas coinjection with steam differs from the typical industry practice in two ways. One is that MEG uses gas co-injection in conjunction with infill wells. The second difference is it begins co-injection earlier in the SAGD process. Most producers co-inject methane with steam during the blowdown phase late in a reservoir’s productive life. Improving the steam to oil ratio is the primary goal. Reducing steam consumption on existing wells frees steam-generating capacity that can then be redeployed to other wells. As Brad Bellows, director of external communications, puts it: “Lowering the steam to oil ratio for particular patterns essentially gives us a nearly capital-investment-free steam package.” Gas co-injection with steam, combined with the infill wells, reduced the steam to oil ratio on the pilot well pairs to 1.3, says Bellows. That is a dramatic reduction from about 2.3 or 2.4—already among the lowest steam to oil ratios in the industry—when eMSAGP began on those well pairs.
Cover Feature
In situ oilsands projects under construction Phase
Technology
Capacity
Year of Production Start
Demonstration
SAGD
1,400
2014
Hangingstone
Phase 1
SAGD
12,000
2015
MacKay River
Phase 1
SAGD
35,000
2015
Christina Lake
Phase F
SAGD
50,000
2016
Phase F
SAGD
45,000
2014
Foster Creek
Phase G
SAGD
40,000
2015
Phase H
SAGD
40,000
2016
Operator
Project
Andora Energy Corporation
Sawn Lake
Athabasca Oil Corporation Brion Energy Corporation
Cenovus Energy Inc.
Narrows Lake
SAP
45,000
2017
Kinosis (K1A)
SAGD
40,000
TBD
Surmont
Phase 2
SAGD
109,000
2015
Devon Canada Corporation
Jackfish
Phase 3
SAGD
35,000
2014
Harvest Operations Corp.
BlackGold
Phase 1
SAGD
10,000
2014
Husky Energy Inc.
Sunrise
Phase 1
SAGD
60,000
2014
CSS
40,000
2014
CNOOC Limited
Long Lake
ConocoPhillips Canada
Imperial Oil Limited Cold Lake
Phase A
Phase 14-16
Japan Canada Oil Sands Limited
Hangingstone
Expansion
SAGD
20,000
2016
MEG Energy Corp.
Christina Lake
Phase 3A
SAGD
50,000
2016
Pengrowth Energy Corporation
Lindbergh
Phase 1
SAGD
11,240
2015
Royal Dutch Shell plc
Peace River
Carmon Creek - Phase 1
VSD
40,000
2017
Source: Oilsands Review
In other words, the pilot well pairs now require a little more than half as much steam to produce the same amount of bitumen. Cenovus has used methane co-injection on six wells at Christina Lake and 15 wells at Foster Creek. “While, generally, methane co-injection has reduced steam-oil ratios, it’s hard to give specifics as it depends on a number of factors, including geology and timing of injection,” Cenovus says. “Co-injection testing at Christina Lake has primarily been done early in the life of well pairs, while at Foster Creek, testing has mainly focused on using methane co-injection to transition wells to blowdown.” Cenovus has a number of other initiatives underway to improve the steam to oil ratio at Foster Creek. The ratio trended higher than expected in 2013 primarily due to the age-related formation of common steam chambers, so the company has been using new operating techniques to improve the conformance of steam along wellbores. Efforts included optimal placement of steam across its well
pads, timely placement of older pads on blowdown and transferring steam to new pads at the most appropriate time. “We have increased our implementation to better monitor our steam movement and coalescence of the steam chambers,” John Brannan, executive vice-president and chief operating officer for Cenovus, told a first-quarter-results conference call. “We are currently running at 95 per cent with our downhole instrumentation, and we plan to maintain this level going forward.” Cenovus has two pads in the early stages of blowdown and one pad fully underway, and it is awaiting regulatory approval to move two additional pads to blowdown. It has also started the application process with the regulator for six more pads, said Brannan. “The critical path on this initiative is having sustained pads ready to begin accepting steam,” he said. The company is fast-tracking the development of additional sustaining pads, he added.
In addition, the company is using wedge well technology where conformance is not ideal. This involves drilling single horizontal producing wells between well pairs, allowing Cenovus to recover more oil while adding very little additional steam. The company drilled 11 of these wells in the first quarter of 2014 and expects to have 42 of them starting production over the next 14 months. “We’re pleased with how Foster Creek has responded to the changes we’ve made,” said Brannan. “We’re on track with our expansion plans and expect to produce between 100,000 and 110,000 barrels per day gross until we begin ramping up production from our next expansion phase in the third quarter.” Seeing the success of integrating new technologies into SAGD operations, Statoil is looking at a suite of 14 technologies it will pilot and deploy in the next decade, according to 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, infill wells and solvent co-injection as an integrated system, plus it has a few more technologies up its sleeve which it is not ready to disclose. While the technologies are not especially novel on their own, using them together is, says Victor del Valle, Statoil’s heavy oil technology centre portfolio leader. The technologies were selected following two years of extensive analysis and model simulations designed to identify opportunities for Statoil’s next proposed oilsands development, its 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. Similar steam to oil ratio 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, says Statoil. Probably the most promising initial technology 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, says del Valle. OIL & GAS INQUIRER • SEPTEMBER 2014
41
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SEPTEMBER 2014 • OIL & GAS INQUIRER
This will be done by mechanical breakthrough such as directional drilling (creating short-length multilaterals near the wellbore) and small-hole drilling, says 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,” says 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 towards the end of the project’s life, however, since the company goes after the most economic barrels—the standard SAGD barrels—first, he says. Infill wells and well-spacing optimization will also be introduced further along in the project, he adds. 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 the surface to shut down and open up zones and control steam more deterministically, says Valle. These flow-control devices should also help with solvents, he says. While steam loss is inefficient, solvent loss is even worse, so Statoil is investigating solvent coinjection 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, says del Valle. This is the same technology that makes a bullet spin as it exits a rifle, he explains. “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 says. “It’s tubes in the boiler that have an etching that spirals 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 buildup 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.
Feature
NORTHERN LIGHTS Peace River Arch continues providing stellar opportunities for disciplined explorers
By Darrell Stonehouse with notes from the Daily Oil Bulletin
W
Photo: Joey Podlubny
ith the Deep Basin to the south and the Montney play across the border in British Columbia—the two hottest plays in western Canada going in to 2014—it is easy to forget about the Peace River Arch area in northwestern Alberta. But that would be a mistake because a number of plays in the stacked reservoirs surrounding Grande Prairie, Alta., are ramping up and providing plenty of work for area service companies. Birchcliff Energy Ltd. is a major player in the region with 615,000 net acres of land and two major plays under development. These are the Montney/Doig gas play and the Worsley/Charlie Lake light oil play. In the first quarter of 2014, Birchcliff drilled seven Montney/ Doig horizontal natural gas wells and two Montney/Doig horizontal light oil wells. Year-to-date, Birchcliff has drilled 12 Montney/ Doig horizontal natural gas wells and two Montney/Doig horizontal light oil wells. Birchcliff continues to expand the Montney/ Doig natural gas resource play both geographically and stratigraphically, says the company. In his first-quarter report to shareholders, Birchcliff president and chief executive officer A. Jeffery Tonken says the company is using a variety of technologies and processes to make the play economic given current gas prices. This includes 3-D seismic, which he described as a key technical tool in the development of resource plays. In the first quarter, the company spent $5.4 million on 3-D seismic surveys, which included 74 square kilometres of new proprietary 3-D seismic, 27 square kilometres of new, speculative industry 3-D seismic and 308 square kilometres of trade 3-D seismic.
OIL & GAS INQUIRER • SEPTEMBER 2014
43
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“This geophysical data gives a much more refi ned image of what the subsurface looks like, assisting in geological interpretations to delineate reservoir distribution of our resource plays and assisting in the drilling of the horizontal wells,” says Tonken. The company is also using pad drilling to wring efficiencies out of its horizontal drilling and multistage fracturing program, which uses five wells per pad. Tonken says the use of multi-well pad drilling “allows us to drill continuously right through spring breakup,” further improving the economics of the play. While Birchcliff has a wealth of potential drilling targets in the Montney/Doig, it continues building on that inventory. “To quantify our aggressive growth strategy for the Montney/Doig resource play, in the first quarter of 2014, through land sales and acquisitions and removing any expires, we added 12.8 net sections of land for the Basal Doig/Upper Montney play and 13 sections of land for the Middle/Lower Montney play, for a total of 25.8 net sections to develop on the Montney/Doig Resource play,” says Tonken. “These lands, developed at four wells per section, per play, yield a total of 103.2 net future locations.” On March 31, 2014, Birchcliff ’s total land holdings on the Middle/Lower Montney play and the Basal Doig/Upper Montney play comprised 615.7 net sections. At the end of the fi rst quarter of 2014, on full development of four horizontal wells per section per play, Birchcliff had 2,462.7 net horizontal existing wells and future horizontal drilling locations. Since 126.9 net locations were drilled at the end of the fi rst quarter of 2014, 2,335.8 net future horizontal drilling
“One general area of development is the increased exploration and commercialization of new stratigraphic intervals within this play.” — A. Jeffery Tonken, president and chief executive officer, Birchcliff Energy Ltd.
locations remain. But Tonken says this is only part of the story. “Recently there have been some significant positive developments by industry on the Montney/Doig play,” he says. “One general area of development is the increased exploration and commercialization of new stratigraphic intervals within this play. We continue to evaluate additional new target intervals within the Montney and Doig formations to more fully define the potential. We anticipate drilling our first horizontal well in one of the new intervals by year-end.” In the first quarter of 2014, Birchcliff drilled five Charlie Lake horizontal oil wells at its Worsley/Charlie Lake light oil resource play using multistage fracture stimulation technology. It also continues to pilot waterflooding in the play. Tourmaline Oil Corp. is going full throttle in the Charlie Lake play, company president and chief executive officer Michael Rose reported in early August. Rose told analysts in his secondquarter conference call that current production from the Charlie Lake oil complex
is 12,000 barrels of oil equivalent with approximately 5,000 barrels per day of additional volume awaiting facility access. Start-up of the new Spirit River 03-10 gas plant early in the fourth quarter and additional tie-ins are expected to yield an exit production level of 18,000–20,000 barrels equivalent per day for 2014. Tourmaline has now drilled 82 Charlie Lake horizontal oil wells and no dry holes in the complex to date, and with three rigs active, it expects to add approximately 45 new horizontals per year. Rose reported completed and stimulated well costs are averaging $4 million to $4.5 million with proved-plus-probable reserves of 350,000 barrels equivalent per horizontal in the current independent engineering report. Seven additional concurrently stimulated well pairs will be drilled and completed prior to year-end 2014 with 10 additional pairs planned in 2015. The company believes these concurrent pairs may lead to a step-change in horizontal well performance. “They look tremendous,” Rose said at the company’s annual meeting. “We want to get seven more, and then you’ve got 10, and you’ve got a statistical base that is worthy of ascertaining if you’ve got a stepchange in production performance or not.” Rose said Tourmaline has a comprehensive infrastructure plan in place for 2014-15 that will allow for the tie-in of rapidly growing production volumes, improved production on-times and reduced operating costs. The first component of the infrastructure plan is the Spirit River sour gas injection plant, operated by Tourmaline, which is expected to start up in mid-October of this year. The second component of the plan is the Mulligan oil battery, of which the first 8,000 barrels
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Feature
per day phase will be operational by spring breakup 2015. The company is also pursuing a complementary series of water disposal, oil blending and direct oil tie-in opportunities to continually improve netbacks. So far this year, operating costs for the Spirit River-Mulligan-Earring complex are approximately $14.83 per barrel equivalent. These costs are anticipated to drop to the $10 level over the next several quarters as the full infrastructure plan is implemented. Overall, long-term corporate operating costs in the $4.25–$4.50 per barrel range are anticipated. Tourmaline has identified over 1,200 potential drilling locations in the Charlie Lake play. Long Run Exploration Ltd. is also having success drilling for oil in the Peace River Arch, this time targeting the Montney Formation. The company drilled a total of 50 net successful horizontal Montney oil wells at Normandville and Girouxville in 2013. In total, 2013 capital spending in the area was approximately $141 million, of which more than $27 million was invested in development activities, including the drilling of 9.5 net wells, during the fourth quarter. Production from its Peace River area has grown to about 13,000 barrels equivalent per day (60 per cent oil and natural gas liquids), up from about 7,500 barrels per day (30 per cent liquids) when the current management, which includes chair and chief executive officer William Andrew, took over in August 2011. Close to 10,000 barrels per day of Long Run’s Peace River area production comes from Normandville and Girouxville. Long Run plans to drill 43 horizontal Montney wells in its Peace River area this year, 18 of which were drilled in the first quarter. Company president Dale Miller says Long Run’s Montney drilling times have been cut to six or seven days (spud to rig release) from 11–12 days. The company is also launching waterflood pilots in the area to improve recovery, says Miller. “They’ll be full-pattern waterflood pilots—it just isn’t going to be one injector and one producer,” he says. “We’ve planned for Normandville, I believe, eight injectors, and at Girouxville we’ll have four injectors with a complement of producers. So we’ll have two really good pattern waterflood pilots.” Long Run has 145,000 net acres in the Montney oil play, with 122 horizontal drilling locations booked.
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45
Feature
Getting it
done
Managing drilling and completions supply chain key to resource play success By Darrell Stonehouse with notes from the
46
SEPTEMBER 2014 • OIL & GAS INQUIRER
Photo: Encana Corporation
Success in the resource plays that dominate drilling and completions activity in western Canada these days means proving up reserves and then turning the development of those reserves into a manufacturing process. But it’s a manufacturing process where much of the work being done is contracted out to service providers, and that means planning, according to Scott Sobie, president and chief executive officer of private producer Canadian International Oil Corp. (CIOC). Sobie told the 2014 TD Securities Calgary Energy Conference that, in resource plays like the Deep Basin where his company operates, operators need to address supply management issues early. He said that CIOC has not yet locked in crews and is not embarking on multi-well programs yet, but it has
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been able to lock in a few drilling rigs, which has helped decrease costs. His Calgary-based company is currently engaged in delineation of the land base through a balance of de-risk pilot wells and development drilling. “The resource play game, and that’s the space we’re in, is largely about getting after the supply management issues very early and trying to ensure that you’re locked in,” said Sobie. Sobie told the conference that CIOC will soon embark on a multi-well, multi-pad program and has been able to secure “very good pricing on the drilling side. We’ve seen a little bit of cost creep on the fracking side, but it’s not been that troublesome for us.” His company has seen “a huge efficiency curve on the drilling side,” he said, adding that, in one particular area where it used to take more than 50 days to drill a well, it now takes 30 days, and the company recently drilled one well in 23 days. That pace has been driven by motor efficiencies, using brine in the lateral and continued bit selectivity, said Sobie. It also helps that his employees are technically adept and experienced in the areas in which CIOC operates, he said. Trent Yanko, president and chief executive officer of Legacy Oil + Gas Inc., says his company has been insulated from any cost pressures because more than 90 per cent of its drilling is in the Williston Basin, where Legacy is one of the most active operators. As a result, Legacy has had the benefit in the past three years of being able to pick up whatever rig it wants and has been able to drive down day rates on both drilling and completions, says Yanko. More importantly, Legacy has continued to find ways to cut drilling days, he says. In the Spearfish play, for example, it now takes between 5.5 and six days to drill a well, whereas it used to take nine days. “Those savings are permanent. Day rates can go back up again, but we don’t foresee ourselves taking a lot longer to drill a well,” says Yanko. “It’s been a lot of small wins. We attack it from bit selection, motors, staying in the zone more consistently,” he says. “The more you’re in the zone, the less you’re steering. It’s like on a race track. The more times your wheels are pointing forward, the faster you can go.” In addition, Legacy emphasizes understanding the geology and having rapid feedback as it drills to ensure time is minimized and results are maximized, he says.
“And we do have a lot of clout with the service guys, so we are able to keep a lid on things,” he adds. Legacy has not experienced any pressures on costs, but when possible it buys items such as casing and tubing in bulk and will purchase steel nine or 10 months in advance when its price dips. “We’re getting to that size, with a nearly 200-well drilling program, to have that type of purchasing power,” says Yanko. George Fink, chief executive officer and chair of the board of Bonterra Energy Corp., and Clayton Thatcher, DeeThree Exploration Ltd.’s vice-president of exploration, both agree with Yanko. Fink adds that, when it comes to savings, his company strives to “come at it from all angles,” meaning it aims to be cost efficient in drilling, completions and tie-ins. Bonterra currently drills and ties in simultaneously in the Cardium to save time and get wells on production a little faster, he says. Sometimes this is not possible during spring breakup when there are road bans, so that’s when his company uses temporary tanks for its production, which is then trucked, he says. Bonterra also experiments with the placement of bottomhole pumps to ensure they last as long as possible. Thatcher says DeeThree has found cost savings with extended-reach horizontal drilling and is always aiming to extend at least two miles. He has found that drilling crews get more efficient with experience, so DeeThree keeps crews together and rigs active. “Our Bakken rig never lies down; it just keeps drilling, going from one location to the next. That’s where most of our efficiencies have come from.” While there appears to be capacity in the drilling market to handle growth in resource play drilling, there is less certainty that pressure pumpers could handle a large increase in development drilling. And this has implications for operator supply chains. Just looking at the Duvernay, Canadian oilfield service firms could easily support the drilling of 200 wells a year, but full development will require a significant expansion of the existing equipment fleet, a service sector engineer said late this winter. According to the most recent estimates, roughly 125–200 horizontal wells are expected to be drilled into the
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emerging shale play in Alberta this year, up from about 105 last year and 51 in 2012, says Tyler Elgar, engineering manager for the Canadian division of Calfrac Well Services Ltd. “But really, you must start thinking beyond the 200 wells a year. If we start talking 300, 400, 500—which many have pegged to be the number for full development of the Duvernay—we need to consider what challenges face us,” Elgar suggests. “We’re going to be talking about large multi-well pads— eight, 16, maybe 24-plus wells on a pad. It’s certainly going to be 24-hour operations,” he says. “The estimate we’ve seen on the hydraulic horsepower demand to facilitate this is 300,000-plus. We’ve seen some estimates encroaching on 400,000.” To put this into perspective, Elgar says that’s roughly 20 per cent of the capacity that exists in Canada today. “This will require significant collaboration and preplanning. I say that because to the best of our knowledge, nobody has really committed the capital yet to build the crews to support this work,” he says. “I think we’re all, in the background, trying to get an appreciation for where this play is going so we can be ready when the workload is there. “And keep in mind, a crew of this size to do this style of work is roughly a 12- to 18-month build time.” He adds, “We’re going to be competing for resources against the Montney, the Cardium, the Deep Basin and other successful plays in this area.” The drilling of wells with longer laterals and tighter spacing will also tie up more services that would otherwise be available for the Duvernay. Elgar points out that success in the Duvernay could generate its own challenges. As drilling in the play ramps up, demand for services in the Duvernay itself could hamper the pace of development. While much of the initial Duvernay drilling was on singlewell pads, full development mode would obviously involve multiwell pads. “On a per-pad basis, we’re talking perhaps eight wells” with 15 frac stages per well—each stage using 150 tonnes of proppant and 2,000 cubic metres of fluid, he says. That would work out to 120 fracs, 18,000 tonnes of proppant and 240,000 cubic metres of fluid for an eight-well pad. With the ability to conduct roughly four fracs in a 24-hour period, it would take about 30 days to get through 120 fracs, pumping 600 tonnes of proppant and 8,000 cubic metres of fluid a day. “The highlight here is logistically this poses a significant challenge, though one that we have the ability to overcome,” Elgar says, referring to the service sector in western Canada. That is, if pressure pumpers can find the workers to man the fleet. “I don’t think industry growth of anything greater than 10 per cent annually is possible,” Brad Fedora, president and chief executive officer of Canyon Services Group Inc., told the TD Securities Calgary Energy Conference. One of four executives appearing on the conference’s oilfield service panel, Fedora said rapid industry activity is testing pressure pumpers’ ability to keep pace. “We can’t keep up with the people side of the business at this stage,” he said. Still, things could get worse before they get better. When construction of liquefied natural gas (LNG) facilities on Canada’s West Coast starts in earnest, the pace of pressure pumping in western Canada will likely rise to the “next level of difficulty,” he said. Producers with Montney natural gas plays in British Columbia are looking to Asian LNG demand to fill their sails, so to
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Better drill bit choices are being credited with part of the improvement in drilling times.
speak, while pressure-pumping contractors will service that and other plays. By September, Canada’s pressure pumpers will be going flat out, with all available equipment at work, Fedora predicted. Even then, the Canadian market still needs as much as another million hydraulic horsepower in pumping capacity, he said. Growth in the B.C. Montney, and, to a much lesser degree, Alberta’s Duvernay, has boosted the fortunes of Canada’s pressure pumpers. While the two plays combined account for only about one in 10 of all wells drilled in western Canada, they represent a disproportionately large chunk of Canadian pressure-pumping demand, said Fedora. “Together, those plays can easily represent 30–40 per cent of…pressure-pumping demand,” he said. “The big change we’ve seen in the last couple of years is the ongoing focus on the Montney and the resulting increase in demand for pressure pumping in that play.” Relatively small changes in Montney activity sharply affect equipment use for Canyon, according to Fedora. “We’ve gone from an 80–85 per cent to a 100 per cent utilization rate in the last six months,” and that has generally been driven by Montney activity, he said. For some on the panel, the current upswing in industry activity recalled a similar trend in 2010-11, and panel chairman Scott Treadwell, vice-president of equity research for TD Securities, asked executives on the panel what, if anything, has changed since then. “This upswing was more anticipated, more expected and probably better planned,” said Alex MacAusland, president and chief executive officer of Western Energy Services Corp. Others also saw an evolution in terms of ownership of oil and gas properties in western Canada. In the 2010-11 period, many properties were still held by junior and intermediate producers, but that changed as much larger Asian and U.S. companies moved in, said Fedora. “A lot of those assets have been sold off, and the people in control of them today are more financially robust and have longer-term planning,” he said. “I think, this time round, it’s been planned better and will unfold more smoothly, just because the bigger companies are running these assets.” In keeping with the increasing size and scale of producers who now own the basin’s assets, some executives noted a corresponding change in approach. Producers calling the shots today are demanding a more sophisticated level of organization and planning by the service companies they hire. For the latter, that has meant more time spent on organizational development, while competitors focus on keeping employees for the long term.
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advertisers' index MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 36
Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . 42
Edmonton Exchanger & Refinery Services Ltd . . . 33
Annugas Compression Consulting Ltd . . . . . . . . .14
Edmonton International Airport . . . . . . . . . . . . . 34
NCSG Crane & Heavy Haul Services . . . . . . . . . . 49
Ar-Tech Coating Ltd . . . . . . . . . . . . . . . . . . . . . . . . 11
Enform . . . . . . . . . . . . . . . . . . . . . . . . . . . . gatefold
Netzsch Canada, Inc . . . . . . . . . . . . . . . . . . . . . . . 29
BC Research . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . .10
Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . 28
Bear Slashing Inc . . . . . . . . . . . . outside back cover
Globalstar Canada Satellite Co . . . . . . . . . . . . . . 23
Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 38
Hemmera . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Brother’s Specialized Coating Systems Ltd . . . . 44
Hotsy Water Blast Manufacturing LP . . . . . . . . . .12
CENTA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Infinity Tubular . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 48 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Phoenix Fence . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Platinum Energy Services ULC . . . . . . . . . . . . . . .13
CG Industrial Specialties Ltd . . . . . . . . . . . . . . . . 20
Infosat Communications LP . . . . . . . . . . . . . . . . .18
Chase Operator Training . . . . . . . . . . . . . . . . . . . 42
League Pipeline Services Ltd . . . . . . . . . . . . . . . 37
Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Lloydminster Heavy Oil Show . . . . . . . . . . . . . . . 24
Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Mainland Machinery Ltd . . . . . . . . . . . . . . . . . . . 48
RedGuard . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 & 30
dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . 32
Site Energy Services . . . . . . . . . . . . . . . . . . . . . . 32
Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . . 8
Meridian Manufacturing . . . . . . . . . . . . . . . . . . . .16
UFA . . . . . . . . . . . . . . . . . . . . . . . inside back cover
Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 22
Messe Dusseldorf . . . . . . . . . . . . . . . . . . . . . . . . .19
V J Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . . 7
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Platinum Grover Int. Inc . . . . . . . . inside front cover Pumps & Pressure Inc . . . . . . . . . . . . . . . . . 28 & 30
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