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ISSUE Pollution-monitoring triggers exceeded in oilsands mining region
Western Canada's Exploration & Production Authority
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CONTENTS
OCTOBER.
in the news
13
Pembina weighs options for propane exports
regional news
17
British Columbia
Artek ups budget
21
Northwestern Alberta
NuVista’s Montney winter drilling program expected to up 2014 production
29
Northeastern Alberta
39
Southern Alberta
Pollution-monitoring triggers exceeded in oilsands mining region
Hemisphere reports Atlee Buffalo success
33
43
Central Alberta
Peyto reaches Deep Basin milestone
Saskatchewan
Northern Blizzard production climbs
features
COVER FEATURE
46 Dirty work It takes grit to make Lloydminster heavy oil pay off
every issue
10 54
Stats at a Glance Political Cartoon
50 Breaking up As completions technologies evolve, operators customize fracturing processes on a play-by-play basis with a focus on cutting costs and raising production
Cover design: Peter Markiw Photo: Joey Podlubny
OIL & GAS INQUIRER • OCTOBER 2014
7
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Editor’s Note Vol. 26 No. 10 EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Lynda Harrison, Paul Wells EDITORIAL ASSISTANCE MANAGER
Tracey Comeau | tcomeau@junewarren-nickles.com EDITORIAL ASSISTANCE
Kate Austin, Michael Doyle, Sarah Maludzinski CREATIVE
LNG export terminal delays could prove costly
CREATIVE SERVICES MANAGER
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD
Cathlene Ozubko PRODUCTION COORDINATOR
Janelle Johnson
GRAPHIC DESIGNER
Peter Markiw
CREATIVE SERVICES
Ginny Tran Mulligan production@junewarren-nickles.com SALES SENIOR ACCOUNT EXECUTIVE
Nick Drinkwater, Tony Poblete, Diana Signorile SALES
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Lorraine Ostapovich | atc@junewarren-nickles.com DIRECTORS CEO
Bill Whitelaw | bwhitelaw@junewarren-nickles.com PRESIDENT
Rob Pentney | rpentney@junewarren-nickles.com DIRECTOR OF SALES & MARKETING
Maurya Sokolon | msokolon@junewarren-nickles.com DIRECTOR OF EVENTS & CONFERENCES
Ian MacGillivray | imacgillivray@junewarren-nickles.com DIRECTOR OF THE DAILY OIL BULLETIN
Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES
Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR OF CONTENT
Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION
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Alberta T2E 6Y4. Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.
Any hopes that liquefied natural gas (LNG) exports will boost western Canada’s energy sector in the short to mid-term are fading fast as project operators push decisions on whether to construct terminals on the west coast further into the future. In April, Imperial Oil Limited chair, president and chief executive officer Rich Kruger said Imperial and parent company Exxon Mobil Corporation are in no hurry to develop their proposed facility off the west coast and a decision on whether the project will go ahead is years away. “Whatever time it happens to take is what it will take,” he said. “And if there’s a market value and a place in the market, then it will be a project. And if there’s not, it won’t go.” In late July, Apache Corporation said it was looking to get out from under its 50 per cent share of the Kitimat LNG project, leaving partner Chevron Canada Limited in purgatory until a new partner is found. Apache also signalled it was looking to sell its 50 per cent interest in the Kitimat upstream partnership, consisting of around 650,000 acres in the Horn River and Liard basins. In September, Royal Dutch Shell plc said it expects to decide whether to develop an LNG export terminal on Canada’s west coast in about two years or in late 2016. This will be followed by four or five years of construction, putting out first exports in 2021-22. The slow movement towards Canadian LNG exports is bad news for gas producers
as U.S. supply keeps climbing and making inroads into Canada. In early September, the U.S. Energy Information Administration (EIA) said gas production in 2014 is expected to climb 5.3 per cent over 2013’s record high. This is the fourth straight year of record production, and the EIA expects production to rise again in 2015 to 75.47 billion cubic feet per day. Most of the production increase is coming from the Marcellus and Utica shale plays in the northeastern United States, and some of that gas is already coming to eastern Canada through Niagara Falls. In 2008, 600 million cubic feet per day of western Canadian gas headed south at Niagara Falls. Last year, 400 million cubic feet per day travelled north as the Tennessee Gas Pipeline system line was reversed. Now, Spectra Energy Corp. is proposing a new system, with up to two billion cubic feet per day of capacity, to supply markets in the Upper Midwest in the United States and Ontario. Western Canadian gas is becoming stranded, and it won’t be long before, despite having hundreds of years of supply, Canada as a whole becomes a gas importer. And that’s just plain embarrassing. Until next month. Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
N EXT I S S U E November 2014 A review of pipeline safety statistics plus a look at what industry is doing to mitigate spills in the future. An examination of development in the Viking play and where growth is predicted to come from going forward.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.
OIL & GAS INQUIRER • OCTOBER 2014
9
FAST NUMBERS
.
billion cubic feet
Average U.S. daily gas production in 2014, according to the U.S. Energy Information Administration.
.
billion cubic feet
Average U.S. daily gas production in 2015, as predicted by the U.S. Energy Information Administration.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
Sep
357
72
Oct
528
153
GAS
T O TA L
MONTH
OIL
2
Sep
72
Oct
OTHER
GAS
D RY
SERVICE
T O TA L
735
113
1
30
53
204
8
7
,
Nov
463
164
44
Nov
852
218
62
,
Dec
28
137
52
Dec
675
180
20
72
Jan
280
105
57
Jan
488
156
18
55
Feb
87
163
15
73
,
Feb
427
11
80
Mar
521
165
126
Mar
24
218
23
118
,
504
142
17
68
Apr
418
4
62
Apr
May
188
54
63
May
25
77
10
5
Jun
240
4
45
Jun
411
154
44
Jul
245
52
70
Jul
562
86
24
71
Aug
257
63
6
Aug
657
77
2
81
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 *
OIL
GAS
Sep
347
0
1
Oct
380
0
15
532
Nov
33
0
27
45
45
Dec
321
0
3
4
4
Feb
46
150
Jan
181
0
13
Mar
55
205
Feb
401
0
7
Apr
56
261
Mar
34
0
14
May
41
302
Apr
7
0
23
Jun
62
364
May
20
0
1
Jul
35
3
Jun
163
0
7
Aug
1
418
Jul
20
0
21
Aug
338
0
26
Sep
43
422
Oct
52
474
Nov
58
Dec Jan
*Year-to-date
MONTH
OTHER
TOTAL
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OCTOBER 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, September 10, 2014 Source: Rig Locator
Alberta, August 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
Aug
GAS WELLS
Aug
Aug
Aug
264
2
47%
Northwestern Alberta
68
7
31
24
British Columbia
52
16
76%
Northeastern Alberta
27
87
0
0
Manitoba
11
14
44%
Central Alberta
137
11
27
6
Saskatchewan
73
73
50%
Southern Alberta
25
36
5
16
%
TOTAL
WC TOTAL
Top Active Drillers in Canada
Drilling Activity: CBM & Bitumen
Western Canada, September 11, 2014 Source: Rig Locator
Alberta, August 2014 Source: Daily Oil Bulletin
O P E R AT O R
ACTIVE RIGS
DEV
EXP
C OA L B E D M E T H A N E
OTHER
Progress Energy Canada Ltd.
1
18
0
1
Tourmaline Oil Corp.
18
15
3
0
Canadian Natural Resources Limited
18
16
1
1
Husky Energy Inc.
17
13
4
0
Crescent Point Energy Corp.
14
8
6
0
Seven Generations Energy Ltd.
11
7
3
1
ConocoPhillips Canada
10
1
0
Cenovus Energy Inc.
7
0
2
Apache Canada Ltd.
6
3
0
Alberta
Aug
Aug
BITUMEN WELLS Aug
Aug
Northwestern Alberta
0
0
3
7
Northeastern Alberta
0
0
27
87
Central Alberta
1
0
61
81
Southern Alberta
4
2
0
0
TOTAL
OIL & GAS INQUIRER • OCTOBER 2014
11
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IN THE
NEWS Issues affecting Canada’s E&P industry
Pembina weighs options for propane exports The marine terminal will include a wharf, trestle and associated infrastructure, including refrigerated propane storage, loading pipelines and ship-loading arms with a maximum loading rate of about 15,000 barrels per hour. It would be capable of accommodating a single very large gas carrier with a maximum capacity of up to 80,000 cubic metres. In response to the surge in liquidsrich gas production in western Canada,
160
Pembina and other midstreamers are expanding their natural gas and natural gas liquids processing capacity. This industry expansion is forecast to boost propane production in western Canada by about 70,000 barrels per day, or about 70 per cent, “which is and will continue to be, over the long term, surplus to Canadian demand,” the application said. North American propane supply has been growing in recent years and
ALBERTA PROPANE SUPPLY AND DEMAND 25 Supply
Alberta demand
140
20 120
100
103 m3/d
15 103 bbls/d
Pembina Pipeline Corporation is seeking export approval to ship up to 75,000 barrels per day of propane from a marine terminal to be built on the west coast of either Canada or the United States. In an application filed with the National Energy Board (NEB), two of Pembina’s wholly owned subsidiaries—Pembina NGL Corporation and Pembina Resource Services Canada—have jointly applied for a 25-year propane export licence. All of the Canadian-sourced propane would be shipped by rail to the proposed marine terminal that would load up to 75,000 barrels per day onto tankers bound for the Pacific Basin, the application said. To date, propane producers in western Canada haven’t had the option of marine exports, Pembina said. The export terminal will consist of propane rail-receipt facilities, storage facilities, marine-loading facilities and interconnecting propaneloading pipelines. Prospective sites on the west coast of Canada and the United States are currently being scoped and evaluated, and preliminary engineering, technical studies and investigations are underway, the application said. Pembina says the fi rst propane cargo from the marine terminal is expected to be exported in the 2017-20 time frame. Since the location could be in the United States or Canada, Pembina is applying for NEB approval to export by rail to the United States as well as by marine terminal. If the export terminal is built on the U.S. west coast, the export points would be where railways cross into the United States. These include Coutts, A lta.; Kingsgate, B.C.; Huntingdon, B.C.; and New Westminster, B.C. If the marine terminal is built on the west coast of Canada, it will be the sole point of export.
80
10
60
40 5 20
0
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Year
0
Source: Alberta Energy Regulator
OIL & GAS INQUIRER • OCTOBER 2014
13
Pembina plans to ship up to 75,000 barrels per day of propane overseas.
fractionation facilities and propane transportation and storage capacity. Pembina retained Gas Processing Management Inc. (GPMI) to forecast Canadian propane supply and demand during 2015-45—the term of the export licence Pembina is seeking. According to Pembina, GPMI expects Canadian propane exports to the United States will continue to fall as the United States grapples with a domestic glut of propane. And while Canadian propane demand is expected to rise steadily, it won’t be enough to absorb the growth in supply, the consultancy warned. GPMI found there is currently a Canadian propane surplus of 90,000 barrels per day, which is forecast to grow to 120,000 barrels per day by 2045, Pembina’s application said. “The total supply of propane in Canada is expected to continue to exceed domestic demand, and therefore Canada will remain a net exporter of propane for the foreseeable future,” GPMI concluded.
is expected to exceed North American demand in both the near term and the long term, Pembina said. Also, increased propane production from new shale gas developments in the United States has significantly increased the propane supply within that market and dampened U.S. demand for propane from western Canada. This surge in North American propane supply has occurred as global demand has grown, so North America is well positioned to serve world export markets, particularly Pacific Basin regions, the application said. “Given the increased focus in Canada on the development of natural gas production and L NG [liquif ied natural gas] exports, it is critical that new and expanded markets…for propane—as a byproduct of this production—be developed,” Pembina argued. Pembina has one of Canada’s biggest networks of pipelines and gas processing facilities. These facilities are concentrated in A lberta and include
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OCTOBER 2014 • OIL & GAS INQUIRER
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In The News
In The News
Service companies, midstreamers increasing capital budgets Capital budgets for Canadian oilfield service and supply and midstream companies continue to rise with forecast spending of more than $8 billion in response to growing customer demand. Twenty-eight companies tracked by the Daily Oil Bulletin plan spending of $8.09 billion, up by more than $1.65 billion, or about 25 per cent, from the $6.45 billion they initially planned to spend in 2014, when they set their budgets in late 2013 or early this year. Precision Drilling Corporation has reported the largest additional capital spending with four increases totalling $430 million so far this year. The company most recently boosted its 2014 budget by $101 million (12 per cent) to $934 million from $833 million in response to strong customer demand for its Super Series rigs. The company has firm
customer commitments on another 13 newbuild rigs, including two more deliveries in 2014 and 11 in 2015. Precision is expanding its long-lead program to shorten construction times for new-build rigs that will provide the capacity of three rig deliveries per month starting October 2014, and as many as four rigs per month to start in 2015 if U.S., Canadian and international customer demand continues at the current pace. In April, Precision boosted its capital budget by 31 per cent to $833 million from $634 million as it saw rising demand for new drilling rigs. The added spending of $199 million was to cover four new-build, Super Triple rigs destined for the U.S. market in the second half of this year, as well as five new Super Triples set for delivery in early 2015.
On the pressure pumping side, Calfrac Well Services Ltd. has increased its budget twice this year for a total increase of $240 million. The second time was last month when it added $210 million, raising planned 2014 spending to $360 million from $150 million, including carry-over capital of $20 million. The growth in spending is in response to significantly improved customer demand in the United States, Canada and Argentina. A portion of the increased capital spending is expected to occur in 2015. In May, Calfrac announced a $10-million expansion of its 2014 capital program to $130 million, plus an additional $20 million of carry-over capital, for expected 2014 capital spending of $150 million. In the midstream business, Pembina Pipeline Corporation and Keyera Corp.
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have each increased their budgets by $200 million. Pembina’s budget for this year rose to $1.7 billion from $1.5 billion, with the increase reflected in additional spending this year for the company’s $2-billion Phase 3 expansion, the largest expansion of Pembina’s systems in the company’s history. The 540-kilometre expansion will follow and expand upon certain segments of the company’s existing pipeline systems from Taylor, B.C., to Edmonton to fulfill capacity needs for Pembina’s customers, with the priority on areas where debottlenecking is essential. The project will increase crude oil, condensate and natural gas liquids takeaway capacity from northwestern Alberta and northeastern British Columbia to markets in the Edmonton and Fort Saskatchewan, Alta., areas. Keyera has also increased its estimated capital spending twice this year, most recently in August when it said it is on target to execute its biggest capital spending program ever. The company now estimates that capital investment in 2014 will be between $700 million and $800 million, up from the previous $600 million to $700 million. The projects complement the existing assets and meet the growing needs of customers, driven by producer activities that are focused on liquids-rich drilling and oilsands development, according to Keyera. — DAILY OIL BULLETIN
16
OCTOBER 2014 • OIL & GAS INQUIRER
Photo: Joey Podlubny
Calfrac plans on spending $150 million on capital projects in 2014.
BRITISH COLUMBIA WELL ACTIVITY AUG/13
AUG/14
Wells licensed
5
AUG/13
AUG/14
Wells spudded
52
AUG/13
AUG/14
53
Rigs released
▼
▲
▲
Source: Daily Oil Bulletin
B.C. British Columbia
Artek ups budget
Photo: Joey Podlubny
Artek Exploration Ltd. has increased its 2014 budget—now $88 million to $86 million— due to the additional capital required to fix mechanical problems in the first half of the year and a budgeted capital expansion. That’s up from the original $61 million to $66 million earlier in the year. Artek announced the expanded capital program in the wake of a $43-million equity financing completed in June. Budgeted are two additional horizontal wells at Inga/Fireweed in British Columbia, an additional water disposal well and about $2 million in pipeline debottlenecking and compression at Inga, aimed at reducing some of the line pressure issues experienced with the more liquids-rich wells.
Artek plans on drilling 9.6 net wells in 2014, including 6.8 wells at Inga.
The 2014 budget now includes 16 (9.6 net) wells, including 12 (6.8 net) wells at Inga/Fireweed, and about $10 million for facilities, pipelines, land and seismic. Because of the significance of the production delays experienced during the second quarter and the capital budget increase not occurring until the second half of the year, 2014 average production is now expected to be between 4,300 and 4,500 barrels equivalent per day, with year-end exit production increasing over the prior forecast to about 5,500–5,600 barrels a day, of which 39–40 per cent is expected to be liquids. In the second quarter, Artek’s oil and natural gas liquids output rose by six per cent to 1,376 barrels per day, which represents 37 per cent of total production. During the quarter, the company drilled two (1.2 net) wells at Inga and had capital spending of $16 million, including $600,000 on undeveloped land acquisitions and $700,000 on facilities. Artek’s second-quarter production was down 10 per cent from the fi rst quarter of the year to 3,769 barrels equivalent per day, due primarily to mechanical issues at Inga delaying production on-stream dates until after spring breakup, shaving about 400 barrels per day off the quarter. In the Mulligan area, the company is in the early stages of developing the production methodology for its new Charlie Lake oil play and experienced some production curtailments related to limited water disposal capacity. As a result, Artek had more downtime during the quarter than anticipated (about 200 barrels per day) due to optimizing its artificial lift systems and commissioning its new water disposal facility. In the future, the company expects to see consistently better run times, and the
start-up of its 100 per cent–operated water disposal facility during the second quarter at Mulligan should result in a 50–60 per cent improvement to operating netbacks for the play. Early in the third quarter, Artek completed both wells in the liquids-rich Inga South area of the play with a slickwater frac. The fi rst well at 10-17-087-23W6 (the most southern Doig horizontal well drilled to date) tested at a restricted rate of 2.9 million cubic feet per day of gas and 641 barrels per day of condensate, or 1,086 barrels equivalent per day, at a flowing pressure of 606 pounds per square inch over the last 12 hours of an 89-hour clean-up production test period. The second well located at 04-33-08723W6 tested at 3.7 million cubic feet per day of gas and 1,131 barrels per day of free condensate, or 1,740 barrels equivalent per day, at a flowing pressure of 1,066 pounds per square inch over the last 12 hours of a 56-hour clean-up production test period. The company has drilled two water source wells and has reduced its well completion costs by about 25 per cent, to between $3 million and $3.5 million, on its last three Doig horizontal completions. By the fourth quarter of 2014, the company anticipates it will have enough water disposal capacity to reduce completion costs a further 10 per cent. The company is observing better test and liquids rates on its Doig wells in these early stages of slickwater fracturing in 2014 and expects it will lower declines and increase reserves per well. The company is currently drilling its first Montney well of the year at A-65-I in the Fireweed area and anticipates completing the well using a 30–35-stage slickwater frac program, which will be its highest frac effort to date on the Montney. In addition, Artek is drilling a fourth horizontal Doig well at 11-16-087-23W6 in the Inga South area. — DAILY OIL BULLETIN OIL & GAS INQUIRER • OCTOBER 2014
17
British Columbia
AltaGas and Painted Pony sign processing deal AltaGas Ltd. and Painted Pony Petroleum Ltd. have signed defi nitive agreements to enter into a 15-year strategic alliance for the development of processing infrastructure and marketing services for natural gas and natural gas liquids. The strategic alliance will provide for the development of essential liquids-rich gas processing infrastructure in northeastern British Columbia and will provide preferred access to international energy markets for Painted Pony’s Montney production. In the fi rst phase of the strategic alliance, AltaGas will construct and operate a 198-million-cubic-feet-per-day shallow cut gas processing facility in the Montney resource play, of which Painted Pony will maintain the right to a minimum 150 million cubic feet per day of firm capacity. The Townsend facility will be located roughly 100 kilometres north of Fort St. John and 20 kilometres southeast of the AltaGas Blair Creek facility, through which Painted
18
OCTOBER 2014 • OIL & GAS INQUIRER
198
million cubic feet
Amount of processing capacity being built at Townsend as part of the deal. Pony has already been processing a significant portion of its Montney production. The Townsend facility is estimated to cost approximately $325 million to $350 million, to be constructed and funded by AltaGas, and is expected to be in service by the end of 2015. Commercial operation is subject to regulatory and other customary approvals. In addition to the construction of key gas processing infrastructure, AltaGas will become the primary marketer for Painted
Pony’s natural gas and natural gas liquids production from its northeastern B.C. land base. Painted Pony will become a significant supplier to AltaGas under the strategic alliance, which will provide preferred access to export opportunities for liquefied natural gas and natural gas liquids from existing and planned facilities. Upon completion of the fi rst phase of the strategic alliance, further opportunities for the build-out of additional natural gas and natural gas liquids processing infrastructure in northeastern British Columbia are expected, including a potential secondphase expansion of the Townsend facility, which could include a deep cut system for the enhanced recovery of additional natural gas liquids and fractionation facilities. This will provide added capability to process and transport Painted Pony’s reserves and meet demand for increased processing infrastructure in the region. — DAILY OIL BULLETIN
British Columbia
Terra Energy redevelops B.C. oil play Terra Energy Corp. says the balance of its $14.33-million capital expenditures program for 2014 w ill focus primarily on 28 –32 recompletion operations targeting its t wo key oil plays in the St o d d a r t a n d R e d C r e e k a r e a s o f British Columbia. Approximately $4.51 million of capital has been allocated toward pipeline tie-ins, and the majority of capital spent in the fi rst two quarters was in connection with the Grande Prairie, Alta., and Monias pipeline tie-ins. Both pipeline projects were completed during t he second quarter, and these pipelines are now operational. The company, though, is experiencing delays and curtailments in its production as a result of third-party processor and competing third-party-operated production issues, Terra said in releasing secondquarter results for the three and six months ended June 30, 2014, in which it
GIBSON ENERGY
posted improved earnings, cash flow and revenue for the quarter despite reduced production. The purpose of the recompletions is not only to increase current production and year-end reserves but primarily to increase the level of confidence for the 2015 and 2016 horizontal drilling programs, which are designed to fully exploit these reservoirs, said Terra. The spring breakup and related road bans continued for two weeks beyond what was initially planned, resulting in the recompletion program getting off to a delayed start in the second quarter. The company has completed 10 of these recompletion operations to date, and several of the wells have already been placed on production but not for any extended period. While the results are generally encouraging, Terra said it needs more time in order to fully assess the technical and economic impact.
Second-quarter production of 3,610 barrels equivalent per day (85 per cent natural gas) was down 3.5 per cent from the second quarter of 2013, reflecting a 50.6 per cent reduction in natural gas liquids production to 157 barrels per day from 318 barrels per day the previous year, off set partially by increased oil sales. Terra attributed the decrease to compressor downtime in the Wilder area in June that resulted in a temporary loss of approximately 21,250 barrels equivalent, largely off set by new production at Monias. Production for the six months was down 12.9 per cent to 3,575 barrels equivalent per day from 4,103 barrels per day in the comparable 2013 period, partially as a result of unexpected operational interruptions resulting from extreme temperature and weather conditions in January and February of this year in the Tower, Square Creek, Stoddart, Hamelin and Wilder areas. — DAILY OIL BULLETIN
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NORTHWESTERN ALBERTA WELL ACTIVITY AUG/13
AUG/14
Wells licensed
225
AUG/13
AUG/14
Wells spudded
212
AUG/13
AUG/14
17
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Photo: Joey Podlubny
NuVista’s Montney winter drilling program expected to up 2014 production NuVista Energy Ltd.’s second-quarter 2014 drilling focused mainly on the Montney Formation in the South Bilbo development block where, during the first half of the year, it drilled four wells (four net) with 100 per cent success and completed spending on its Bilbo block compressor station and trunk pipelines. The company is now forecasting an increase in fourth-quarter volumes to a range of 20,000–23,000 barrels equivalent per day from the previous guidance of 20,000–21,000 barrels per day due to excellent ongoing Montney drilling results. The drilling program in the fi rst half of 2014 was focused largely on converting Bilbo economic contingent resources to reserves for the start-up of the new Bilbo block facilities. Also during the second quarter, NuVista achieved two new 30-day initial production (IP30) rates, conducted new facility start-ups and divested of assets. “Although our Wapiti production was highly restricted by both planned and unplanned outages at third-party facilities, NuVista delivered production above the top of our second-quarter-guidance range of 13,000 to 14,000 barrels equivalent per day,” wrote the company in its secondquarter results release. Several of the facility restrictions during the quarter included work on thirdparty facility capacity expansions, which along with new NuVista facilities, lay the foundation for significant growth for years to come, it said. Volumes continue to build behind pipe, which allow NuVista to increase its previously announced fourth-quarter 2014 guidance to between 20,000 and 23,000 barrels equivalent per day.
In addition, an independent evaluation of NuVista’s Wapiti Montney reserves has been updated. According to the company, proved and probable reserves increased markedly through a combination of successful drilling and positive revisions to existing reserves due to outperformance of its initial wells. Despite these substantial increases to reserves and resources, just 14 per cent and 58 per cent of NuVista’s gross Montney landholdings are currently attributed reserves and contingent resources, respectively, it said. NuVista finished drilling, fracture stimulating and testing several additional wells with continued favourable results, said the company.
NuVista is awaiting the construction of processsing facilities as it works through its planned 32-well Montney drilling program.
“As we await the start-up of downstream facilities, it is not possible yet to achieve IP30 rates on a number of wells; however, NuVista expects to have up to 25 wells on production by the end of the third quarter as compared to 16 wells at the beginning of the first quarter,” said the company. NuVista expects to have about 32 Montney wells on production by year-end 2014. Despite temporary facility curtailments, NuVista achieved significant new IP30 production rates on two wells: wells 20 and 21. The company said the IP30 for well 20, at 103/13-25-068-07W6 on the far northeastern corner of NuVista’s Montney position, is significant given the location. “We are strongly encouraged that this initial test has proven the area to be highly condensate-rich, over-pressured and home to some of the lowest drilling and completion costs to date due to slightly shallower depth,” it said. “We are currently drilling an offset location to this well and expect to optimize the completion design to further improve deliverability.” NuVista said well 21 is the strongest Montney well completed on its lands to date. Its IP30, at 2,195 barrels equivalent per day, is effectively equal to the highest of all of NuVista’s wells, but this rate was achieved at a very high flowing pressure of 3,200 pounds per square inch (psi) due to being significantly choked by temporary facility restrictions, it said. “For comparison, our Montney wells typically reach pipeline pressure of approximately 600 psi within the IP30 period,” said NuVista. “This is the best result to date on the Bilbo block and leaves us very encouraged as we look to bring on a number of new Bilbo block wells over the remainder of 2014.” OIL & GAS INQUIRER • OCTOBER 2014
21
Northwestern Alberta
Also during the second quarter of 2014, NuVista started up its large new compressor and dehydration facility in the Bilbo block. This project began production on time, at the end of the second quarter, and on budget. The facility has a design capacity of up to 80 million cubic feet per day of raw gas and 8,000 barrels per day of raw condensate. It is performing very well, said NuVista, and it is essentially idling while awaiting increased downstream capacity via the
SemCAMS K3 plant and the start-up of the new Keyera pipelines to the Simonette plant. The company recognized a material increase to the Montney discovered petroleum initially in place via an updated independent resource evaluation, reaching 7.8 trillion cubic feet or 1.3 billion barrels equivalent, an increase of 40 per cent from the last evaluation completed in October 2013. Reserves increased significantly through Montney additions, reaching 107.1 million
barrels equivalent (33 per cent) on a proved basis and 185.9 million barrels (33 per cent) on a proved-plus-probable basis. The evaluation does not yet include any discovered resources in the Lower Montney zone. The company is targeting 2014 capital closer to the lower end of the previous guidance range of $300 million to $315 million as a result of the deferral of one or two Montney wells. — DAILY OIL BULLETIN
Strategic Oil & Gas boosts reserves 32 per cent in first half of 2014 In this year’s first half, Strategic Oil & Gas Ltd. boosted proved-plus-probable oil and gas reserves 32 per cent, reaching 16 million barrels equivalent (66 per cent oil) after accounting for year-to-date production. Management cited an independent reserves report, dated July 1, 2014, showing significant growth in reserves volume in the company’s Marlowe operating area, where the company has focused on drilling in the Muskeg Formation.
22
OCTOBER 2014 • OIL & GAS INQUIRER
The three Muskeg wells Strategic drilled in the first quarter posted over 95 per cent uptime and are performing at or above type curve, management said. Sales volumes in the quarter fell 10 per cent from last year’s period due to no new tie-ins, and about 9,000 barrels of oil production at Marlowe was used to fi ll the sales oil pipeline. The sale of about 90 barrels equivalent per day of non-operated production also went through during the quarter.
While production fell about 10 per cent in the quarter, it was roughly flat in the first half of 2014 compared to last year, as higher natural gas volumes offset lower crude oil production. While posting flat revenue in the second quarter, Strategic saw revenue grow nine per cent in the year-to-date period. On June 13, Strategic started its summer Muskeg drilling program and has since drilled three wells and spud a fourth. The company made changes to the Muskeg
Northwestern Alberta
well design that have proven successful at cutting drilling times and costs while boosting production rates. As a result, management said the company is well ahead of schedule and expects to have five Muskeg wells drilled and on stream by the end of the third quarter, with one rig expected to remain active for the rest of the year. The Muskeg 11-24 well, the fi rst well drilled post breakup on the western rim at Marlowe, was drilled and completed with a 13-stage frac. Over its first 25 days, the well produced at a rate of 487 barrels equivalent per day (63 per cent oil), management said. By comparison, the previous Muskeg 10-24 well was drilled and completed with a 15-stage frac before spring breakup.
Average production rates in the first 30 and 90 days were 560 and 420 barrels equivalent per day, respectively. In all, the well has produced 38,600 barrels equivalent (60 per cent crude oil) in three months and is outperforming the company’s estimates. Capit a l e x pendit u res sl ipped to $13.54 million in the quarter from $14.79 million in last year’s period. Spending went to the company’s sales oil pipeline, related infrastructure, completion of the 10-24 Muskeg well drilled in this year’s first quarter, and start up of Strategic’s summer 2014 drilling program in June, the company said. Strategic also recently closed a sale of non-core oil and gas assets in southern
Alberta for about $3.5 million. The sold assets consisted of two sections of land and about 90 barrels equivalent per day of production (94 per cent natural gas and associated liquids). Proceeds were allocated to the company’s Muskeg stack development at Marlowe, management said. About two-thirds, or 10.49 million barrels equivalent, of Strategic’s provedplus-probable reserves consist of light and medium crude oil, according to the independent reserves evalu-ation completed for Strategic by McDaniel & Associates Consultants Ltd. The remaining reserves consist mainly of natural gas. — DAILY OIL BULLETIN
Tourmaline ramping up at Charlie Lake Tourmaline Oil Corp. continues ramping up production at its Peace River High Charlie Lake oil complex. Current production at the company’s oil complex is 12,000 barrels equivalent per day, with about 5,000 barrels per day of
additional volume awaiting facility access. With the start-up of its new Spirit River 03-10 gas plant early in the fourth quarter and with additional tie-ins, the complex should yield a 2014 exit production level of 18,000–20,000 barrels equivalent per day.
Tourmaline has drilled 82 Charlie Lake horizontal oil wells, with no dry holes in the complex thus far, and three active rigs are expected to add about 45 new horizontals per year. Completed and stimulated well costs average about $4.5 million. The company
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Northwestern Alberta
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OCTOBER 2014 • OIL & GAS INQUIRER
will complete seven additional concurrently stimulated well pairs prior to year-end 2014, with 10 additional pairs planned in 2015. The company’s 2014-15 Peace River High Charlie Lake infrastructure plan allows 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, followed by the Mulligan oil battery, of which the first 8,000-barrel-per-day phase will be operational by spring breakup 2015. Tourmaline is also pursuing a complementary series of water disposal, oil blending and direct oil tie-in opportunities to continually improve its netbacks. Year-todate, the company’s Spirit River-MulliganEarring complex operating costs are about $14.83 per barrel equivalent, which management anticipates will drop to $10 per barrel over the next several quarters when a new infrastructure plan is implemented. — DAILY OIL BULLETIN
Pinecrest continues Slave Point remediation efforts During the second quarter , Pinecrest Energy Inc. continued remediation efforts on certain producing wells and deferred capital spending on all new drilling. The company’s current strategy is to limit capital spending, maintain relatively flat production and use excess cash flow to repay debt while monitoring the performance of its waterfloods and remediation efforts. The company said its technical team has furthered its understanding in the Slave Point reservoir and has identified pumping limitations they believe contribute to the reduced production performance in some of its horizontal wells. With an understanding of these reservoir effects, the company has begun to implement a remediation plan to address these potential limitations. Pinecrest continues to maintain voidage and monitor the performance of its seven operated waterflood schemes. Early production gains followed by setbacks on certain waterfloods are being addressed. The company said it will undertake remedial action as required.
Northwestern Alberta
It is encouraged by the positive increase in oil production that has been sustained for five months, resulting from the firstquarter treatment on the Evi #2 03-32-08711W5 well. Field estimates for July show the well producing at 31 barrels of oil per day with an 88 per cent water cut and production of about 50 barrels of oil per day with an 84 per cent water cut during the first three weeks of August. Evi #2 and Evi #3 waterfloods continue to demonstrate the low-decline, long-life nature of the Slave Point reservoir in the Red Earth area, the company said. While further production monitoring and additional time is required to fully substantiate the early and encouraging remedial treatments, Pinecrest is cautiously optimistic that the results and learnings can be applied to its large drilling inventory with improved capital efficiencies. Besides remediat ion t reat ments, Pinecrest is looking at more cost-effective and potentially improved initial completion techniques to be undertaken when its drilling program resumes. With lower capital costs for new wells and improvement in production, Pinecrest believes positive steps are being taken to unlock the large oil resource in the Greater Red Earth area. — DAILY OIL BULLETIN
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Seven Generations production skyrockets Production for Seven Generations Energy Ltd. averaged a record 23,999 barrels equivalent per day in the second quarter, just under four times the average output of 6,182 barrels per day in the comparable 2013 period. The private company also reported record cash flow of $65.97 million for the three months ended June 30, 2014, up from $9.22 million last year. During the second quarter, Seven Generations drilled 15 wells with an average horizontal lateral length of approximately 2,700 metres, completed nine wells and brought seven new wells on production. The company, which is developing the Kakwa River project in northwestern Alberta, also increased its active drilling rig count to nine rigs during the quarter from seven rigs at the beginning of the year.
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25
Northwestern Alberta
During the second quarter of 2014, the company completed a number of land transactions that resulted in a net acquisition of 107 sections of Montney land. These transactions bring its total acreage position to 547 net sections, including 516 net sections of petroleum and natural gas rights in the Montney Formation, a 29 per cent increase since the beginning of 2014. Net capital investments for the quarter totalled $219.12 million, with approximately 71 per cent invested in drilling and
completions and 16 per cent in facilities and well equipment. At the end of the second quarter of 2014, the company entered into an agreement to double previously contracted rich gas delivery volumes on the Alliance Pipeline system and through Aux Sable Liquid Products Inc.’s extraction and fractionation facilities. Contracted volumes will increase to 500 million cubic feet per day in the fourth quarter of 2018 from 250 million cubic feet per day in the fourth quarter of 2015.
Subsequent to the second quarter of 2014, Seven Generations announced the results of its independent reserve evaluation, effective July 1, 2014, from Mc Da n iel & A ssoc iates Consu lta nt s Ltd. Proved-plus-probable (2P) reserves increased 129 per cent to 649.1 million barrels equivalent (328 million barrels proved). The 2P liquids weighting also increased to 55 per cent from 51 per cent at the end of last year. — DAILY OIL BULLETIN
High North grows Montney production In July, Montney oil production sales were up 30 per cent from June 2014, to 8,400 barrels per day, High North Resources Ltd. has reported. As of July 30, 2014, the company had sold more than 55,900 barrels of oil and increased its field netback to approximately $45 per barrel of oil. Gas is currently being f lared, while High North moves forward with the installation of
facilities to conserve gas and recover liquid by-products. The company has completed installation of larger surface equipment at the 09-03076-21W5 surface pad (the 08-02, 09-02 and 16-02-076-21W5 producing wells) and at the 12-21-076-21W5 surface pad (which services the 08-21-076-21W5 producing well) and expects to recover clean oil and water by the end of September.
High North said it is encouraged by the amount of Montney pay zone encountered at each of the step-out drilling locations to date. The company intends to continue to de-risk the play by drilling stepout locations in sections 09-076-21W5 and 17-076-21W5, subject to approval of fl ared volumes by the Alberta Energy Regulator. — DAILY OIL BULLETIN
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NORTHEASTERN ALBERTA WELL ACTIVITY AUG/13
AUG/14
Wells licensed
146
AUG/13
AUG/14
Wells spudded
103
AUG/13
AUG/14
110
Rigs released
▼
▲
▼
Source: Daily Oil Bulletin
N.E.
Northeastern Alberta
Pollution-monitoring triggers exceeded in oilsands mining region By Lynda Harrison
A recently released Government of Alberta report says air and surface water pollution in the Athabasca oilsands region triggered exceedances at monitoring stations in 2012. Ten air monitoring stations had nitrogen dioxide (NO 2) or sulphur dioxide (SO2) above trigger levels, while at one water monitoring station, triggering levels were exceeded for total nitrogen, dissolved uranium and dissolved lithium. Trigger levels that were exceeded were well below the limits, said Duncan MacDonnell, public affairs officer for Alberta Environment and Sustainable Resource Development (ESRD). “ T here seems to be some conf usion out there that—and perhaps this is our fault for releasing a fairly technical report—but there seems to be some feeling that air pollution is increasing and that we’re in danger here, and that’s really not the case,” said MacDonnell, adding some media reports indicate misunderstanding. “They’re just indicators,” he said. “The triggers are not science-based—the limit is. They’re management triggers to give stakeholders time for proactive measures to avoid an exceedance of the limit.” The report says it fulfills a commitment made in the Lower Athabasca Regional Plan to initiate a management response when a n nua l assessments indicate that triggers or limits have been exceeded. Reporting was done under the Air Quality Management Framework for NO2 and SO2 and the Surface Water Quality Management Framework for the Lower Athabasca Region.
The next steps are to continue evaluating the need for action on the observed trigger exceedances. ESRD says it will determine the need for further investigation to identify potential management actions and will involve stakeholders. Pointing to one monitor’s SO2 exceedance, MacDonnell said that since that reading was taken, Syncrude Energy Inc. has installed scrubbers. “So we may not have a problem there anymore, if it was even a problem in the first place,” he said. A further report updating the status of the management response is to be made publically available by the end of 2014 on ESRD’s website. An initial investigation is underway and includes the identification of potential emissions sources and a preliminary analysis of NO2 and SO2 at monitoring stations. Initial steps that were undertaken in the investigation to date include locating stations and emissions sources according to 2013 National Pollutant Release Inventory (NPRI) data. ESRD has also performed a statistical analysis of episodes with SO2 and NO2 hourly measurements that exceeded triggers for the upper range of the hourly data to determine the meteorological conditions under which higher concentrations of SO2 and NO2 were observed in 2012. T he report suggests that because enhanced levels of NO2 were observed most frequently under low wind speeds and during winter, NO 2 accumulates when meteorological conditions are stable and pollutants are not dispersed effectively.
It also says elevated levels of NO 2 occur primarily during morning and evening rush hours, pointing to local traffi c as the culprit. “The Level 2 triggers at Albian Muskeg R iver, Millennium, CNR L [Canadian Natural Resources Limited] Horizon, Fort McKay and Syncrude [Canada Ltd.] UE1 Stations all appear to be affected by 24-hour industrial sources, which could include facilit y point sources as well as mobile emissions from mine f leets,” it says. ESRD is also beginning to assess the 2012 levels in the context of previous yea r s t h roug h t he qua l it at ive a nalysis of the annual average of the hourly data and upper range of the hourly data for 2003-12. ESRD is identifying the emissions reduction programs that are currently in place or planned for the future and are identifying future pressures in the region. Next steps may include identifying specific periods with enhanced SO2 at the Level 3 stations and investigating the causes of these individual events. This study could include information on facility upsets and meteorological conditions. ESRD may also conduct a detailed assessment of the variation of NO2 and SO2 ambient levels since 2003. This study could be performed in the context of point source emissions estimates for 2004-11 from the NPRI, population changes in Fort McMurray, the growth and development of industrial facilities and the past implementation of emissions reduction technologies in the oilsands. Also under consideration is consulting with subject matter experts to determine whether air quality models could contribute to the understanding of ambient SO2 levels in the region. This would include the identification of previous modelling studies that may have relevant results as well as the OIL & GAS INQUIRER • OCTOBER 2014
29
Northeastern Alberta
Mile One Centre, St. John’s, Newfoundland & Labrador
consideration of a new modelling study. If a new modelling study is deemed useful, the resource requirements could be assessed. ESRD may also assess the need for additional monitoring. Amin Asadollahi, oilsands program director at the Pembina Institute, a nonpartisan clean-energy think tank, said the evidence that some of Alberta’s air quality trigger limits have been exceeded requires immediate management action. A commitment by the province to implement measures to reduce pollution is also necessary in light of expected oilsands expansion, he added. “When air pollution is serious enough to exceed these trigger limits, it is supposed to prompt management action to reduce pollution from industrial facilities to ensure we don’t exceed any of the hard limits set for the region—simply doing more monitoring and investigation is not enough,” he said. “Industry modelling shows that maximum legal air quality limits are projected to be exceeded in coming years if oilsands expansion proceeds as planned.”
Suncor continues to find markets for crude By Paul Wells
@petroleumshow
30
OCTOBER 2014 • OIL & GAS INQUIRER
Suncor Energy Inc.’s top executive says the company continues to successfully skirt market access issues and has excess pipeline capacity to handle future production growth. Speaking in New York City at the Barclays Capital CEO Energy-Power Conference, president and chief executive officer (CEO) Steve Williams said the company’s integrated business model and focus on ensuring strong market access continue to pay off. “Market access has been a big part of the discussion around oilsands. In the past few years, we’ve spent considerable time and effort enhancing what for us is a deep midstream ability,” he said. “We invest in—and operate—a network of pipes and have secured shipping rights on a number of other lines. We’ve got significant storage ability across this continent, and we also have rail facilities. And we’ve been an operator of rail facilities for
Northeastern Alberta
40 years, so we’ve got lots of experience in all those aspects of market access.” Williams said the progress made on the market access front is encouraging and noted that the company has been able to lower the feed costs to its Montreal refinery. Suncor increased rail shipments of inland-priced crudes to the Montreal refinery to 36,000 barrels per day in the second quarter of 2014 and continued marine shipments of lower-priced crudes from the U.S. Gulf Coast to the Montreal refinery when market conditions were favourable. “We moved an average of 45,000 barrels per day of low-cost inland crude in there through a combination of rail and shipping through the Gulf Coast. For those volumes, we realized an average benefit of over $7 per barrel,” he said. Although TransCanada Corporation’s proposed $5.4-billion Keystone XL pipeline continues to face opposition and delays south of the border, Williams said the pipeline, which would connect western Canada’s oilsands with Texas oil refineries, is not currently essential to Suncor’s growth plans. “I often get questions on Keystone XL, and I answer them in two ways. The first way, just as a Canadian, I believe that pipelines need to be built. Pipelines are the safest, most environmentally effective way to transport oil. And yet, as CEO of Suncor, I’ve often pointed out that an individual project like Keystone XL is not critical to our plans to get our products to market, nor is it hampering our efforts to expand our production,” Williams said. “That is in part due to the choices we’ve made. By the end of 2014, we expect to be able to deliver more than 600,000 barrels per day to our refineries and other globally priced markets across North America, which is significantly above our current production rates.” In fact, Williams said that as part of the company’s day-to-day business, Suncor often trades some of its market access capability. “We will have the ability to potentially trade around Quebec, we will have the ability to trade around the Gulf…and we’ve been doing that,” he said. “On Keystone south, which is already operational, we are one of the few companies who have contracted volumes on there, and we have 70,000 barrels a day. And we’ve been trading that volume because we don’t need it to get our barrels to market as we speak today, but in the future, we have that capability available to us.”
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SIGNATURES
31
CENTRAL ALBERTA WELL ACTIVITY AUG/13
AUG/14
Wells licensed
211
AUG/13
AUG/14
Wells spudded
215
AUG/13
AUG/14
217
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
C.A.B. Central Alberta
Peyto reaches Deep Basin milestone By Paul Wells
Photo: Joey Podlubny
Natural gas–weighte d ju n ior Pey to Exploration & Development Corp. reached an impressive milestone in August when it spud its 1,000th well at 16-28-054-21W5 in Sundance, Alta., entrenching the company’s place as one of the most prolific Deep Basin drillers. Remarkably, this location is directly adjacent to Peyto’s original recompletion in Sundance at 15-30-054-21W5, which continues to produce some 15 years later. Darren Gee, president and chief executive officer, told the company’s second-quarter conference call that the achievement speaks volumes as it places
Peyto drilled 31 Deep Basin wells in the second quarter of 2014.
his smaller company in the same league as some industry heavyweights in terms of Deep Basin drilling. “It’s pretty cool. There are not a lot of companies in the industry that have drilled that many wells over the last 15 years in the Deep Basin,” he said. “I t h i n k we’re t he fou r t h most active driller behind companies like C o n o c o[ Ph i l l ip s C a n a d a], E n c a n a [Corporation], and CNR L [Canadian Natural Resources Limited], which is pretty lofty company, especially considering that we’ve only got 46 people here at Peyto, and that’s probably less people than those companies have in their IT department.” Over the last five years, Gee said that Peyto has drilled over 400 natural gas wells, making the company the most active Alberta Deep Basin gas driller. Gee added that because of Peyto’s efforts, there’s no question that the company’s Sundance area has become one of the “premier natural gas areas” in the province. “You kind of have to wonder if it’s such a premier area because it was always going to be one of those or is it because we made it one of those because we’ve continued to focus on that area for 15 years now?” he said. “I think it’s the latter, and I think it’s one of the reasons Peyto is so successful with our strategy, because we don’t just do what we see there today and then move on. We continue to dig around and focus on the same areas for new opportunities over and over again, year after year.” Production in the second quarter of 2014 increased 24 per cent to 72,302 barrels equivalent per day from 58,145 barrels per day during the comparable period last year. Natural gas production averaged 388.41 million cubic feet per day in the second quarter of 2014, 25 per cent higher
than the 310.62 million cubic feet per day reported for the same period in 2013. Oil and natural gas liquids production averaged 7,568 barrels per day, an increase of 19 per cent from 6,374 barrels per day reported in the prior year. The production increases are attributable to Peyto’s capital program and resulting production additions. While new production additions off set the base well declines, overall production growth was partially impeded by downtime and unscheduled disruptions caused by higher sales line pressures and power outages.
72,302
barrels equivalent per day Amount produced by Peyto in the second quarter.
“We certainly had a more active second quarter this year compared to last year. Most of Peyto’s 31 wells drilled during the quarter focused on the greater Sundance area, where we took advantage of our existing infrastructure to drill through breakup,” said Jean-Paul Lachance, vicepresident of exploitation. The majority of the wells were drilled in the Wilrich and Falher members of the Spirit River Formation. “The initial production performance of that program as a whole has exceeded expectations, and the group is now adding a net 23,000 barrels equivalent per day to our production.” Over the course of the second quarter, Peyto spent $68.5 million to drill the 31 (28.2 net) horizontal wells and $48 million to complete 30 (28 net) wells. Additionally, 32 (29.8 net) wells were brought on stream with $10.3 million of wellsite equipment and gathering pipelines. Major facilit y capital investment amounted to $16.3 million and included OIL & GAS INQUIRER • OCTOBER 2014
33
Central Alberta
the installation and commissioning of an eighth compressor at the Wildhay gas plant (adding 10 million cubic feet per day of capacity), the twinning of the Wildhay sales pipeline (providing 35 million cubic feet per day of additional sales gas transmission capacity), the installation of a large gathering line between the Oldman and Nosehill plants to take advantage of spare
and fabrication for the planned Oldman North plant expansion (adding 40 million cubic feet per day with expected start-up in October). During the second quarter, Pey to invested $5.9 million at Alberta Crown land sales on highly prospective Wilrich lands adjacent to the company’s existing Deep Basin land position. A total of
Well results throughout all geographic areas and across all zones, particularly the Notikewin, Falher and Wilrich members in the Sundance, Obed and Ansell areas, have provided steady growth from an average of 71,500 barrels equivalent per day in April to an average of 74,800 barrels per day in July. More recently, August daily production has averaged 78,500 barrels
“It’s pretty cool. There are not a lot of companies in the industry that have drilled that many wells over the last 15 years in the Deep Basin.” — Darren Gee, president and chief executive officer, Peyto Exploration and Development Corp.
Nosehill plant capacity, and the commissioning of a fourth compressor at the Swanson plant (adding 18 million cubic feet per day). A refrigeration plant and an additional compressor were also installed at the Brazeau River gas plant (adding 10 million cubic feet per day). Lastly, $1 million was directed toward preparation
11 net sections (containing 34 internally identified new drilling locations) were added for $833 per acre. Cont i nuous operat ion s, t h rough breakup and into the summer months, have been highly successful in accelerating the 2014 capital plans, resulting in strong production growth over the past two months.
per day. Peyto remains on track to meet or exceed previous guidance of $625 million of capital and exit production of 81,500 barrels equivalent per day. Currently, the company has all nine of its drilling rigs active, with four completion spreads following up, and anticipates maintaining this activity level through to year-end.
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OCTOBER 2014 • OIL & GAS INQUIRER
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Whitecap paying $267 million for Elnora oil assets Whitecap Resources Inc. will pay about $266.7 million for a controlling interest in a producing property near Elnora, Alta., management said in August. Whitecap agreed to acquire the interest in a deal that would add 2,470 barrels per day of production (90 per cent oil and natural gas liquids, or NGLs), most of which is linked to the Elnora Nisku light oil pool. Whitecap did not quantify the interest it’s acquiring as a percentage of the total. L ocated about 50 m i les east of Whitecap’s Garrington core area, the Elnora Nisku pool was discovered in December 2011, has been delineated with 3-D seismic and includes 16 producing vertical oil wells, management said. Currently, gross production from the pool is capped at 2,470 barrels of oil per day until an application for a waterflood is granted by the Alberta Energy Regulator (AER). In a press release, Whitecap said efforts to make that application have been prolonged because the six parties involved
could not agree on a common unitized pool working interest. However, due to Whitecap’s pending acquisition, the number of parties with interests in the pool has been cut to two from six, and Whitecap believes it can now accelerate the application process. As a result, management expects the AER’s production cap to be lifted and a waterflood to be in place by mid-2015. “With the waterf lood in place, we expect to be able to increase our net production in the pool by 145 per cent to 4,900 barrels equivalent per day with minimal capital spending,” the company said. The Elnora Nisku pool is light (35 degrees API), sweet oil with less than fi ve per cent (1.3 million barrels) recovered to date. A field simulation of the property has been done by an engineering fi rm that predicts an ultimate recovery of 65 per cent of the discovered oil originally in place. The internal reserves assigned to the Elnora pool reflect a 36 per cent and
47.5 per cent recovery on a proved and proved-plus-probable basis, respectively, Whitecap said. Based on a third-party report, Whitecap said the Elnora holds about 9.37 million barrels (94 per cent light oil and NGLs) of proved reserves and estimated provedplus-probable reserves of 13.63 million barrels (94 per cent light oil and NGLs). Whitecap said the “outstanding” production capability of the Elnora wells and reservoir and the waterflood support will lead to very low production declines. Based on the computer simulation, the company predicted declines would be fl at until the production cap is removed and the waterflood completed. After that, the simulation predicts pool production declines would be flat for the first two years and eight to 16 per cent per year thereafter, the company added. Capital spending of $4 million on the assets this year will be focused on drilling one well at Elnora and consolidating and
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expanding facilities for the upcoming production cap removal, as well as production optimization initiatives. In addition to the Elnora Nisku asset, Whitecap said it acquired production of 513 barrels equivalent per day (57 per cent oil) of medium-grade oil (28 degrees API) in the Killam area of Alberta. In that region, the company said 31 locations have been identified, of which 14 have been booked in the reserves evaluation. — DAILY OIL BULLETIN
Glacier production at record levels, says Advantage Oil & Gas Advantage Oil & Gas Ltd. reported an 81 per cent increase in funds from operations, driven by record production at Glacier in the second quarter. Funds from operations for the second quarter of 2014 increased to $42.56 million from $23.49 million in the prior year’s period. Production climbed to 22,685 barrels equivalent per day during the April-to-June period from 19,966 barrels per day during the second quarter last year. Production from the previous Phase 6 and older wells continues to outperform expectations, thereby reducing the pace at which the company planned to add new wells to offset natural production declines. At this time, Advantage has roughly 53 million cubic feet per day of excess well deliverability from its inventory of Phase 6 and older standing wells compared to current production of 136 million cubic feet per day. These standing wells will be used as required to maintain current production. Additionally, the last Phase 6 pad consisting of four Lower Montney wells, is currently being completed. Upon completion of the 100 per cent–owned Glacier gas plant expansion, some of the new Phase 7 wells will be used to ramp up production to 183 million cubic feet per day by June 2015. A total of 13 previous Upper and Lower Montney wells completed with slickwater and modified completion techniques continue to produce at or above Phase 7 budget type curve (based on an average initial 30-day production rate of 6.9 million cubic feet per day). The top performing wells are trending toward cumulative production of over two billion cubic feet after 12 months, which results in a simple payout of less than 10 months, based on Advantage’s second-quarter 2014 operating netback. Advantage’s record liquids-rich Middle Montney well, located at 12-02-076-12W6, continues to flow at a restricted rate of 6.5 million cubic feet per day after 150 days of production. This well was tested at an average free condensate yield of 20 barrels per million cubic feet and is estimated to recover 42 barrels per million cubic feet of propane-plus liquids when processed through a shallow-cut liquids extraction process. The 12-02-076-12W6 well has been restricted to control the amount of free condensate that the company’s facilities handle at this time since the Glacier gas plant does not currently have liquid extraction or condensate stabilization processes installed. Advantage’s current Phase 7 Glacier development program is designed to grow production to 183 million cubic feet per day by June 2015, including the extraction of natural gas liquids at the Glacier gas plant. A total of 33 Phase 7 wells are being drilled to
Central Alberta
Exclusive Authorized Distributor create a new well inventory to support the future ramp-up and sustainment of production at 183 million cubic feet per day. To date, 11 new Phase 7 wells have been drilled and rig released. Drilling operations are progressing on schedule with three drilling rigs active at Glacier. Completion operations on new Phase 7 wells are planned to begin during the third quarter of 2014. — DAILY OIL BULLETIN
Journey reports discovery at Windfall Journey Energy Inc. says its Windfall 10-10-060-14W5 horizontal well, completed over 18 intervals in the Beaverhill Lake Group and production tested from August 9 to August 22, produced 5,416 barrels of 44-degree API oil and 30.6 million cubic feet of raw gas during a 30-hour extended test. Final flow rates for the last 24 hours of the test were 320 barrels per day of oil, two million cubic feet per day of raw gas and 250 barrels per day of water at a flowing pressure of 300 pounds per square inch. The produced raw gas was liquids rich, and recoveries of approximately 50 barrels of natural gas liquids (NGLs) per million cubic feet of raw gas were calculated from the gas analysis. If processed through a facility, this test rate equates to approximately 700 barrels equivalent per day (60 per cent oil and NGLs). Water cuts followed a declining trend and decreased throughout the test from 100 per cent to a final water cut of 44 per cent. The gas analysis showed 2.4 per cent CO2 and 0.9 per cent hydrogen sulfide (H2S). Given the H2S concentration and the lack of acid gas processing on the north side of the Athabasca River, Journey is reviewing tie-in options for the well and a long-term development plan for the resource. As a result, the Windfall well is not included in Journey’s 2014 or 2015 production guidances. Further capital requirements and added volumes for Windfall will be determined once the development plan is complete and will be included in the company’s 2015 guidance. Drilling of the 10-10 well will earn and validate 22 sections of land (100 per cent working interest), and the pool is thought to extend over the majority of these sections. This play represents a potentially significant resource for the company, and there are no reserves currently attributed to the Windfall pool in Journey’s 2013 year-end reserve report, Journey wrote in a press release. The Windfall well cost $4.4 million to drill and complete. Journey expects reductions in drilling and completion costs with larger drilling programs as the field is developed. Journey says its production from recently drilled wells has exceeded budgeted rates and it is in a position to meet exit guidance of 11,200 barrels equivalent per day without Windfall. August production was in excess of 11,000 barrels per day from field receipts, and the company continues to add new production over and above declines. Guidance for the third quarter remains on track at 10,600 barrels equivalent per day. — DAILY OIL BULLETIN
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SOUTHERN ALBERTA WELL ACTIVITY AUG/13
AUG/14
Wells licensed
70
AUG/13
AUG/14
Wells spudded
4
AUG/13
AUG/14
4
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
Photo: Joey Podlubny
Hemisphere reports Atlee Buffalo success Hemisphere Energy Corporation says it is “extremely encouraged” by the success of its horizontal wells in Atlee Buff alo in southeastern Alberta, where it had a record five-well summer drilling program, and the associated robust economics. In the second quarter of 2014, the company increased its average daily production by 36 per cent over the second quarter of 2013 to 553 barrels equivalent per day (82 per cent oil and natural gas liquids), attributing the increase to the addition of two oil wells in Jenner and one oil well in Atlee Buffalo that were drilled in the fi rst quarter of 2014. Gas volumes increased as a result of new wells and the installation of a solution gas compressor at the Jenner production facility in the second quarter of 2014, which has increased gas volume throughput. The company’s next phase of drilling is to start in late September with up to four more horizontal wells in Atlee and one vertical test well in Jenner, east of Brooks in southeastern Alberta. With just two of the five wells from the summer program having been on production for more than 30 days, Hemisphere’s output during the first three weeks of August increased to an average of 670 barrels equivalent per day. T he remaining three wells were brought on production early in the fourth week of August. The largest drilling campaign in company history, it was executed on schedule and 10 per cent under budget. The program followed up Hemisphere’s fi rst successful Atlee Buffalo well drilled in the fi rst quarter of 2014, which has already produced over 16,000 barrels equivalent and is still producing around 66 barrels per day.
Hemisphere’s first two wells of the summer program were drilled from the same surface pad location as the company’s original well and were completed, equipped and placed on production approximately four weeks after drilling operations fi nished. The wells targeted the oil-bearing sandstones of the Glauconitic Formation and encountered excellent reservoir along the horizontal sections.
Hemisphere is targeting the Glauconite Formation in southeastern Alberta.
These two new horizontal wells have now been on production for over 30 days and are producing within Hemisphere’s forecast range. Current rates are approximately 100 barrels per day (93 per cent oil) and 65 barrels per day (88 per cent oil). The remaining three new horizontal wells were drilled from a second surface pad location where drilling operations fi nished in mid-July. These wells also encountered excellent reservoir and were recently placed on production following the completion, equipment and tie-in of operations, said Hemisphere. Production data will be released once stabilized rates have been achieved and results are available. I n t h e t h i r d q u a r t e r o f 2 014, Hemisphere closed an acquisition in the Atlee Buffalo area that included an 85 per cent working interest in 1.75 sections (1,120 acres) of land adjacent to the company’s existing land base. The company now has close to 100 per cent working interest in 10.5 contiguous sections covering two significant Glauconitic oil pools with current recovery factors of less than five per cent. Hemisphere is reviewing the recent introduction of the Enhanced Oil Recovery Program announced by Alberta Energy this summer. The Alberta government is encouraging the use of enhanced oil recovery methods to optimize hydrocarbon resources in the province. “It is believed that the changes are very positive and may aff ect the type of pressure maintenance scheme ultimately implemented at Atlee Buffalo,” said Hemisphere. — DAILY OIL BULLETIN OIL & GAS INQUIRER • OCTOBER 2014
39
Southern Alberta
LGX ups exit production, capital expenditures
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LGX Oil + Gas Inc. reported it now expects average production of approximately 1,000 barrels equivalent per day for 2014 with exit production of 1,500 barrels per day, approximately 67 per cent higher than 2013 exit production guidance. In addition, the company announced it has spud the fi rst horizontal well in its 2014 Alberta Bakken development drilling program. LGX spud the fi rst well (15-25-008-24W4) of a budgeted two-well horizontal drilling program on Aug. 13, 2014, targeting the Big Valley Formation with fi rst production anticipated in the fourth quarter of 2014. This well off set LGX’s highly successful 14-02 well drilled in late 2013. The company will now drill the 15-25 well at 100 per cent working interest and expects to also drill the second well at 100 per cent working interest. The company now anticipates it will spud the second well in mid-September, immediately following rig release of the first well, with first production anticipated late in the fourth quarter of 2014. These wells were delayed slightly from the original budget due to the late arrival of the drilling rig. To account for the increase in working interest, as well as additional scope in the completions of the wells, the company now expects capital spending in 2014 to be approximately $18.5 million. To fund this program, LGX has entered into a new banking facility with ATB Financial, consisting of a $20-million revolving demand credit facility and a $10-million non-revolving term credit facility. The features of the term credit facility include a two year committed term (subject to extension upon mutual consent) available in two tranches with full payment of the principle on maturity. The term credit facility is subject to fi nancial and reserve-based covenants. The new facility replaces the previous $25-million facility. The revolving portion of the new facility is a borrowing base facility subject to annual review by the lender, with the next review scheduled for no later than May 31, 2015. The new credit facility provides the company with a significant increase to its fi nancial flexibility in conducting its operations. — DAILY OIL BULLETIN
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OCTOBER 2014 • OIL & GAS INQUIRER
Newly public Journey tops 11,000 barrels equivalent per day Journey Energy Inc., until recently a private company, reported record production during the second quarter due to a major acquisition from a senior producer, which closed in March. In June, Journey began the most active drilling program in its history. Its 2014 capital program is set at between $90 million and $95 million.
Southern Alberta
Sixty per cent of Journey’s exploration and development budget is to be spent from June through to October. In this period, the company will have up to four active (three operated) drilling rigs. Journey is currently in the middle of a four-well program in its Keystone Cardium unit (52 per cent working interest) and a threewell program in Herronton (100 per cent working interest). Journey became a publicly traded entity on June 19 when its shares were listed on the Toronto Stock Exchange. The dividendpaying corporation is focused on conventional, oil-weighted operations in western Canada. The company raised $166 million in net proceeds through an initial public offering. The company said its drilling inventory exceeds 10 years at current activity levels. In the second quarter, Journey continued to focus on its southern Alberta core area with the drilling of seven (six net) wells. The second quarter capital program was heavily weighted to June. Journey also completed a three-well program in Matziwin (100 per cent working interest) and took part in a three-well program in the Countess/Brooks area (50 per cent working interest) in the second quarter. All of these wells have been successful.
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Number of unbooked Glauconite wells in southern Alberta belonging to Journey.
During the same quarter, the company established productivity in the Glauconite Formation in East Matziwin and Countess, two pools containing over 30 unbooked, 100 per cent working interest drilling locations. A 100 per cent working interest Glauconite well in the East Matziwin area was recently brought on stream at a restricted rate of 400 barrels equivalent per day. Journey has identified over 13 off setting locations to this well and has no reserve bookings to date in East Matziwin. Based on this success, Journey has added a second East Matziwin well to its fourth-quarter drilling program. Also, a partner-operated well was successfully completed in the Glauconite zone in Countess. Journey said this well is near its 100 per cent land block where it has identified 20 unbooked locations. Journey plans to start a three-well drilling program (100 per cent working interest) in Countess in September. In its Herronton area, Journey added more land during the second quarter with a combination of Crown purchases and freehold leases. The company’s footprint has expanded in the area to more than 31 sections, more than triple what it had when the pool was acquired in 2013. Journey recently tested the first two wells of a three-well drilling program. It expects both of these wells will be brought on stream with 30-day initial production rates topping 400 barrels equivalent per day per well. — DAILY OIL BULLETIN OIL & GAS INQUIRER • OCTOBER 2014
41
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SASKATCHEWAN WELL ACTIVITY AUG/13
AUG/14
Wells licensed
257
AUG/13
AUG/14
Wells spudded
35
AUG/13
AUG/14
404
Rigs released
▲
▼
▲
Source: Daily Oil Bulletin
S.K. Saskatchewan
Photo: Gerald Ford
Northern Blizzard production climbs Northern Blizzard Resources Inc. kicked off its fi rst week as a publicly traded company with a quarterly report that showed an average production of 19,890 barrels equivalent per day for the first half of 2014, representing a 12 per cent increase from the same time frame last year. Management mainly attributes improved production to the drilling of new oil wells, including a Viking light oil development at Smiley. Natural declines and seasonal maintenance at a number of areas during the second quarter partially offset increases. The company’s forecast capital expenditures for the entirety of 2014 are about $255 million, with an average production forecast of 20,500–21,500 barrels per day for the year. While production at mid-year was below Northern Blizzard’s annual guidance range, management expects 2014 production to be within guidance thanks to new developments coming on stream in the second half of the year. “It is notable that we have drilled our 1,000th well since acquiring the assets in July 2010, all with about a 98 per cent success rate,” John Rooney, chair and chief executive officer, told the second-quarter conference call. While the company is almost five years old, its public debut came in August after completing an offering of 26.32 million common shares, priced at $19 per share, for total gross proceeds of $500 million, conducted by way of a $350-million treasury offering and a $150-million secondary offering by existing shareholders. “We will be diligent and work hard in making sure you make a good return on your investment,” Rooney said. Capital expenses totalled $54.89 million in the second quarter and $126.94 million for the fi rst six months of 2014, compared to $37.98 million and $107.15 million for the same periods one year prior.
During the first half of the year, the company’s drilling, completion and equipping budget totalled $65.2 million, which included drilling 102 (97.1 net) wells. Northern Blizzard spent $56 million on facilities and pipelines during the fi rst six months of 2014. “Included in that are 18 horizontal wells at the Winter field and 36 vertical wells at our Cactus [Lake] field,” Rooney said. “We currently have five rigs in the field running, and we plan to drill just over 200 wells this year.” Of the company’s five rigs currently in operation, two are at Cactus Lake, 50 kilometres northeast of Kerrobert, Sask.; one is at Winter, 75 kilometres southeast of Lloydminster, on the Saskatchewan-Alberta
border; one is drilling Viking wells; and the fifth is currently transitioning from the Cuthbert field to the Court field west of Kerrobert. The company completed its Plover Lake steam assisted gravity drainage project in the fi rst half of 2014, with steam injection beginning in July. Management anticipates production from the project to be about 2,400 barrels per day by the end of the year. Northern Blizzard also continued Bakken polymer injections at Cactus Lake, with more than eight million barrels injected. In the Viking play at Smiley, the company also drilled its fi rst eight net light oil wells during the fi rst six months of 2014, with 27 Viking wells planned for the year. — DAILY OIL BULLETIN
Northern Blizzard has five rigs currently working in Saskatchewan.
OIL & GAS INQUIRER • OCTOBER 2014
43
Saskatchewan
Raging River doubles year-over-year production Raging River Exploration Inc.’s production for the second quarter of 2014 increased to 9,960 barrels equivalent per day from 4,620 barrels per day during the same period last year, an increase of 116 per cent. The year-over-year increase was attributable to a successful drilling program in 2013 and 2014 combined with the property acquisition that closed late in the fourth quarter of 2013. Production levels moderated through breakup to lows of 9,600 barrels per day and have now begun to increase concurrent with capital activities, with current production in excess of 10,500 barrels per day. The company has increased its average production guidance to 10,300 barrels per day from 9,800 barrels per day and increased exit guidance to 12,100 barrels per day from 11,700 barrels per day. The company spent $27.79 million on capital expenditures, including $27.3 million on development activities in addition to $400,000 on land.
A total of 23 (22 net) horizontal Viking wells, testing 14 (13.5 net) undrilled sections, were drilled in the second quarter. In all cases, the geological data was compelling, with all wells cased and completed. However, during completion operations, one well encountered a casing collapse that resulted in the abandoning of the well. Given the geological success of this well, it will be re-drilled later in the year. To date in the third quarter, 30 (23.9 net) additional wells have been successfully drilled, testing 10 (8.3 net) new sections. These wells are currently in various stages of completion. The third quarter of 2014 is expected to be Raging River’s busiest quarter on record, with 75–80 net wells expected to be drilled during the quarter. At Forgan, the six wells drilled in the fi rst quarter of 2014 have all been on production greater than 120 days, with average rates of 40 barrels per day of oil. The company said that 18 (16.2 net) wells have been drilled since June, with
10.9 net wells testing previously undrilled sections. These wells have successfully extended the boundaries of the proven economic edges of the play. At Beadle, 19 (17.8 net) wells have been drilled since June at 100 per cent success. Raging River said that nine (7.8 net) of the wells drilled since June have tested previously undrilled sections. Early time production results from these wells have been favourable, again extending the boundaries of the proven economic edges of the play. The 39 wells placed on production in the area in 2014 have shown 150-day average rates of 37 barrels per day, which is consistent with the 30 wells drilled in the area in 2013. At Plato, 16 wells placed on production in the area in the fi rst quarter of 2014 have shown six-month average oil rates of 50 barrels per day, which are the strongest wells drilled in the area to date. — DAILY OIL BULLETIN
Crescent Point continues consolidation in southeastern Saskatchewan Crescent Point Energy Corp. has announced another acquisition as it reported record production for the second quarter, bolstered by previous purchases. On July 18, the company signed an agreement to acquire T. Bird Oil Ltd., a privately
held oil and gas company with assets in Manitoba and southeastern Saskatchewan. The price is about $88 million, including 1.5 million Crescent Point shares and assumed net debt, based on a five-day weighted average share price of $45.36 per
Crescent Point share. Closing was expected in mid-August. The assets produce 700 barrels per day and include more than 24 net sections of land. Crescent Point said the assets offer excellent rates of return and include 53 net
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OCTOBER 2014 • OIL & GAS INQUIRER
Saskatchewan
low-risk drilling locations and significant exploration potential in multiple horizons. On July 30, the company closed an agreement to buy assets in the Viewfield Bakken and Flat Lake plays in southeastern Saskatchewan from an unidentified producer for $99.1 million in cash. The Flat Lake assets are producing about 825 barrels per day and include more than 54 net sections of land. These assets are next to Crescent Point’s Viewfield and Flat Lake lands and include 38 net low-risk drilling locations. On May 15, Crescent Point completed the acquisition of CanEra Energy Corp., a privately held southeastern Saskatchewan oil and gas producer, for $1.1 billion. The CanEra assets include more than 260 net sections of land with Torquay potential and conventional production of about 10,000 barrels per day. The acquisition is also expected to help drive a seven per cent reduction in the company’s all-in payout ratio in 2015. On June 12, Crescent Point completed the acquisition of Saskatchewan Viking oil assets from Polar Star Canadian Oil and Gas, Inc., a private western Canadian oil and gas producer, for $331.7 million. Crescent Point bought all of Polar Star’s assets in the Viking play at Dodsland. The deal includes more than 2,800 barrels per day and consolidates Crescent Point’s Viking land position at Dodsland. Given its performance and acquisitions, the company has increased its 2014 guidance. Average daily production and exit production in 2014 are expected to increase to 138,000 barrels per day from
• Plug Milling • Frac Seat Milling
135,500 barrels per day and to 149,000 barrels per day from 148,000 barrels per day, respectively. During the second quarter, Crescent Point drilled 27 (26.5 net) oil wells in the Viewfield Bakken play. The company continues to refine its one-mile, 25-stage cemented liner completion technique and to expand its waterflood program in the play, which are both driving strong rates of return. Crescent Point has 81 water injection wells completed
138,000
barrels per day
Crescent Point's expected 2014 average production.
in the Viewfield Bakken with another 15 expected by year’s end. The company is pleased with results in the Torquay play at Flat Lake, having drilled six (5.7 net) oil wells during the quarter. Crescent Point is seeing positive results with step-out wells that continue to delineate the area. During the second quarter, Crescent Point continued to expand its waterflood program in the Shaunavon resource play. Crescent Point currently has 29 water injection wells operating in the Shaunavon zone and a further 14 are expected by year’s end. During the quarter, the company submitted an application for its second
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unit in the area, which is next to the fi rst unit. Crescent Point expects approval by year’s end. The company is excited by this development as the fi rst unit continues to exhibit positive waterflood response. Based on results to date, the company estimates it has reduced decline rates by up to 10 per cent in waterflood-affected areas compared to areas not under waterflood. In t he second qua r ter, Crescent Point drilled 16 (16 net) oil wells in the Shaunavon resource play. As the company continues with the largest Shaunavon drilling program in its history, it continues to refi ne its cemented liner completion technology. It believes using 25-stage cemented liner completions should ultimately lead to positive technical reserve additions on its remaining booked drilling inventory and existing producing wells. In 2014, Crescent Point also plans to drill 90 net wells from pad locations that allow it to drill up to three wells per pad location, as opposed to one well. In July, the company began its drilling program in Battrum, with 11 (4.8 net) oil wells planned for 2014. Crescent Point also plans to begin participating in its Cantuar drilling program in August, with six (3.3 net) oil wells planned for 2014. In the Saskatchewan Viking play, the company integrated the Viking assets acquired from Polar Star late in the second quarter and began its 2014 drilling program in July. — DAILY OIL BULLETIN
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OIL & GAS INQUIRER • OCTOBER 2014
45
Cover Feature
DIRTY WORK 46
OCTOBER 2014 • OIL & GAS INQUIRER
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Cover Feature
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loydminster heavy oil is one of the most profitable resource plays in North America, according to Scotia Capital Inc.’s ranking of plays released in March. But it isn’t for the faint of heart, said Scott Stauth, senior vice-president of North American operations at Canadian Natural Resources Limited. “It’s not easy to be successful in heavy oil,” Stauth said at Canadian Natural’s investor presentation in June. “Many companies have tried it and found barriers to entry or complex challenges that require larger-scale operations to be efficient. Think of it as a manufacturing plant. What’s important here is how, in a low commodity price cycle, you need effective oil, sand and water logistics and reliable and efficient equipment to keep your costs down. “Heavy oil is labour intensive,” he added, as the product is trucked to process facilities rather than piped in gathering lines as in light oil or gas plays. But for those with the resources and grit to make heavy oil development a go, the rewards can be well worth it. Scotia Capital ranked vertical heavy oil wells in the
It takes
grit
Stauth credits Canadian Natural’s success to its large concentrated land base with a drilling inventory of over 8,000 wells. This base allows the company to do large-scale drilling programs year after year, averaging around 800–900 wells annually for the last five years. “The drilling programs allow us to pre-order all our equipment to cut costs,” he explained. Owning its own processing facilities and pipeline infrastructure is also a key to Canadian Natural’s success, said Stauth. The company processes all its own oil at five major facilities and has 100 per cent ownership of the ECHO heavy oil pipeline. “Our facilities were built over a decade ago, and in today’s dollars, a 10,000-barrela-day processing facility would cost around $80 million,” he explained. “We have capacity in excess of 150,000 barrels per day that has already paid for itself and has been well maintained.” Canadian Natural’s ownership of the ECHO pipeline adds to its cost advantage. Around half of the company’s production is shipped to Hardisty, Alta., on the pipeline before going to end markets. The ECHO
to make Lloydminster heavy oil
pay off
Lloydminster area the seventh most profitable resource play on the continent out of 50 plays, based on a profit-to-investment ratio. Vertical wells returned over $2 for every dollar invested. Horizontal wells at Lloydminster ranked 15th, returning about $1.80 for every dollar invested. For Canadian Natural, heavy oil competes favourably with its vast portfolio of light oil, oilsands and natural gas assets in Canada and around the world. “Primary heavy oil provides the most significant influx of free cash flow in our portfolio,” Stauth said. “Being the biggest heavy oil producer in Canada, we have built a cash flow machine at Lloydminster.” Canadian Natural currently produces around 140,000 barrels per day of primary heavy oil production, with plans to increase that to around 144,000 barrels per day this year. The key to the company’s success has been controlling costs while leveraging new technology when possible.
By Darrell Stonehouse
pipeline uses heat from the company’s processing facilities to lower the viscosity of the oil, allowing it to flow better. “It requires less condensate than other heavy oil pipelines, and that lowers transportation costs,” said Stauth, adding the company is now investigating using friction reducers in the ECHO line to further improve its capacity. Expertise in drilling and completing heavy oil wells is also important to success in the Lloydminster play, said Stauth. “We are very efficient at slant drilling, which has proven to be the main driver of our production,” he explained. “But in addition, horizontal drilling in lower-permeability or oil-over-water reservoirs where it’s not practical [to] slant drill has also become a driver. We expect to drill 130 horizontal wells this year.” In 2014, Canadian Natural expects to spend around $1.1 billion drilling around 850 heavy oil wells and recompleting another 550. It expects to continue spending this
amount out to 2017, according to its mid-term capital plan. It expects to generate cash flow of between $1.2 billion and $1.4 billion each year through that investment. “And that cash flow is reliable because it’s low-risk development with a proven track record,” he said. Canadian Natural focuses on enhanced heavy oil recovery Canadian Natural is also advancing a number of enhanced recovery schemes to further capture value in its heavy oil operations. At Lone Rock and Epping in western Saskatchewan near the Alberta border, the company is doing three separate tests in partially depleted heavy oil pools. These are typical heavy oil reservoirs, where only 10–15 per cent of the oil is recovered on primary production. In 2011 and 2012, the company began two waterflood pilots in an unconventional heavy oil application at Lone Rock and South Epping. Successful heavy oil waterfloods are rare in viscosities greater than 1,000 centipoise. Oil viscosities in the Lone Rock and South Epping pools range between 700 and 2,300 centipoise, and the gravity is 15–17 degrees API. The production response from the two waterflood pilots has been excellent, said Lyle Stevens, Canadian Natural’s executive vice-president of Canadian conventional. “The production has increased from essentially zero in these depleted pools to approximately 600 barrels per day.” The two Lone Rock and South Epping pilots have 28 producer wells producing from the Sparky Formation. Stevens said the value of the pressure support was shown recently when an injection well was temporarily shut in and oil production dropped steeply. “So far, the response has met our expectations and the results are pointing to the economic viability of the waterflood and its expansion to the rest of the pools,” he said. If the pilots are successful, commercial projects would be undertaken in the next two to three years, Stevens said. Canadian Natural hopes unconventional waterflooding at Lone Rock and Epping can recover an additional 20 million barrels of oil. Also at Epping, the company is testing a polymer flood pilot with vertical wells that will allow it to compare the economic viability of waterflooding versus polymer flooding. The Southwest Epping polymer pilot began in the fourth quarter of last year and is still in the fill-up period. About OIL & GAS INQUIRER • OCTOBER 2014
47
WORK Cover Feature
Comparison between vertical and horizontal Lloydminster heavy oil wells
Completed well cost
Production (IP30)
Expected ultimate recovery
Vertical
Horizontal
$450,000
$950,000
30–50 bbls/d
70–80 bbls/d
30–50 million bbls 60–80 million bbls
Capital efficiency
$11,250/day
$12,700/day
Development cost
$11.25/bbl
$13.60/bbl
12 per cent of the 64 million barrels of original oil in place at South Epping has been recovered. Canadian Natural hopes to increase recovery by about 13 per cent of the original oil in place. “Success here could result in doubling the recoverable oil,” Stevens said. Baytex uses multilaterals to cut costs Baytex Energy Corp. is also focused on cutting costs at its Lloydminster operations. It is heavily investing in rail as a means to maximize the value of its production. Speaking at the company’s secondquarter analysts’ conference, Baytex chief operating officer Richard Ramsay said one way the company is cutting expenditures is through the drilling of multi-leg horizontal wells, similar to what the company is doing at its Peace River oilsands operations. In the second quarter, Baytex drilled 9.2 net oil wells at Lloydminster, including two multilateral wells with two laterals and four laterals. “We are fairly early into translating that technology over to our Saskatchewan assets,” he said, adding that the goal is capital efficiency. “Generally, we’re spending about $950,000 to drill, complete and equip for a single-leg well there. For a two-leg well we’re bringing that down to about $1.1 million to $1.2 million. So that’s really where we’re going to be seeing the efficiencies.” Baytex president and chief executive officer James Bowzer said transporting heavy oil by rail is another way the company is making its Lloydminster heavy oil production profitable. “In the second quarter, approximately 55 per cent of our heavy oil volumes were delivered to market by rail, as compared to 42 per cent for the full-year 2013,” he said. “For the third quarter, we expect to deliver approximately 60 per cent of our total heavy oil volumes to market by rail, and our marketing team continues to focus on opportunities to further mitigate the 48
Heavy oil prices 2010-14
OCTOBER 2014 • OIL & GAS INQUIRER
WTI US$/bbl
WCS US$/bbl
Differential US$/bbl
% of WTI
2010
79.53
65.30
14.23
17.9
2011
95.12
77.97
17.15
18.1
2012
94.20
73.17
21.03
22.2
2013
97.97
72.77
25.20
26
2014 (six months)
100.84
79.25
21.59
21.5
volatility in WCS [Western Canadian Select] price differentials by transporting crude oil to higher-value markets by rail.”
Husky builds steam Husky Energy Inc. is taking a slightly different approach to creating value from its Lloydminster operations by both leveraging its downstream operations and focusing on the most profitable parts of its huge heavy oil land base. Bob Baird, Husky’s senior vice-president, downstream, said at the company’s Investor Day last summer that the goal of the company’s downstream operations is to eliminate as much of the differential between heavy oil prices and international light oil prices as possible. “It’s our job to get Brent-like pricing for all our landlocked barrels, and we’re doing that job,” he explained. “Over the past three years, this part of our business has generated more than $2.5 billion in earnings.” Baird said Husky’s Lloydminster Upgrader and asphalt refinery is the beginning of this effort. “This is the heart of the heavy oil integration story and a big piece in closing the gap between Brent and Western Canada Select prices,” he explained. “These are legacy assets. This means that while the profits can go up and down in any given year, depending on differentials, over the long haul these assets have paid for themselves and will continue to do so many times over.” Baird said the next link in the value chain for the company is Hardisty, the hub for heavy oil transportation out of western Canada. From Hardisty, Husky’s heavy crude and upgraded product can go to the market with the highest value. “I like to say that Hardisty is the Cushing [Okla.] of the north.... All pipes end up in Cushing, and Hardisty is where they start and where we have assets,” said Baird. “Basically, we at Husky are plumbed right through to our markets. We have the flexibility to move our barrels to the best-priced markets. We dabble in rail to keep our understanding of
Source: Baytex Energy Corp.
the market, but we don’t need it to run our crude to market. Pipelines are the most costeffective way to move landlocked crude. It’s a fundamental principle and a key factor in our focus integration strategy.” Completing Husky’s strategy is its investment in refining capacity in the United States. Husky owns a light oil refinery in Lima, Ohio, and has a 50 per cent interest in another refinery in Toledo, Ohio, that processes about 50 per cent heavy crude feedstock. “Our U.S. refining capability gives us Brent or Brent-like pricing,” said Baird. Husky expects to spend $1.3 billion in 2014 on heavy oil development. That investment is expected to continue in the mid-term as it works to double thermal production over the next six years. Upstream, Husky is focused on the lowest-cost development areas on its more than two million acres of land spanning around 20,000 square kilometres in the Lloydminster area. All of that land isn’t equal, Ed Connolly, Husky’s senior vicepresident of heavy oil, said. “Just over one million acres of that lease is held by one freehold lease with no royalties. As long as we have one producing well, the entire block is held, and today we have over 4,000 producing wells,” he explained. Without royalties to pay, this makes those one million acres highly profitable, said Connolly. “The royalty benefit of the freehold lease adds about $4-a-barrel netback to the total production in Lloydminster,” he explained. Aside from drilling on its freehold lands, Husky is focused on expanding thermal developments to maximize returns at Lloydminster. “Certainly, thermal production is the headline story within the heavy oil business unit,” said Connolly. “Thermals deliver long life with low decline, and they’re highreturn projects. They also have oil recovery rates that are typically over 50 per cent, and that compares to CHOPS, or cold production, in the range of eight to 10 per cent. Pikes Peak, for example, has produced for more than 30 years with current recovery
K
Cover Feature
rates over 60 per cent, and we’re now targeting 70 per cent. This leads to low finding and development costs, and it allows us to exploit smaller targets. That opens up a huge opportunity in the Lloyd block.” Thermal operating costs are also more favourable than cold production, and we’re realizing higher quality of returns,” he added. “Last year, 30 per cent of the heavy oil business unit production came from thermals, but they generated 80 per cent of our operating earnings.” Husky is currently producing 40,000 barrels per day of thermal production at Lloydminster with plans to double that production by 2020. “In the near and the mid-term, we’re focused on developing our thermal opportunities. As we increase the share of our production in thermals, we improve our overall quality of returns,” said Connolly. Connolly said there are three factors that drive returns in thermal heavy oil operations. The first is project execution, which is driven by carving smaller thermal projects out of its massive heavy oil resource base. “Thermals are a great example of making big projects small,” said Connolly. “Build times are only two years, and the projects are very controllable. This gives us good certainty on costs and delivery schedule. We use modularized designs to minimize field construction hours. Our onsite construction labour force is relatively small, and many live in the Lloydminster area, so there’s no need for expensive camps to house our workers there, and these projects are repeatable. “The second driver is reservoir quality,” he said. “The reservoir lends itself to very efficient production ramp-up, and that allows us to achieve nameplate capacity within three months of start-up. Good steam-oil ratios. We design our plants for steam-oil ratio at three; however, in the early life, we see steam-oil ratios less than two. Pikes Peak South and Paradise Hill have both operated for more than two years, and both are still running steam-oil ratio below two.” Connolly said the third driver making thermal heavy oil highly profitable is the quality of the oil itself. “Heavy oil is much lighter than bitumen and, as such, it has a significantly higher value, is a significantly higher-value product,” he said. “So, in summary, the excellent capital efficiencies, the top-quality reservoirs, combined with the higher realizations, gives us returns north—well north—of 20 per cent.”
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OIL & GAS INQUIRER • OCTOBER 2014
49
Feature
F
As completions technologies evolve, operators customize fracturing processes on a play-by-play basis with a focus on cutting costs and raising production By Darrell Stonehouse with notes from the Daily Oil Bulletin
50
OCTOBER 2014 • OIL & GAS INQUIRER
racturing horizontal wells is an expensive proposition up front. In the emerging Duvernay shale play, Yoho Resources Inc. reported completion costs of $7 million per well—or a little over 58 per cent of the cost of drilling, casing and completing the well—this summer. But as time goes on, those costs decline. In 2010, it cost around $2.5 million to complete a well in the Cardium. Today, it costs around $1.3 million despite the fact that the number of stages fractured has increased from an average of seven to 18. This sort of bending of the cost curve is happening across resource plays in western Canada as operators learn from experience what works best in each play. At the Viewfield Bakken tight oil play in southeastern Saskatchewan, Crescent Point Energy Corp. is enjoying the benefits of fine-tuning its completions technology. The company has been using cemented liners with 25 fracturing stages exclusively in the play for the last year with excellent results, said Neil Smith, chief operating officer of Crescent Point. “About three years ago, we moved from the packer system to cemented liners,” Smith explained earlier this year. “Basically what it does is allow you more precision as to where you place the frac. And it allows you to go back into wells and do as many fracs as you want. So we started out with eight stages with a cemented liner and then we went to 16-stage cemented liner, then to 20, then to 25. We adjusted the amount of sand, the amount of water used, and did the correlation between productivity and reserves and cost. And we’ve seen a tremendous uptick in that. “Also what has occurred, which we didn’t actually really expect, was that we got higher IPs [initial production rates] and lower declines because we are opening up more rock,” he added. “And opening up more rock opens up more matrix porosity within the rock, which then allows more oil
Feature
“ We use a slickwater frac with a ball- drop-style delivery, and you can now use that in a two-mile well
as you can a one-mile well.” — Philip Harvey, vice-president of exploitation, Anderson Energy Ltd.
to flow and flow at a lower pressure change, which then allows for the flattening of the production curves. We’ve seen that across all of the plays that we’ve implemented this in. And to give you an example, I think the math on the Bakken is something like after 12 months, instead of 50 barrels a day, it’s at 100 barrels a day. It’s a pretty tremendous outperformance relative to the older 16-stage completion technique.” Smith said he believes the cemented liner system works better because it has fewer failed frac stages. “A lot of it is simply that, in the 16-stage packer system technique, you maybe got 10–12 of the fracs that worked. So what we see is that there is a low percentage of fracs that work in that kind of methodology, and you wind up refracking the same frac in that case. And so you don’t get the good productivity,” he explained. The cemented liner completions technology has also cut costs, largely due to less water handling, says Crescent Point chief financial officer Greg Tisdale. “When you complete a well, just to give you a simple example, instead of using 2,000 cubes [cubic metres] of water, we use 1,000 cubes. So there is less tank storage, less power to pump that fluid in. Then when you flow it back, you’re disposing of less water. All of that goes into your capital cost.” Tisdale says the cemented liner completions save about $100,000 per well on water handling costs. “Our completion guides are really focused in on reducing the amount of fluid,” he adds, pointing out that often in the industry you hear about operators doubling their fluid, doubling their sand, doubling everything—and so their costs are going up. “We’re trying to look at it from the opposite direction and mitigate costs and reduce costs but get better performance. That’s what we’ve seen. And so we’re pretty excited about that side of it. There are further ways to reduce those costs. So that’s really over the last year to
two years what’s happened is any of the inflationary costs that you would have seen in capital programs we’ve mitigated just by changing and optimizing our completion technique.” Legacy Oil + Gas Inc. is also a believer in cemented liners, company president and chief executive officer Trent Yanko said in late March. “Over three and a half years ago, we started using cemented liners in the Bakken,” he said. “We recognized the potential of the improvement in being able to control the frac, how those fracs initiate and the profile of them back at that time. We have moved to cemented liners, using them in the Three Forks, Spearfish, Bakken and in a lot of our different areas, and we have been at the forefront of that. “Also, we have been at the forefront of using slower pumping rates and less tonnage,” he added. “Three and a half to four years ago, we recognized that as a potential for cost savings but also a performance enhancer in these plays.”
Going long in the Cardium The Cardium tight oil play is also seeing an evolution in completions technology that continues as operators drill longer and longer horizontal wells. Lightstream Resources Ltd. entered the Cardium in 2010 and now has production of around 20,000 barrels per day. In April, Lightstream senior vice-president and chief operating officer Rene LaPrade said during its four years in the Cardium play, Lightstream has sought to maximize production and minimize capital costs. The company has used multi-well pad drilling wherever possible, changed wellbore designs, and used monobore drilling techniques, long-reach horizontal wells and economies of scale to reduce costs. “As a matter of interest, we’ve drilled 16 one-and-a-half-mile wells and four two-mile horizontal wells in the Cardium to date, which is not only cost efficient
but reduces our environmental footprint,” LaPrade said. “On the Cardium completions, Lightstream was the first to use slickwater fracturing techniques, increased the number of frac stages from eight to as high as 30 stages, increased our sand tonnages from 10 to 20 tonnes per stage and changed the sand grain size.” Technology in the play continues to move forward as new processes allow even more fracturing density. Late last winter, NCS Energy Services, LLC reported the successful completion of two horizontal Cardium wells, employing a first-time combination of high-rate slickwater and the NCS Multistage Unlimited fracturing system. More than 60 frac stages were placed in one well, with aggressive spacing of individual fracture stages, said NCS. Treating rates of 7.1 cubic metres per minute enabled placement of 40 frac stages in a single 24-hour period, making tightly spaced fractures a viable and economical alternative to unpredictable and less precise stimulation methods, it said. Cemented NCS GripShift casing sleeves provided fast and reliable formation access, and subsequent analysis of downhole gauge data allowed identification of any inter-stage communication, according to the company. Calfrac Well Services Ltd. provided the field execution of the new marriage of slickwater technology with high-density pinpoint fracture placement, believed to be an industry first in the evolution of multistage completion technology. But these long extended-reach wells with high frac density come with their challenges, said LaPrade. “When we are looking at longer-reach wells, whether they be 1.5 or two miles, our philosophy has been that we can drill them. They do have some advantages from a capital-efficiency standpoint, but from a completion and production standpoint, they also have some technical challenges when you are drilling them so long.” OIL & GAS INQUIRER • OCTOBER 2014
51
Feature
Canadian fracturing requirements by play Fracture stages per well
Fracturing hydraulic horsepower required
Cardium
15–25
8,000–25,000
20–40
Slave Point
10–20
7,500–12,500
20–40
Beaverhill Lake
10–20
20,000–30,000
75–150 (cubic metres/stage)
Viking
10–15
4,000–15,000
20–40
Bakken
10–25
2,000–4,000
6–12
Play
Fracture size (tonnes/stage)
Oil plays
Lower Shaunavon
10–15
6,000–10,000
20–40
Alberta Bakken
12–20
4,000–15,000
20–30
Gas and natural gas liquids plays Montney
10–20
18,000–40,000
50–250
Deep Basin Horizontal
8–12
10,000–30,000
50–250
Deep Basin Vertical
3–5
10,000–30,000
40–120
Horn River
15–30
30,000–50,000
200–300
Duvernay
10–20
35,000–50,000
80–150
Sources: Canyon Technical Services Ltd.; Calfrac Well Services Ltd.
Although most of Lightstream’s long-reach wells are 1.5 miles in length, LaPrade said his company was actually able to use long-reach wells to access hydrocarbons from underneath the town of Cochrane, Alta., drilling two wells that were over two miles in horizontal length. But it wasn’t easy. “I would say that those have been technical challenges because of the distance you have to pump sand when we frac them. So it is not the actual distance of drilling, but it’s actually the completion technique that gets to be a bit of a challenge on those longer-reach wells.” According to LaPrade, current technology is somewhat limited when it comes to easily completing and producing really long horizontal wells. He said, “We are normally pumping about 20 stages in a normal one-mile well, but in a two-mile well, we’re pumping anywhere up to 35 stages. “To get that frac fluid out two miles down a piece of pipe is again a technical challenge with the type of sand and fluid you must use to get it out there. Producing it back, of course, is not always the easiest thing because if you have any sand issues, then it gets to be a challenge.” Philip Harvey, vice-president of exploitation at Cardium-operator Anderson Energy Ltd., said that completions have come a long way toward making extended-reach wells more common—a fairly recent phenomenon in his experience, which was not the case even as recently as 18 months ago. 52
OCTOBER 2014 • OIL & GAS INQUIRER
“We use a slickwater frac with a balldrop-style delivery, and you can now use that in a two-mile well as you can a one-mile well,” he said, adding that the increments on ball-drop balls used to be one-quarter of an inch and are now one-16th of an inch, meaning one can drop more balls and service a longer horizontal well. “It’s basically as simple as that. It’s not anything high-tech; it’s just a matter of reconfiguring the ball seats and the ball sizes. Jobs will take longer to do, but it is the same technology. You can start out at a 1.5- to two-inch ball range and work your way up to whatever fits in a 4.5-inch monobore well. You can get over 30 fracs away in your long well.” Lightstream was one of the first companies to use the ball-and-seat system to complete its wells eight years ago, LaPrade said, and while that is a proven, timetested system, other methods with sliding sleeves and full-opening ports are in development and would allow completions beyond two miles. However, a higher-pressure well will require more pressure when pumping at surface, he noted, which is another factor companies must account for when considering extended-reach wells. “There gets to be a diminishing amount of pressure that I can pump at the surface; I start running into equipment limitations if the zone pressure is too high, and I have to pump it in at a higher rate if I want to get it into the zone, and I have friction that I have
to get by. The reservoir pressure would have an impact on that delivery system.” Just as technology has made extendedreach wells more economically viable for oil and gas producers, though, Harvey said there is no reason to believe that further improvements will not increase efficiencies to make this style of well even more cost effective and feasible in the future. “We always think we know everything now, but five years from now, technology will advance considerably and some of our ideas today might seem a bit quaint,” he said. “Think of how far we have come in the last five years on tight oil development technology.”
Fracking shift under way in the Montney Changing fracturing technology is also having a major impact in the Montney play straddling the Alberta and British Columbia border. Crew Energy Inc. had been hesitant about developing its Tower Montney oil play due to its tight rock—siltstone, shale and sandy— but is now getting “quite excited about it.” Although it is still early in its efforts to learn how to treat the play, the company has seen very good results recently, Dale Shwed, president and chief executive officer, told the CIBC 17th Annual Energy Conference in Toronto. A recently drilled well, 01-24, on the emerging Montney light oil play tested at more than 600 barrels of oil per day and 1.5 million cubic feet of gas per day over 13 days. Another well, 13-08, tested 342 barrels of oil per day and 1.7 million cubic feet of gas per day over 23 days. The company has 51 sections of land at Tower with more than 700 drilling locations and 138 sections of land in the oil window, 163 sections in the liquids-rich gas window and about 76 sections in the dry gas window, so it has “lots of running room” to pursue the play more aggressively, said Shwed. Crew plans to use larger well casings to increase the velocity of the fracs further into the well and will extend the horizontal legs to about 1,800 metres, hoping to flow up to 10 cubic metres per minute when they are fractured. At Septimus, also in the Montney, the company is making changes to improve productivity and cut costs, the conference heard. The company is tinkering with the sand concentration during fracturing,
adjusting the amount in each interval from 50 tonnes to 75 tonnes and then back to 50 tonnes. And while most producers in the area are using the plug-and-perf system, Crew uses the ball-drop system. “We find that we’ve had much better results using that system,” said Shwed. “It’s been borne out through microseismic that we’ve done as well. I think there’s some science behind it that supports it, and there’s also the practical aspect: we’re getting better results as well.” 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. 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. In August, Delphi Energy said it is preparing to employ new completion methods to increase frac stages on a couple of its upcoming extended-reach wells. “We do have technology changing as such that instead of 30 stages, we could be going to 40 or 50 just because of the change in some of the technology around the ball-drop system,” David Reid, president and chief executive officer, told the company’s second-quarter conference call. “Increased frac density is something that we do want to find with our extendedreach laterals.” According to Delphi’s engineering department, Reid said, longer-reach laterals deliver greater access to reserves, and new technology applied on the next couple of wells should further improve those returns. “It’s difficult in early time here to quantify the benefit of horizontal length from the actual production, but we have fairly significant reservoir modelling and history matching with the data we do have.”
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Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . .18
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Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 37
Globalstar Canada Satellite Co . . . . . . . . . . . . . . 49
Rush-Overland Manufacturing . . . . . . . . . . . . . . 26
Brews Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Grant Thornton LLP . . . . . . . . . . . . . . . . . . . . . . . 23
STEP Energy Services . . . . . . . . . . . . . . . . . . . . . . 5
Brother’s Specialized Coating Systems Ltd . . . . 44
Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . . 38
Tank Gauging Systems . . . . . . . . . . . . . . . . . . . . . 41
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Testo, Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16
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League Pipeline Services Ltd . . . . . . . . . . . . . . . 40
Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
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Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . . 14
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DSI Thru-Tubing Inc . . . . . . . . . . . . . . . . . . . . . . . 45
Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
V J Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 11
Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 53
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OCTOBER 2014 • OIL & GAS INQUIRER
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