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DRILLING HEATS UP IN THE BAKKEN, WITH ENHANCED RECOVERY SCHEMES ALSO TAKING SHAPE
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FRACTURE STIMULATION PROGRAMS
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Plug & perf and ball-sleeves and packers are basically brute-force techniques, with fluids and fracs bullheaded down the casing and into the formation, with no feedback about formation response at the frac zone, no recourse in the event of a screenout, and no way to conserve water and chemicals. Also, both methods can require extensive post-stimulation work to drill out plugs or ball seats. With the Multistage Unlimited system, coiled tubing provides both a circulation path to the frac zone and a work string, giving this unique system a number of important advantages and none of the disadvantages of the other methods.
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FEATURES
15
25
Turning on the tap
Fine-tuning fracturing
Drilling heats up in the Bakken, with enhanced recovery schemes also taking shape
Operators focus on fracturing density, fluid choices and improving processes
By Darrell Stonehouse
By Darrell Stonehouse
G e n era l Ne w s
By Lynda Harrison
35
British Columbia B.C. turning to oil
Northwestern Alberta Delphi reports success at Bigstone
43
Northeastern Alberta Kearl remains on track By Elsie Ross
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Central Alberta Perpetual reports loss, changes focus to heavy oil
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Southern Alberta AltaGas Gas expects liquids, Harmattan project, to drive results
Saskatchewan Saskatchewan drilling builds speed By Lynda Harrison
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• Underground intersects
• Harmful Alteration Disruption or Destruction (HADD) repairs to water crossing • Shore approaches and outfalls • Pipe ramming • Pipe bursting • Slip lining
Northern Frontier N.W.T. Canol oil shale play taking shape By Elsie Ross
T e c h n o l og y Ne w s
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IN EVERY ISSUE
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Stats at a Glance
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O I L & G A S I N Q U I R E R • MAY 2 0 1 2
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Editor’s Note
Vol. 24 No. 4
Darrell Stonehouse | dstonehouse@junewarren-nickles.com
editorial Editor
American renaissance, Canadian problems
Darrell Stonehouse | dstonehouse@junewarren-nickles.com Contributing writers
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The United States petroleum exploration industry is on a roll. The arrival of extended reach drilling and multistage fracturing has set off a shale gas boom that has added over 100 years of potential supply. The downside is that the shale gas rush has driven prices down to the point that on an energy equivalence measurement, gas is trading at 1/50th the price of oil. But that’s short term. Longer term, the expanded gas supply will find a home in power generation, LNG exports and even transportation, bringing the price back to profitable levels. The new drilling and completions technology is also breathing life into the country’s onshore oil industry, with tight oil plays like the Bakken and liquids-rich gas plays in Texas quickly cranking up production. Add to that the successful exploration in the deep water off the Gulf of Mexico coming on stream in the next few years. Banking giant Citigroup believes the United States is in the midst of an energy renaissance that could propel the country into the forefront of the global industry. In a report released early this year, Citigroup says U.S. oil and liquids production could increase by 2.6 million barrels per day in the period from 2011-15, to average 11.6 million barrels per day. By 2020, it says U.S. liquids production could reach 15.6 million barrels per day, a 6.6-million-barrel-per-day increase over 2011 levels. On the gas front, Citigroup says the mainland United States is now producing around 62 billion cubic feet per day. It expects production to climb by 14 billion–18 billion cubic feet per day by 2020, if they can find places to burn it. Citigroup adds there are no geological or technical roadblocks stopping the United States from reaching these production volumes. The only issue is whether political or environmental issues slow the exploration advance. If the Citigroup forecast is reality, nowhere will the implications of this explosion in U.S. petroleum production be felt as acutely as in Canada. The western Canadian gas industry has already been devastated by massive shale supplies south of the border, with production down 31 per cent in the last year alone. Bottlenecks in U.S. oil infrastructure have Canadian oil being discounted by over $40 per barrel. Looking ahead, it appears this is only the beginning. The United States is going to be self-sufficient in natural gas within the decade and competing in LNG markets against Canadian gas. Domestic oil production is likely to push oilsands crude back into Alberta in some refinery areas. Adding to that, Citigroup is projecting a two-million-barrel-per-day decline in demand in the United States, and the trouble deepens. Canadian industry, provincial governments and the federal government need to wakeup—fast. The days of the United States taking all the petroleum we can produce are over. New markets are needed, like yesterday.
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N E X T
I S S U E
June 2012 In the June issue, we look at Canadian service and supply companies successfully exporting to the United States and around the globe. We also examine future export hotspots.
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.
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
11
Stats
AT A GLANCE Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
MONTH
OIL
GAS
OTHER
T O TA L
MONTH
OIL
GAS
D RY
T O TA L
Mar 2011 Apr 2011 Jun 2011
1,069 618 428
1,081 509 197
64 46 12
164 81 183
2,378 1,254 820
Mar 2011 Apr 2011 Jun 2011
650 419 209
974 472 124
222 112 100
1,846 1,003 433
Jul 2011 Aug 2011 Sep 2011
105 452 1,028
43 183 357
97 93 146
245 728 1,531
Jul 2011 Aug 2011 Sep 2011
298 922 1,448
97 262 445
15 28 24
88 80 155
498 1,292 2,072
Oct 2011 Nov 2011 Dec 2011
626 557 568
259 241 300
19 36 72
904 834 940
Oct 2011 Nov 2011 Dec 2011
1,153 1,170 988
321 331 359
20 27 27
49 42 115
1,543 1,570 1,489
Jan 2012 Feb 2012 Mar 2012
215 491 515
131 177 147
35 50 55
381 718 717
Jan 2012 Feb 2012 Mar 2012
419 846 996
190 244 180
15 21 33
31 52 66
655 1,153 1,275
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS DRILLED
C U M U L AT I V E *
MONTH
OIL
GAS
OTHER
TOTAL
Mar 2011 Apr 2011 Jun 2011
55 41 54
186 172 419
Mar 2011 Apr 2011 Jun 2011
316 183 217
8 11 25
4 11 89
328 205 331
Jul 2011 Aug 2011 Sep 2011
56 40 92
479 519 611
Jul 2011 Aug 2011 Sep 2011
185 413 352
5 2 4
3 13 29
193 428 385
Oct 2011 Nov 2011 Dec 2011
35 92 58
646 738 796
Oct 2011 Nov 2011 Dec 2011
457 524 332
29 4 4
46 32 61
532 560 397
Jan 2012 Feb 2012 Mar 2012
53 66 39
53 119 158
Jan 2012 Feb 2012 Mar 2012
142 296 414
10 6 0
8 20 40
160 322 454
*From year toto date * from year date
561266 V.J. Pamensky Canada Inc 1/4h · qpv STATS 12
SERVICE
MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
FAST NUMBERS
9,000,000
15,600,000
Barrels of liquids per day produced in the United States in 2011, says Citigroup.
Estimated United States daily liquids production in 2020, says Citigroup.
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, April 12, 2012 Source: Rig Locator
Alberta, April 2012 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
143
458
601
24%
26
27
53
49%
Manitoba
-
19
19
0%
Saskatchewan
9
109
118
8%
178
613
791
23%
-
2
2
0%
178
615
793
22%
British Columbia
WC Totals
OIL WELLS
Alberta
Apr 12
GAS WELLS Apr 11
Apr 12
Apr 11
Northwestern Alberta
192
165
126
212
Northeastern Alberta
52
176
0
3
193
211
14
206
78
96
7
547
515
648
147
968
Central Alberta
Eastern Canada New Brunswick TOTAL
Southern Alberta TOTAL
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada, April 12, 2012 Source: Rig Locator
Alberta, April 2012 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
C OA L B E D M E T H A N E
Alberta
Apr 12
Apr 11
BITUMEN WELLS Apr 12
Apr 11
356
407
763
47%
Northwestern Alberta
192
165
126
212
British Columbia
3
27
30
10%
Northeastern Alberta
52
176
-
3
Manitoba
7
11
18
39%
Central Alberta
193
211
14
206
Saskatchewan
114
82
196
58%
78
96
7
547
WC Totals
480
527
1,007
48%
515
648
147
968
PLUG MILLING FRAC SEAT MILLING TT FISHING
Southern Alberta TOTAL
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O I L & G A S I N Q U I R E R • MAY 2 0 1 2
13
Ulterra’s Jason Maw Presents an SPE Paper
“Paradigm Shift in PDC Bit Design for Canadian Heavy Oil Sands”
at the 2012 SPE Heavy Oil Conference - Canada June 12-14 | BMO Centre at Stampede Park | Calgary, AB
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Feature
TAP
TURNING on the
Drilling heats up in the Bakken, with enhanced recovery schemes also taking shape BY DARRELL STONEHOUSE
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
15
Feature
T
he Bakken tight oil play in southeastern Saskatchewan is quickly moving from an exploration play into a development play. Production has climbed to around 65,000 barrels per day in the field, and operators in the play are now working through a huge inventory of development wells to be drilled, along with pushing forward with enhanced recovery plans to access more of the billions of barrels of crude trapped in the tight rock. Efforts are also under way to break the transportation bottleneck limiting access to premium markets for Bakken oil. Crescent Point Energ y Corp. has emerged as the dominant producer in the Bakken, with over 1,100 net sections of development land and a drilling inventory of 3,800 wells. The company believes its Bakken acreage could deliver as many as 300 million barrels in reserves, and production could peak at as high as 266,000 barrels of oil equivalent per day. Early this year, Crescent Point continued consolidating its position in the Bakken through another series of
acquisitions, while pushing forward with aggressive drilling plans and enhanced recovery efforts. In February, the company announced it was purchasing 25 net sections of land with current production of 2,900 barrels equivalent per day from competitor, PetroBakken Energy Ltd. The price tag was $427 million. It also purchased Reliable Energy Limited, adding approximately 1,000 barrels of oil equivalent per day in the Kirkella/Manson area, and a land base of more than 135 net sections in southern Saskatchewan and southwestern Manitoba. The assets of Reliable include internally assigned proved-plus-probable reserves of 4.1 million barrels, and an internally identified drilling inventory of 36 net drilling locations. Crescent Point cont inued working through its huge drilling inventory throughout the winter, drilling 87 (71.4 net) oil wells in southeastern Saskatchewan and Manitoba, achieving a 100 per cent success rate. Of the wells drilled, 67 (57.5 net) were horizontal wells in the Bakken light oil resource play. In total, during 2011, the company drilled 193 (166.8 net) Bakken horizontal
oil wells, achieving a 100 per cent success rate. The company plans to drill up to 154 net wells in the Viewfield Bakken play during 2012, and to spend approximately $425 million, including around $50 million for land, seismic and facilities. Crescent Point is also advancing its enhanced recovery scheme in the play. Production performance from water injection patterns in the Viewfield Bakken resource play continues to exceed its expectations and has demonstrated the applicability of waterflood to the play, according to Crescent Point. During the final quarter of 2011 it began injecting water into four additional wells. By yearend 2011, the company had converted a total of 24 producing wells to injection wells in the play. Including wells converted to date in 2012, Crescent Point has 32 water injection wells in the play and expects to have approximately 60 by yearend 2012. With the recently announced agreement to acquire PetroBakken’s interests in the proposed Viewfield Bakken waterflood area, Crescent Point says it intends to accelerate plans to implement unit-wide waterfloods.
The Dreaded CRA Tax Audit: tax tips for the self-employed
Does the CRA target small business owners and the self-employed?
I am being audited. What can I do to lessen the potential blow?
The CRA focuses on those groups who are more likely to omit or misrepresent information on their tax returns, one of whom is, according to the CRA, the self-employed.
1. Consult a tax lawyer. Yes, a tax lawyer is advising you to consult a lawyer. Nevertheless, the key to being audited without your tax bill doubling is to ensure the audit is conducted fairly - without intimidation. This is best achieved with the representation of a tax lawyer, who is trained to know the law and the CRA’s internal policies and, unlike other tax professionals, is trained to fight for your rights. 2. Be nice. No one likes being audited, but taking it out on the auditor will get you nowhere. 3. Be on guard. Avoid getting chatty and volunteering more information than necessary that can later be used against you. 4. Be organized. It may be tempting to dump a box full of financial records onto the auditor’s lap, this will only serve to motivate the agent to work harder to find omissions and mistakes in your return. Keeping your records organized will, at the very least, lend credibility to you as a responsible businessperson.
Is there anything I can do to avoid a tax audit?
838667 Barrett Tax Law 1/2h · hp editorial
The following strategies can be used to reduce the number of red flags that may come up with your file, thereby reducing the likelihood of an audit: 1. File on time! Nothing places a red flag faster than a late tax return, so get your return in by the deadline. The same holds true for filing too early.
2. Be honest and consistent. The CRA has tools to investigate and gather information about your industry. If your numbers don’t fit the typical profile, then chances are you will be audited. Also, major changes in income, expenses or tax deductions from one year to the next will raise suspicion.
3. Avoid declaring business losses year after year. A reasonable amount of losses is fine; however, continuous business losses over a few consecutive years will alert the CRA.
4. Select your partners wisely. Any close association you make with other businesses or individuals who had or currently have problems with the CRA may result in a tax audit.
5. Inform yourself. Knowing your rights will help you be better prepared when facing an audit. The CRA publishes the Taxpayer’s Bill of Rights, and although some of these rights are not technically legal rights, it is still useful to know the principles behind which the CRA hopes to conduct their tax audits.
*Visit www.fightthecra.ca/free-consultation for details
16
MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
i
Feature
Photo: The Pipeline News
The company also continues building out infrastructure to ease bottlenecks in getting Bakken oil to market. Late last year Crescent Point completed the construction of approximately 100 kilometres of pipeline-gathering systems in the Viewfield area. It has also completed lease preparation in the Stoughton area for oil-loading rail facilities and ordered trans-loaders to fill rail cars with trucked-in oil. Rail transport will allow it to diversify its markets for Bakken crude oil and to more effectively manage pipeline disruptions, says the company. The rail facility became operational in firstquarter 2012. More than 2,500 barrels per day of Bakken production was delivered through the facility in February, and the company expects March deliveries through the facility to be approximately 6,000 barrels per day. “The beauty of once it’s on rail is that it can go any where in North America,” said Trent St a ngl, v ice president of marketing and investor relations for Crescent Point, i n a n nou nc i ng
A Halliburton crew at work in the Bakken last summer. Development drilling will keep industry busy for the next few years in the play.
566238 ZCL Composites Inc 1/2h · hp feature TM
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
17
Photo: Gerald Ford
Feature
Crescent Point is sending over 6,000 barrels per day to market by rail.
the company’s year-end results. “It allows us to reach markets outside of the U.S. Midwest. We can get to the Gulf Coast, we can get to the east coast, we can get to the west coast. It really allows us to diversify our pricing and manage pipeline risk.” Legacy Oil + Gas Inc. is also delivering strong results in the Bakken, while adding to flows out of the region through the drillbit in the nearby Spearfish play in Manitoba. At its Bakken play at Taylorton, Legacy continues fine-tuning its fracturing program to drive production increases. Legacy drilled nine wells that had 30-day initial production rates in excess of 260 barrels equivalent per day per well. These wells had 90-day average production rates of 260 barrels equivalent per day per well, and six-month production rates averaging 190 barrels equivalent per day per well. Like Crescent Point, Legacy is also advancing waterfloods to capture more resource from the Bakken. The company plans to expand its 2011 waterflood project this year. This pilot waterflood could lead to incremental reserve bookings and lower production-decline rates, and could be
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MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
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Legacy is leveraging its tight oil knowledge developed in Saskatchewan in the Spearfish play in Manitoba and North Dakota. further expanded depending upon results, says Legacy. At Star Valley, Legacy is working to expand the Bakken play using multistage fracking in the Heward area. Two Legacy operated wells brought on in the first quarter of 2012 have 30-day initial production rates of 225 barrels per day per well, and current production is still approximately 195 barrels per day per well. As a result, the company believes the Bakken play boundaries have expanded and has therefore increased its drilling location inventory to more than 50 net wells in Star Valley. Legacy has also remained active, drilling conventional Mississippian horizontal wells throughout its southeastern Saskatchewan properties. These wells typically cost about $1 million to drill, complete, equip and tie-in as they generally are not fracture-stimulated and have excellent rates of return and quick payouts. Legacy is leveraging its tight oil knowledge developed in Saskatchewan in the Spearfish play in Manitoba and North Dakota. In the first quarter of 2012, the company drilled 49 (35.1 net) wells, all targeting light oil, with a 100 per cent success rate. This total included 13 (10.2 net) horizontal wells in its Spearfish play at Pierson, Man., and Bottineau County, North Dakota. At Pierson, production rates from Legacy-drilled wells are: the 30-day average of 16 producing wells is 96 barrels of oil per day; the 60-day average of 12 wells is 86 barrels per day; and the 90-day average for 10 wells is 95 barrels per day. Legacy noted that it has achieved these rates while constraining production to maximize ultimate recovery. All of the above wells carry significant fluid levels, with some wells having fluid just below surface. The company estimates that initial productive capability of these
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Pierson wells would be far in excess of the constrained rates. The five wells with the longest producing history (147 days on average) have averaged 101 barrels of oil per day per well over this period. The company believes these achievements will lead to superior longterm performance, higher per-well reserve bookings, plus additional locations booked. Legacy has identified 210 net locations on its lands at Pierson, approximately 77 per cent unbooked in the most recent independent reserves report. Current production
development opportunity that has been essentially unbooked in the recent independent reser ves report. Production results from Legacy drilled wells are as follows: the 30-day average of five producing wells is 90 barrels per day; the 60-day average for five wells is 102 barrels per day; and the 90-day average for five wells is 98 barrels per day. The company has also drilled two stratigraphic wells on the northern portion of its lands confirming net pay of approximately nine metres, porosity of 13.1 per
The total Spearfish play developmentdrilling inventory of 440 net potential locations (88 per cent unbooked) is based on eight wells per section. Based on other operators’ results in the play, Legacy’s location count could increase by 50 per cent through downspacing. In addition, the company is evaluating the waterflood potential in the play and anticipates recovery factors of up to 14 per cent, based on analogous pools. PetroBakken is back on sure footing in the Bakken after a successful winter drilling
Petrobakken replaced 173 per cent of Bakken production in 2011. in the area is greater than 2,000 barrels per day. The company is now building out infrastructure, and with the installation of a central oil battery and the tie-in of 29 wells thus far, operating costs are anticipated to improve significantly. At North Dakota, the company has had similar success in the Spearfish. Legacy said its lands in Bottineau County represent a significant light oil
cent and original oil in place of greater than 10 million barrels per section. Legacy has identified 230 net locations on the north portion only of its lands in Bottineau County, approximately 97 per cent unbooked in the most recent independent reserves report. This location count could grow significantly as Legacy derisks the opportunity on the southern portion of its lands over the coming years.
season, company president and chief executive officer John Wright reported to share holders in March. “We drilled 101 [74 net] wells in the Ba k ken business unit, of which 47 net were bilateral wells, and achieved a 99 per cent success rate,” Wright said in announcing
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year-end results for 2011. “Our average production in the fourth quarter was 22,588 barrels of oil equivalent per day. The Bakken business unit grew [provedplus-probable] reserves by 7 per cent to 88.5 million barrels, replacing 173 per cent of 2011 production.” Like its competitors, PetroBakken is also working towards extending the life of its Bakken resource and recovering more reserves through enhanced recovery. The difference is that PetroBakken is using natural gas rather than water to force the oil from the tight rock. “We also continued to advance our enhanced oil recovery efforts through the initiation of five EOR [enhanced oil recovery] projects in the Bakken that are currently at various stages of implementation. Early indications suggest the technology has the potential to increase recovery rates and further attenuate decline rates,” said Wright. With production on the upswing and take-away capacity tight, rail is becoming a preferred method for moving Bakken crude to market. Railway giant Canadian Pacific is the latest to enter the Bakken with a new
Drilling crews are off to a brisk start in 2012 in southeastern Saskatchewan, making up for lost ground due to the wet conditions last summer.
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“ The model we developed in North Dakota is proven and we’re now bringing
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that north.”
— Tracy Robinson,
vice-president, CP energy and merchandise
transload facility, operated by Bulk Plus Logistics in Estevan, Sask. This is in addition to railcar loads already moving out of the Dollard, Sask., transload facility on the Great Western Railway, a short-line partner of Canadian Pacific (CP). This oil is destined to various refineries in both Canada and the United States. The Bakken Formation, encompassing sections of Saskatchewan and North Dakota, is a key area of focus for CP and part of the railway’s growing energy portfolio, according to the company. In the past three years, the volume of crude oil delivered by rail has increased significantly. Volumes of rail shipments out of North Dakota, for example, have grown from approximately 500 carloads in 2009 to more than 13,000 carloads in 2011, and are expected to increase to 70,000 annual carloads in the future. “To move the crude by rail, CP will take what it has learned and apply it in the emerging Saskatchewan and Alberta Bakken markets,” said Tracy Robinson, C P energ y a nd merc ha ndi se v ice president. “The model we developed in North Dakota is proven and we’re now bringing that north.” “To fully capitalize on these opportunities, CP has established a specialized energy development team to position CP’s products and capabilities in this rapidly emerging marketplace,” Robinson added. Work i ng w it h t he development team, potential crude-by-rail shippers in Saskatchewan have been using CP’s service to test the viability of rail transport to their end terminals. CP is investing more than $90 million to enhance capacity on its U.S. main line south of Saskatchewan, through North Dakota and into Minnesota to handle anticipated increased Bak ken crude shipments. This includes upgraded track and sidings.
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Fine-tuning
fracturing Operators focus on fracturing density, fluid choices and improving processes By Darrell Stonehouse
ong horizontal wells with multistage fracturing treatments have become the standard for accessing tight oil and gas resources across North America in the last five years. Thousands of wells have been drilled, with tens of thousands of fracture stages completed. As the data is gathered, operators are fine-tuning their drilling and completion programs, custom fitting them to the formation targeted. The trend is for greater fracture density, along with a move towards slickwater fracs in many plays. The Bakken in North Dakota and the Marcellus shale play in the northeastern United States have been ground zero in the quest to increase fracturing density along extended-reach horizontal wells. In March of last year, Baker Hughes Inc. reported its successful installation of a 40-stage open-hole completion system in the Bakken for Whiting Petroleum Corporation. At the time the well marked the most stages ever performed in a single-lateral fracsleeve/packer-completion system, the company said.
Baker Hughes’ FracPoint EX-C multistage fracturing system was used in Whiting’s horizontal well, Smith 14-29XH, in the Bakken shale. “The industry continues to push the limits of total frac stages in horizontal completions in the Bakken Shale and other unconventional reservoirs,” said Paul Butero, president of the U.S. Land region for Baker Hughes, in announcing the record well. The company’s FracPoint product features a modular design that can be optimized according to customer specifications. In many areas of the Williston Basin, for example, Baker Hughes’ custom-designed reactive element packers (REPackers) are used in the FracPoint EX-C system to isolate intervals of a horizontal section, while frac sleeves are used for the precise delivery of the fracture treatment. Reactive element packers are a versatile option that allow for a wide range of open-hole sizes and improve the capabilities of packer and sleeve completions. O I L & G A S I N Q U I R E R • MAY 2 0 1 2
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A small frac job in southern Alberta. Producers are fine-tuning their programs based on the geology of the formations they operate in.
Photo: Gerald Ford
FracPoint EX-C extends current capabilities to 40 stages via 1/16-inch incremental stages in ball size, to achieve an increased number of ball seats. The patented design provides additional mechanical support to the ball during pumping operations. The impact of the denser fracture treatments can be seen in the results of Brigham Exploration Company in the North Dakota Bakken. To date, based on publicly available information, Brigham has the four highest-initial-rate Bakken wells and seven of the top 10 initial-rate Bakken wells in the Williston Basin. Brigham has now completed 56 consecutive long-lateral high-fracstage wells in North Dakota, with an average early 24-hour peak flow-back rate of approximately 2,884 barrels of oil equivalent. The company has been applying between 30 and 40 frac stages per well in the play. In the Marcellus Shale play, Calgary-based Packers Plus Energy Services Inc. has pushed the envelope even further, installing a 60-stage open-hole completion, the largest job to date in the prolific play. The installation used 124 tool assemblies in a row. “This job in the Marcellus Shale demonstrates the breadth and depth of our technology,” said Dan Themig, president of Packers Plus. “We had no issues sending 61 RockSEAL packers downhole in a 3,600-foot lateral. This hybrid system features our latest technological innovations in one well.” Packers Plus worked closely with the operator in the planning stages to ensure that the open-hole system met all of the operator’s design requirements. This included detailed pre-job calculations and full operational contingency plans. “Preparation before the job was key,” said James Athans, U.S. general manager. “This completion included our new SF Cementor stage collar and RepeaterPORT sleeve in a hybrid of StackFRAC and QuickFRAC systems. It was a complex design that met the unique requirements of the operator.” In recent years, the move to more stages and shorter stage lengths has dominated the open-hole completions industry, according to Themig. 26
MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
“We are seeing that operators want more and more stages,” said Themig. “Our work in the Marcellus, James Lime, Bakken and other U.S. formations has all moved in this direction. With our most recent product launches, we have answered the need for more stages and this job demonstrates our ability in this area.” Packers Plus’s RepeaterPORT sleeve, is the key technology enabling the greater fracturing density. The new stage-multiplier technology is the first of its kind in the industry, Themig says. “The RepeaterPORT sleeve represents a great innovation within our industry. We can actually drop the same-sized ball multiple times and activate specific ports within the system,” he explains. “The advantage for operators is that they can increase stage numbers, increase ultimate recovery, and increase ball-seat size, which reduces friction pressures allowing for higher-rate treatments.” The RepeaterPORT effectively increases the number of stages available in the StackFRAC HD system. By using the same size ball, the RepeaterPORT sleeve multiplies the number of available stages that can be fractured, allowing for optimization of frac crews and the use of less frac fluid. There are a variety of ball-seat sizes allowing numerous stages to be run in sequence. While the number of frac stages increases, operators are also focused on finding the most cost-effective fluids for the targeted formation. Spartan Oil Corp. has been one of the most active players in the Cardium play in Alberta, with plans to drill 46 wells this year. To date in 2012, the company has drilled a total of 12 (10.3 net) horizontal wells at its Keystone property. This brings the total well count to 27 (22.1 net) horizontal wells drilled since Spartan began operations on June 1, 2011. The company has tested several different completion techniques in an effort to maximize the productivity of the wells, including oil-based fracs, nitrified surfactant foam fracs, gelled water fracs and slickwater fracs. “We have seen improvements in both productivity and costs as a result of these efforts,” the company said in a press release.
Feature Of the wells drilled to date in 2012, two (1.5 net) have been completed with nitrified surfactant foam fracs, six (5.9 net) have been completed with slickwater fracs and one (0.97 net) has been completed with a gelled water frac. Results are still preliminary, but the company said it is “very encouraged” by the initial results from the slickwater fracs. There is not enough production data “ As we progressed on available to date to assess the each well, we cut back results on the gelled water our frac program a little completion. As an example of this, the bit. We will likely company recently completed two wells in the interior of Unit reverse that trend, as 2 that are in close proximity to earlier fracs with more each other. stages resulted in One of the wells was completed with a 17-stage slickbetter wells than the water frac and the other was smaller slickwater fracs completed with a 17-stage nitrified surfactant foam with fewer stages.” frac. The initial 30-day production (IP30) rate for the — Brian McLachlan, well that received the slickpresident, Yoho Resources Inc. water frac treatment was 145 barrels per day of oil, while the other well achieved an IP30 rate of 119 barrels per day. Calgary-based GasFrac Energy Services Inc. is making major inroads with its propane-based fracturing system in the Deep Basin and other liquids rich gas plays. The company recently
signed a three-year deal to provide fracture stimulation service to Husky Energy Inc. for its operations at Ansell in the Deep Basin. Its technology has also proven its worth for Artek Exploration Ltd. at its condensate play at Inga in northeastern British Columbia. Last April Artek Exploration Ltd. reported success using a 12-stage fracture stimulation program using GasFrac’s propane frac technology at Inga. The final rate after a 43-hour cleanup, and a 27-hour flow test or 70-hour flow period, was restricted at five million cubic feet per day (of which approximately four million was formation gas) and approximately 1,400 barrels per day of condensate for a total rate of approximately 2,040 barrels of oil equivalent per day, at a flowing pressure of 1,070 pounds per square inch (7,373 kiloPascals). GasFrac currently has eight sets of equipment operating (five in Canada and three in the United States) with two additional sets being delivered. As knowledge has accumulated, operators are fine-tuning multistage fracturing programs to various plays. And probably no one has done more experimentation with horizontal wells and multistage fracturing in tight oil plays than Penn West Exploration. In the Cardium the company reports two different drilling and completion techniques being used in its core areas. At Willesden Green and West Pembina, Penn West is drilling 1,200–1,400metre laterals, with 14–20 fracture stages of 20–25 tonnes per stage. At Alder Flats, it is drilling monobore wells with the same length laterals but completing as many as 25 stages. Penn West is using the ball-drop system for its completions in the Cardium. In the Swan Hills carbonate play, Penn West is drilling 1,200– 1,400-metre laterals with intermediate casing and lines being
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used in the wellbore. It is averaging 10–12 frac stages, using 900–1,000 cubic metres of hydrochloric acid per stage. In the Viking tight oil play in Saskatchewan, Penn West is drilling 600-metre laterals using the monobore technique. It is averaging 15 stages per well, with each stage averaging 15 tonnes. It is using the ported collar system to place frac stages in the Viking. In the Spearfish play in Manitoba, Penn West is again drilling 600-metre horizontal laterals using the monobore technique. It is averaging 17 fracture stages per well, with each frac averaging five tonnes. Its completion technology of choice in the Spearfish is the ported collar/mongoose system. But as drilling and completion systems take shape in existing plays, new plays are developing and the testing begins anew. Yoho Resources Inc. is in the process of developing its system in the emerging Duvernay and Montney plays in northwestern Alberta. Yoho Resources Inc. plans on drilling four or five wells strategically located across its acreage in the Duvernay this year, along with four or five wells in the Montney in northeastern British Columbia. Yoho has completed four wells in the Duvernay so far, each with better results than the one before it. Gas test rates ranged from 2.1 million cubic feet per day, to 7.7 million cubic feet a day with free condensate production rates of 42, 71, 92 and 109 barrels per million cubic feet, as Yoho improved its completion technique. “With each subsequent attempt at completions, we’ve seen better results. From our first well, which we were only able to complete part of due to a ruptured liner, we have improved our techniques,” Yoho president Brian McLachlan said. Development will likely be six to eight wells per section with possibly more in the thickest part of the Duvernay, he said. Drilled from pads, the horizontal wells are expected to cost an average of roughly $10 million apiece to drill, case and complete. In the Montney, the company is focused on increasing the density of its fracture stages going forward. At its Nig Creek play, Yoho has drilled three horizontal wells in the Upper Montney and one horizontal well in the Lower Montney. The company’s first well in the Nig Creek Upper Montney tested 6.3 million cubic feet per day a day of gas. Although it initially tested only 12 barrels per million cubic feet of free condensate, later production rates were 40 barrels of liquids per million cubic feet (including 28 barrels of condensate). The other two wells in the Nig Creek Upper Montney tested 5.6 million cubic feet per day with 21 barrels of free condensate per million cubic feet, and 3.5 million cubic feet per day with 12 barrels of condensate per million cubic feet. “As we progressed on each well, we cut back our frac program a little bit. We will likely reverse that trend, as earlier fracs with more stages resulted in better wells than the smaller slickwater fracs with fewer stages,” McLachlan said. “By year-end 2012 we should have an excellent quantitative evaluation of our Duvernay and Montney plays and a detailed development plan for each,” McLachlan said. “2013 will be our first full year of development on both of those plays.”
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General News
Oilsands gas demand expected to double or triple
Photo: Joey Podlubny
By Lynda Harrison
Gas use in the oilsands is expected to climb to 3.6 billion cubic feet per day by 2045, says CERI.
Oilsands projects’ need for natural gas is expected to double or triple from current levels by 2045, says a new study by the Canadian Energy Research Institute (CERI). Under CERI’s robust production projection, natural gas use is estimated to rise from 1.2 billion cubic per day in 2010, to 3.59 billion cubic feet per day in 2045 under its “high-case” scenario, 3.2 billion cubic feet in its “reference-case” scenario and 2.75 billion cubic feet per day under the “low-case” scenario. The study, entitled Canadian Oil Sands Supply Costs and Development Projects (2011–2045), provides capacity projections for three scenarios, in addition to an unconstrained scenario. In each scenario, oilsands capacity grows significantly, exceeding four million barrels per day by 2045. The rate of expansion is higher at the front end of the forecast period, and becomes more or less flat past 2027. Over the 35-year projection period, from 2011 to 2045 inclusive, the total initial capital required for oilsands projects is projected to be $253 billion under the
high-case scenario, $220 billion under the reference-case scenario and $190 billion under the low-case scenario. With careful planning, the referencecase scenario could be a viable target. By 2015, $17.4 billion in capital investments will be required; however, in 2030 the required investment drops to $1.3 billion, or a total of $216.8 billion between 2011 and 2030. Ongoing investment, in the form of sustaining capital, will take place on an annual basis. Compared to figures from the 2010 update, over the 35-year projection period the total initial capital investment fell by 17 per cent. Capital investment for in situ, upgrader and mining projects decreased by two, 15 and 24 per cent, respectively. In the 2011 update, over the 10-year window from 2011 (inclusive) to 2020, capital investment for in situ and upgrader projects increases, but for mining projects it decreases by 58 per cent, as most of the capital investment will be targeted for in situ projects. New investment dollars start declining by 2027 and approach zero by the end
of the projection period. This does not reflect a slowdown in oilsands, merely a lack of new capacity coming on stream; it relates to CERI’s assumptions for project start dates, and announcements from the oilsands proponents. Supply costs in this study are calculated using an annual discount rate of 10 per cent (real), which is equivalent to an annual return on investment of 12.5 per cent (nominal) based on the assumed inflation rate of 2.5 per cent per annum. Based on these assumptions, the supply cost for the production of crude bitumen using SAGD, surface mining and extraction, and integrated mining and upgrading has been calculated for a hypothetical project. It would be expected that Canada and the United States could be engaged in an energy exchange—Canadian oil for U.S. natural gas—that further enhances the trade relationship between the two countries, says CERI. Also, the prospects for technology switching and efficiency improvements are substantial and will likely put downward pressure on the industry’s natural gas requirements, it adds. CERI says operators have learned from the most recent boom and are intently focused on controlling cost inf lation; however, if oil prices further strengthen, the research institute expects the pace of development to increase in response. The forecast indicates gas prices will remain flat (in real terms) for the first decade of the forecast, gradually increasing and surpassing the $6-per-millionBritish-thermal-units mark, but never reaching the levels seen in the 2007-08 period. This has created favourable nearterm conditions for thermal oilsands production, such as steam assisted gravity drainage (SAGD) or cyclic steam stimulation (CSS). The initial capital costs have decreased for SAGD producers by 17.6 per cent from 2010, to $31,952 per barrel per day of capacity; and for mining by 13 per cent, to $72,938 per barrel per day of capacity. “Supply costs are lower this year than they were last year,” Dinara Millington, O I L & G A S I N Q U I R E R • MAY 2 0 1 2
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General News
CERI’s director of research, told the DOB. “This is due to our initial capital per barrel of flowing capacity [being] lower across all the generic projects that we evaluated for the supply cost calculation.” The non-energy total operating costs have increased to $9.20 per barrel of
production for SAGD producers, and mining saw an increase to $14.60 per barrel of produced bitumen. These costs ref lect the fact that ongoing labour, materials and equipment costs have seen the greatest escalation in recent years, says Millington.
CERI says its reference-case scenario provides the most plausible view of the oilsands production, in which projected volumes will increase from 1.5 million barrels per day in 2010, to 3.3 million barrels per day by 2020, and 5.4 million barrels per day in 2045.
NGL production steady By Lynda Harrison Alberta’s natural gas liquids (NGLs) production appears to be stabilizing after years of decline, while NGL storage in western Canada—with approximately 17 million barrels of capacity—is definitely in short supply, a recent conference heard. Steven Paget, v ice-president of energy infrastructure at FirstEnergy Capital, said the unprecedented spike in Alberta propane demand in 2010-11 was caused by withdrawals for use in oilsands extraction tests. “I have heard that there is demand for storage approximately equal in capacity of the storage that we already have. The problem is getting the specialty drilling rigs to drill and wash the caverns,” he told the Canada & U.S. Western Midstream Summit in Calgary. FirstEnergy assumes AECO gas prices this summer will drop to $1 per thousand cubic feet, he said. If that happens, this will send many dry-gas cash netbacks to zero or below, while rich gas will still return over $2 per thousand cubic feet to the producer, said Paget. “Therefore rich gas production and liquids extraction will continue.”
Each NGL stream has its own supply and demand picture, and the data available changes with each commodity, he noted. “Liquids demand in PADD II still dominates our destiny here in western Canada,” he said. “We depend on PADD II demand; it’s the one place we have preferential access versus, say, Gulf Coast, but I’m concerned here that Utica [and] Marcellus [shale gas] volumes will have preferential access to PADD II, and push back at us over the next five years.” The approximately 300,000 barrels per day of growth in U.S. ethane production since 2006 is larger than the entire Alberta ethane industry, Paget noted. Ethane, which is used as a feedstock in petrochemical plants, is in short supply in the province but FirstEnergy believes the situation will be alleviated within three years. Meanwhile, butane use in Alberta is down 18 per cent since 2004, said Paget. Although takeaway capacity of NGLs in the United States is currently constrained, 2.1 million barrels per day of new pipeline projects will offer some relief and even some overbuild in some
regions, said Jennifer Brickle, a senior energy analyst with Bentek Energy LLC, a U.S.-based energy markets information and analytics company. After decades of declining production, the United States experienced its third consecutive year of oil output growth in 2011. Bentek estimates that combined Canadian and U.S. oil production will grow more than 3.1 million barrels per day by 2016, reaching 12.1 million barrels per day and surpassing the previous record of 11.2 million barrels per day set in 1973. Bentek expects the United States to increase oil production to 2.2 million barrels per day during this time, most of which will be light or intermediate crudes. In addition, crude oil imports into the United States are expected to rise by 900,000 barrels per day. According to Bentek, the U.S. refining industry is expected to be the primary destination for Canada’s additional crude supply. However, five of the six major pipeline systems that move crude across the CanadaU.S. border are either full or constrained, and pipeline takeaway capacity will be limited until new pipeline expansions come online.
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Canadian crude oil production will grow 31 per cent to nearly four million barrels per day from 2011 through 2016, with almost all incremental supply transported to the U.S. Midwest and Gulf Coast for refining, says Bentek. This will lead to a 42 per cent or 917,000-barrel-per-day increase in Canadian crude exports to the United States, affecting the already constrained refinery and transportation markets, it says. A report by Bentek, Crude Awakening: Shale Boom Hits Oil, projects Canadian crude oil production growth of nearly
one million barrels per day in western Canada between 2011 and 2016 will stem predominantly from the oilsands in the Athabasca, Peace River and Cold Lake regions. A number of emerging unconventional oil plays will also add to this grow th, says Bentek, including the Alberta Bakken, Cardium and Viking plays, and all of this production will compete for pipeline space. Oil and gas exports to the Pacific are poised to grow, said Gerry Goobie, managing consultant at Purvin & Gertz Inc.,
adding the supply outlook depends on demand from oilsands, U.S. exports and LNG exports. If Pacific basin gas prices remain strong, Canadian LNG exports could exceed three billion cubic feet. “In the meantime, frac spreads are going to be high; everybody’s going to go after processing rich gas,” he said. “In order to survive we have to get cost out of the system. Western Canada is a very high-cost environment. We’ll either do it voluntarily or it will be forced upon us through bankruptcies, and so forth.”
CAPP recognizes HSE projects On Wednesday, the Canadian Association of Petroleum Producers (CAPP) presented recognition awards to six upstream companies for innovative projects demonstrating leading environmental, social, and health and safety performance. “The Responsible Canadian Energy [RCE] Awards is our means of recognizing leadership among our members in delivering environmental, social, and health and safety performance,” said Dave Collyer, CAPP’s president. “These awards shine a light on successful projects, and the people working hard on them to demonstrate and encourage continuous performance improvement.” CAPP’s 2012 RCE Awards had 29 project nominations with six companies receiving awards in five categories: • Health and Safet y Award: Shell Canada for its Scotford Tri-Partite Safety Leadership Initiative, and
Suncor Energ y Inc. for leading by metrics; • Social Performance Award: Devon Canada Corporation for its Conklingets-a-high-school project; • Environmental Performance Award: Statoil Canada for its innovative use of dogs to gather wildlife information; • President’s Award: Canadian Natural Resources Limited for both its Septimus electrification project and its Horizon oilsands wildlife management system; and, • Chair’s Award: Quicksilver Resources Canada Inc. for its timber use in northeastern British Columbia. RCE is a CAPP program designed to assess and report the environmental, social and safety performance of Canada’s oil and gas industry. RCE is also a mechanism for the industry to identify and share best practices, and to award specific projects with measurable results.
“All 29 projects nominated are examples of exceptional achievement,” Collyer said. “The combination of leading technology and innovation, along with the creativity and perseverance of these individuals and teams, helps to elevate our overall performance as an industry.” The RCE Awards are selected from the nominated projects by the RCE Advisory Group, which consists of external stakeholders from the landowner, investor, labour, environmental, business and academic communities. More than 600 people attended the awards ceremony a nd key note address by Alberta Premier Alison Redford. CAPP’s RCE program measures and reports on the Canadian oil and gas industry’s environmental, social, and health and safety performance in an annual report. — DAILY OIL BULLETIN
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British Columbia
B.C. turning to oil By Richard Macedo
MAR/11
MAR/12
MAR/11
MAR/12
WELLS SPUDDED
53
28
WELLS DRILLED
73
55
Photo: Joey Podlubny
“They are investigating the possibility of a regional resource-style oil play in the Triassic Baldonnel.” Adams said that studies are underway in these areas to correlate and compare detail facies and reservoir characteristics of the Birch Baldonnel ‘C’ oil pool. This involves detailed petrologic analysis, including thin-section petrography, to evaluate the reservoir quality, pore geometry and fluid sensitivities of the upper Baldonnel. British Columbia produced approximately eight million barrels of oil in 2010, about one per cent less from the previous year, marking the 10th year in a row of flat or decreasing annual production. According to the B.C. Oil and Gas Commission’s annual reserves report, a total of 19 oil wells were drilled in the province in 2010, compared to 31 in 2009. Drilling activity resulted in the discovery of one new oil pool—a single-well new pool called the
Cache Creek Doig BB. The largest positive revision to B.C. oil reserves resulted from a performance review of the Boundary Lake A pool, which accounted for 37 per cent of the total revisions in 2010. British Columbia’s oil fields continue to be dominated by secondary recovery schemes. Waterflood pools account for approximately 50 per cent of remaining oil reserves with the Hay River and Boundary Lake fields being the dominant contributors. Gas injection is currently occurring in four oil pools (Bulrush, Cecil Lake, Rigel, Stoddart West) and contributed about one per cent to the 2010 provincial remaining oil reserves. The province, though, is better known for its vast unconventional natural gas resources, but an export outlet to allow that gas to tap overseas markets will be key in ensuring resources from the Horn River Basin realize their full potential. For the time being, many producers at Horn River are committing the minimum drilling capital required to hold leases. Many wells remain on confidential status in the Horn River Basin. The Oil and Gas Commission (OGC) reported 392 million cubic feet per day in production from 98 producing shale gas wells at the end of 2010. “My guess is that the Horn River is producing close to 500 million cubic feet per day as we speak,” Adams said. Cumulative gas production in the Horn River to the end of 2010 was 74 billion cubic feet. Further south, the Montney enjoys an advantage in that it produces liquids, as opposed to the dry gas of the Horn River. “The liquids tend to be up where [Progress Energy Resources Corp.] is doing their work in the North Montney and then extending to the east a bit,” Adams said. “You tend to get more towards an oil window in that northeastern section of the Montney in the Umbach area, for example.” As much as 48 per cent of British Columbia’s gas-production stream in 2010 was from unconventional sources such as tight gas and some shale gas. Less than
With low gas prices, some B.C. producers are targeting known oil reserves in the province.
Although British Columbia is better known for its natural gas production and future potential, producers are poking around the province to see where horizontal well technology and fracturing could create opportunities to unlock more of its light and medium oil. British Columbia has produced only 25 per cent of the original oil in-place of 2.8 billion barrels, said Christopher Adams, an oil and gas specialist with the B.C. Ministry of Energy and Mines, following a presentation at the Infocast Canada and U.S. Western Midstream Summit. “Horizontal well technology and new fracturing methods could create terrific opportunities for British Columbia’s conventional light/medium oil, much of it located in well-known reservoirs,” he said. “For example, I believe some producers are doing some analysis of wells in the Stoddart and Birch areas (87-20 and 21W6 and 94-A-13). BRITISH COLUMBIA WELL ACTIVITY
MAR/11
MAR/12
WELL LICENCES
132
52
▼
▼
▼
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
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British Columbia
30 per cent of all gas wells drilled in British Columbia are conventional, vertical wells. “In the Montney, I’m seeing anywhere from 20 to about 90 barrels per million cubic feet,” Adams said during his presentation. “It varies throughout the Montney, but that’s the range I’m seeing. “When we look at other liquids areas throughout North America, the Montney’s
not particularly high in liquids, but certainly it makes the economics more feasible.” Land sales, meanwhile, have trailed off significantly. From a record $2.66 billion in 2008, the province collected $222.68 million last year. The Montney play trend accounted for 89 per cent of the 2011 B.C. land sale bonus total. Almost 85 per cent of wells rig-released in 2011 in the
Montney trend region listed the Triassic Doig and the Montney formations as the projected target. The number of wells drilled in the province has also fallen off after a record 1,435 in 2006, according to OGC statistics. There were 656 wells drilled in 2011, down from 701 the previous year. To February 17 of this year, 26 wells were drilled.
Collaboration cuts water management costs for Progress Last spring Progress Energy Resources Corp. found it had a surplus of produced water at its north Montney play in northeastern British Columbia. The mid-sized producer had no immediate need for the water since its hydraulic fracturing operations were finished for the winter. Disposing of the 5,000 cubic metres of produced water would cost money and put a lot of trucks on the road. Before committing to this costly option Progress looked for a more economical and environmentally attractive solution.
“Just by having some good dialogue with another producer, we found they were… short of water,” said Jim Stannard, Progress’s senior vice-president of development. A nother operator, it turned out, needed water and was prepared to truck fresh water from a distant source. Instead, the other producer used Progress’s produced water, avoiding the cost, carbon emissions and stakeholder aggravation of multiple truck trips. “So rather than then using 5,000 cubic metres of fresh water that they had to
truck in from quite a distance away, we were able to just truck our f luid from our site over to their site. They used our produced water,” Stannard recalled. “We also avoided a lot of trucking. And both companies saved a significant amount of dollars,” the Progress executive told the recent Canadian Business Conferences forum on shale gas and tight oil water management. Sharing produced water is one example of how collaboration can save time
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and money, improve ef f icienc y and reduce environmental impact. Royal Dutch Shell plc also recently found it was producing more water than it could use or store, so the surplus was destined for disposal. Instead, “we actually moved over 10,000 cubic metres of water to an area producer—water that would have come out of a freshwater source had they not had access to our excess produced water,” said Shawn Baxter, water project manager in northeastern British Columbia. Another area where producers can collaborate is information sharing. Secrecy typically surrounds land sales, but Stannard said in blockbuster plays like the Montney, the good land has already been posted and purchased. So there are no reasons for secrecy. “At this point…at Progress we’re prepared to share what we’re doing with other operators on the basis that…we can get information back from them, and we can all do a better job—be more efficient in our operations,” he said. “So when I talk to my staff about this, I encourage them to share information with other companies.” But it obviously isn’t going to work if the information is flowing in one direction only.
“A good example is we had one meeting with another operator, and we were telling them five pieces of information, and they were telling us half of one piece back,” Stannard recalled. “…But we have other operators we had meetings with where we had great interaction, and that’s been a very positive outcome for both companies.” Another key area where Progress believes collaboration will play a large role in the future is in coordinating industry efforts on things that need to be worked out between government agencies, between the producers themselves and with stakeholders. “From Progress’s perspective, we still believe that CAPP [the Canadian Association of Petroleum Producers] is the best vehicle for the producers to work together,” Stannard said. “CAPP provides the best venue for proceeding in our negotiations and discussions with various stakeholders and government groups.” But it is important to provide the resources. “So when we attend CAPP meetings and participate in groups, we try to send technical people that have technical knowledge about that particular topic. And
we also try to send people who have management authority to make decisions at the meetings and be proactive there,” said the Progress executive. “We think that participating in CAPP is more than just sending a person or two to sit in a meeting.” Stannard cited another specific example of producers cooperating to cut costs, eliminate duplication and increase efficiency. Progress and two other producers had separately approached the B.C. Oil & Gas Commission (OGC) for permits to build separate facilities to take water from a river in the northern Montney area. “Upon the suggestion of the OGC— which was a great suggestion—we got together the three producers, and we [are] now working on a proposal to construct a more permanent and more functional water-handling facility [for] withdrawal from the river,” he said. “The advantage here is that rather than having three operators all stepping on each other, getting in each other’s way with…smaller facilities, we can have one larger facility that’s more properly constructed with better access.” — DAILY OIL BULLETIN
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
37
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Delphi reports success at Bigstone
The Bigstone/Fir area is a drilling hotspot, with Delphi and other companies drilling more than 20 horizontals targeting the liquids-rich Montney.
Delphi Energy Corp. has successfully completed and tested its second Bigstone East Montney well (0.75 net) with a record horizontal length of 3,005 metres. The 4-2-60-23W5 well—with its surface located at 5-14-60-23W5, or five kilometres southwest of Delphi’s first Montney well—was drilled to a total measured depth of 5,867 metres. It was completed with a 20-stage fracturing program, similar to the first well, and flow-tested at an average restricted rate of 10.3 million cubic feet per day over the final 24 hours of the four-day flow period, at a flowing pressure of 6,000 kiloPascals. The well was also producing approximately 515 barrels per day of free condensate at the end of the test, although all of the load fluid hadn’t been recovered. Shallowcut plant recoveries of natural gas liquids at Bigstone East are expected to yield an additional 30–35 barrels per million cubic feet.
As previously reported, the company’s first horizontal well targeting the Montney formation at Bigstone East, with a surface location of 1-19-60-22W5, was successfully completed and flow-tested at an average rate of 12.5 million cubic feet per day, at a flowing pressure of 2,000 kiloPascals over the final 24 hours of the four-day flow period. The well was also producing approximately 770 barrels per day or 62 barrels per million cubic feet of free condensate at the end of the test, although 100 per cent of the load fluid had not been recovered. The initial flow-test results of both Bigstone East wells have exceeded Delphi’s expectations and with competitor drilling activity all around these lands, the remaining 31 net Montney horizontal locations identified at Bigstone East have been largely de-risked. In the current commodity price environment and based on
the well test data, the Montney production would have similar netbacks to the company’s operating netbacks achieved in 2011. The drilling rig is expected to move back onto the Bigstone East 5-14 surface location to drill another extended-reach horizontal well to the north over spring breakup. Industry horizontal-drilling activity in the Bigstone/Fir areas remains very busy where more than 20 horizontal wells have either been drilled, or are currently being drilled, into the Montney formation. Completion results reported to date have yielded strong natural gas test rates with some wells now reporting up to six months of production. Delphi and other operators in the area are using extended-reach horizontal wells with the horizontal lateral up to twice as long as earlier horizontal wells in the area. This reduces the number of wellheads required for a full four-well-per-section development by up to 50 per cent, with total project cost savings of approximately 35 per cent. The company expects to commission, for start-up by mid-April, its 100 per cent owned gathering system and 30-millioncubic-feet-per-day facility at Bigstone East. At Bigstone West, the 9-4-60-24W5 Montney horizontal well was drilled to a total measured depth of 5,396 metres from a surface location at 1-33-59-24W5 over the winter drilling season. The drilling and completion operations were successful as planned with the full length of the 2,289metre horizontal section encountering the anticipated reservoir-quality rock. Over the final six days of the test period, the well flowed at an average rate of 900,000 cubic feet per day of sweet natural gas, and consistently averaged 170 barrels per million cubic feet of free condensate/light oil (48 degree API), although 100 per cent of the load fluid had not been recovered.
NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY
MAR/11
MAR/12
WELL LICENCES
175
131
▼
MAR/11
MAR/12
WELLS SPUDDED
213
181
▼
MAR/11
MAR/12
WELLS DRILLED
282
285
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
39
Northwestern Alberta/Foothills
Shallow-cut plant recoveries of natural gas liquids (NGLs) are expected to yield an additional 40–45 barrels per million cubic feet. The well was completed using a similar fracture-stimulation design that was successfully used at Bigstone East. Although the natural gas test rate was below Delphi’s expectations, the major differences in test results compared to Bigstone East continue to make Bigstone West a compelling play, said Delphi. The combination of two- to three-times more free condensate/light oil, a 30 per cent higher plant NGL yield and sweet natural gas at a reservoir pressure 20–30 per cent higher than at Bigstone East suggests a different fracture-stimulation program designed more for an oil play would yield better flow results, it said. The well is expected to be on production in early April, giving the company time to evaluate the production performance as it plans a follow-up well. Delphi has accumulated a total of 45 (41.75 net) sections of undeveloped land prospective for liquids-rich natural gas in the Montney formation on two separate blocks in its core area of Bigstone within the Deep Basin of northwestern Alberta. The company holds 18 (14.75 net) sections of Montney rights on the Bigstone East block. At Bigstone West, the company continues to hold 27 sections (100 per cent) of
Montney rights. Delphi was successful in acquiring only minimal acreage in recent land sales as land prices have escalated to $1 million–$1.25 million per section. Given the company’s 9-4 well result, indicating a very rich NGL sweet-gas window or an emerging light oil play as well as other new confidential wells in the area, Delphi said its 27 gross sections represent a substantial position in the play. The company has a total inventory of approximately 100 horizontal Montney locations identified on its 45 (41.75 net) sections of land in Bigstone. Other emerging light oil and liquids-rich natural gas plays in the Dunvegan, Nordegg and Duvernay formations being drilled by industry at Bigstone offer additional potential on company lands. Delphi has actively drilled the Gething formation at Bigstone using vertical wells since acquiring the property in 2005. Technological advances in horizontal drilling and multistage fracturing have enabled the company to take a different approach to exploiting this complex natural gas– charged channel system. Although the Gething reservoir is not typically “tight” by resource-play standards, the application of this technology is a much more effective way to increase the ultimate recovery of the natural gas in the reservoir, traditionally done through a greater number of vertical wells per section.
The 13-16 well (0.65 net), with its surface at 3-16-60-23W5, was drilled and completed with a 10-stage fracture program successfully placed over an 879-metre horizontal section. After a two-day test, the well had a cleanup rate of 13.8 million cubic per day, at a flowing pressure of 4,300 kiloPascals. The production rate was still increasing when the well was shut-in to run production tubing. The well is expected to produce NGL yields of approximately 25 barrels per million cubic feet, based on existing Gething production in the area. The company has identified an initial 20 followup locations. With the success of the Montney program thus far, the current plan is to drill another Montney well through spring breakup and then reassess the natural gas environment, the disposition program, and Montney and Gething production performance prior to making firm plans with respect to a second-half-of-2012 capital program. As previously indicated, Delphi will provide 2012 guidance once production performance data is gathered for the three Bigstone Montney wells and the Bigstone Gething well. Some production history is required to appropriately forecast both natural gas production performance and condensate yields. — DAILY OIL BULLETIN
Yoho testing Montney, Duvernay this year Early Duvernay player Yoho Resources Inc. will drill four or five wells strategically located across its acreage in the emerging shale gas play this year, in order to glean the maximum reserve information, the company’s annual meeting heard. At Nig Creek in northeastern British Columbia—where Yoho has had similar success with an over-pressured tight gas play in the Upper Montney formation— the company also plans to drill four to five delineation wells, said Yoho president Brian McLachlan. Yoho was an early mover in the Duvernay at Kaybob in northwestern Alberta. “With land prices peaking at $3.5 million a section, Yoho’s initial eight sections on this play were purchased 40
MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
for $20,000 a section,” McLachlan told shareholders. Although the 75 per cent gas-weighted junior producer is obviously challenged by low gas prices in the short term, the longterm outlook is encouraging. In the meantime, high yields of natural gas liquids on its two major plays will improve its netbacks, said McLachlan. Exiting the fiscal year ending Sept. 30, 2011, Yoho’s estimated proved-plusprobable reserves totalled 14.03 million barrels equivalent—up 54 per cent over Sept. 30, 2010. But presumably that’s just the tip of the iceberg. “On our t wo big plays —t he Duvernay at Kaybob and the Montney at Nig—the reserves assigned for both of
those plays represent only four per cent of our land base on each of those plays,” McLachlan said. The Duvernay formation in Alberta has been generating much excitement because the resource is expected to be enormous and—more important at a time of low gas prices—liquids rich. Some observers, such as Encana Corporation, have expressed the hope that the Duvernay will be another Eagle Ford, the hot Texas shale play that has drawn major investment because of its high liquids content. “Unrisked reserve upside, net recoverable to Yoho, could easily be in the order of 450 billion cubic feet of sales gas and 60 million barrels of high-quality liquids,” McLachlan said of Yoho’s Duvernay acreage.
Northwestern Alberta/Foothills
The gas is expected to yield 100 –150 barrels of liquids per million cubic feet. Others obviously share his optimism. The Yoho president said industry land purchases in the play have totalled about $3.5 billion over the past 30 months.
Development will likely be six to eight wells per section, with possibly more in the thickest part of the Duvernay. Because Yoho got in so early, the junior was able to acquire 50 sections, “in what we now know to be the thickest portion of the high gas-liquids window in the Kaybob area,” he said. Yoho has completed four wells in the Duvernay, each with better results than the one before it. Gas test rates were 2.1 million cubic feet a day, 5.2 million cubic feet a day, 7.1 million cubic feet a day and 7.7 million cubic feet a day with free
• • • • • • • • • • • • •
condensate production rates of 42, 71, 92 and 109 barrels per million cubic feet. “With each subsequent attempt at completions, we’ve seen better results. From our first well [which] we were only able to complete part of [due to] a ruptured liner, we have improved our techniques,” McLachlan said. Development will likely be six to eight wells per section, with possibly more in the thickest part of the Duvernay, he said. Drilled from pads, the horizontal wells are expected to cost an average of roughly $10 million apiece to drill, case and complete. There are also ample facilities in the Kaybob area. Further bolstering the economics is the fact that the play qualifies for a fiveyear royalty of five per cent, thanks to two Alberta incentives—the shale gas program and the deep horizontal gas program. At Nig Creek, meanwhile, “we’ve had a similar magnitude of success in the Montney formation…. Our geologists recognized the anomalously thick and over-pressured Montney sediments in the Nig Creek sub-basin, which allowed us to put together a sizable land package
before many others recognized the potential in this unique geological situation,” McLachlan said. “We’ve now accumulated 20,000 net acres of land in here.” In the Nig Creek play, Yoho has drilled three horizontal wells in the Upper Montney and one horizontal well in the Lower Montney. The company’s first well in the Nig Creek Upper Montney tested 6.3 million cubic feet a day of gas. Although it initially tested only 12 barrels per million cubic feet of free condensate, later production rates were 40 barrels of liquids, including 28 barrels of condensate. The well into the Lower Montney tested one million cubic feet per day of gas with 75 barrels of condensate. “As we progressed on each well, we cut back our frac program a little bit. We will likely reverse that trend as earlier…fracs with more stages resulted in better wells than the smaller slickwater fracs with fewer stages,” McLachlan said. T he company plans to spend $35 million–$40 million in 2012 delineating the Montney and the Duvernay. — DAILY OIL BULLETIN
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Northeastern Alberta
Kearl remains on track By Elsie Ross
MAR/11
MAR/12
MAR/11
MAR/12
WELLS SPUDDED
111
152
WELLS DRILLED
139
155
Photo: Joey Podlubny
into legal challenges in the United States when it came to trucking them up from the port of Lewiston, Idaho. (The other 1,000 modules were built in Edmonton or other parts of Canada and were delivered on time and basically on budget.) When Kearl was sanctioned late in 2008, Imperial could not confirm there would be space in Edmonton or elsewhere in Canada, so it decided to have the modules built in Korea. At present, 75 modules are on the Kearl site with another 75 in assembly, or waiting to be assembled, in Edmonton. A workforce of 1,000 (in three shops) is working on their assembly. The remaining approximately 40 modules are in Pasco, Wash., a smaller port near Vancouver, waiting to be transported to Edmonton. The goal is to have all the modules to Edmonton and in the reassembly chain by early May. Each module has been identified as to where it is needed and the
critical path of start-up by year-end for the 110,000-barrel-per-day initial phase of Kearl. As of the end of February, Kearl was 89 per cent complete overall while construction progress on site was more than 80 per cent complete, said Glenn Scott, senior vicepresident, resources. The initial development haul truck fleet is on site and both electric mine shovels and the hydraulic shovel are ready for operation. Imperial expects to begin building the initial ore stockpile and advancing overburden removal in about three months. The Kearl expansion will bring on an additional 110,000 barrels per day of bitumen by late 2015. With future mine and debottlenecking plans based on actual operating experience, the long-term plateau volumes are expected to reach Kearl’s regulatory production limit of 345,000 barrels per day by 2020, he said. K ea rl — ow ne d 71 p e r ce nt by Imperial and 29 per cent by ExxonMobil Corporation—will be the first oilsands mining operation without an upgrader, as its proprietary paraffinic froth treatment technology produces a diluted bitumen that meets pipeline and refinery specifications. Imperial and ExxonMobil’s downstream personnel are working to enhance the valuations and the marketing of the new Kearl bitumen, and its refining technology tool kit is being employed to understand the characteristics of Kearl diluted bitumen and how to maximize its value in its refineries. Not all Kearl production will go to equity refineries; a good portion will go to third parties, March said. “Many times, it takes a period of time before the true value of a new crude to market is realized,” he said. “Should this occur, we have a large and flexible refining and logistics network that will be able to provide backstop processing capabilities and capture this value ourselves.”
The Kearl oilsands should be producing oil by the end of the year, according to Imperial Oil Limited.
Imperial Oil Limited is still committed to beginning operations by year-end at its $10.9-billion Kearl oilsands mine, despite delays it encountered in transporting Korean-made modules to Edmonton for reassembly, its top official said in March. “We are very confident that we’ve got the capability to meet year-end [start-up],” Bruce March, president, chief executive officer and chairman, told analysts at the company’s investor day in Toronto. “That’s certainly our goal…but it’s really about getting the utility modules reassembled and deployed at the Kearl site, buttoned together.” That will be followed by froth treatment and then whatever else is left. For Imperial, start-up means “making a finished product,” he said in response to an analyst’s question. March said Imperial is making good progress in the assembly of the 200 full-size modules that were built in Korea, but ran NORTHEASTERN ALBERTA WELL ACTIVITY
MAR/11
MAR/12
WELL LICENCES
86
42
▼
▲
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
43
Northeastern Alberta
Although there is adequate pipeline capacity out of western Canada for the initial phase of Kearl, new capacity will be required by 2015-16 when the Kearl expansion starts up. Imperial believes that the Keystone XL pipeline to the Gulf Coast will be built. In a presentation on technical leadership, March said that his company’s research in tailings management has
liquid very quickly, a process called CIMA (chemically induced micro agglomeration). The entire process can be made to occur within a continuous length of pipe. After a few days of drying, the flotation tailings deposited material is strong enough to use for reclamation and the separated water is clean enough to recycle and reuse. Imperial is currently in the process of securing a site for a field test next year.
An important difference for Kearl is that—after a few years of initial mining and a few years of the use of a tailings pond— it will treat its tailings streams as they are produced, significantly minimizing the size of the Kearl tailings pond.
focused on how to deliver a solution that meets the environmental regulator y requirements faster, at a lower cost. It has found ways to chemically “glue” the tailings particles together with a substance called an “inline flocculent,” so that the very fine solids separate from the
An important difference for Kearl is that—after a few years of initial mining and a few years of the use of a tailings pond—it will treat its tailings streams as they are produced, significantly minimizing the size of the Kearl tailings pond and the associated reclamation costs that come with it.
While the tailings thickener technology that Imperial has chosen to use at Kearl has a somewhat higher initial capital cost, over the life of the mine it will result in lower operating costs, chemical usage and material handling costs. Scientists in Imperial’s Calgary research centre are actively pursuing non-aqueous extraction (NAE), in which naturally occurring oilsands will be selectively separated with an organic solvent instead of being forcefully separated with hot water and the current bitumen extraction process. The solid sand and clay agglomerates are left behind for prompt placement back into the mine as dry tailings. After solvent is separated from the bitumen it is reused in the process. This technology worked successfully at the laboratory bench scale and the next step is to increase the scale of the technology in a pilot plant and eventually continue the scale up to a commercial pilot level. “This NAE technology would be a huge breakthrough from a number of perspectives,” said March. For example, energy costs would be much lower because the need for hot water would be largely eliminated and it would remove the need entirely for fluids tailings ponds.
ERCB conditionally approves Koch SAGD project near Cold Lake Koch Oil Sands Operating ULC has received conditional approval from Alberta’s Energy Resources Conservation Board (ERCB) to build and operate a steam assisted gravity drainage (SAGD) project in the Cold Lake oilsands. The two-stage Gemini Oil Sands bitumen recovery project will have a production rate of up to 11,200 barrels of bitumen per day. It will be located about one kilometre southwest of the community of Beaverdam. In its application, the company says the first stage will be 1,200 barrels per day from one well pair over two years. Given the proximity of the project to Angling Lake and several domestic stock and water wells, the ERCB required that— as part of its annual performance presentation—Koch provide a summary of its annual groundwater monitoring program report describing any thermal effects of the scheme on groundwater and Angling Lake. In its decision, the board said it will look to Alberta Environment and Water for advice 44
MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
on assessing these matters. Thermal effects that occur may cause it to modify or rescind this approval, said the board. In addition, prior to submitting any related Directive 56: Energy Development Applications and Schedules applications, Koch will be required to submit, for board review and approval, a plan to mitigate the potential impacts to surface water bodies from wells and facilities associated with Pads 101 and 103, which are within 100 metres of water bodies. The additional information would at a minimum include the following items: • a discussion of the preventive measures that will be employed at the facility to minimize the risk of a spill occurring and, in the event of a spill, the preventive measures for ensuring that the spill does not reach the water body; • a description of the proposed equipment, tanks and piping that will be located less than 100 metres from the water body and the fluids involved;
• a description of the types of automatic controls that will be installed; • a detailed survey plan that clearly identifies the location of the facility and its distance from the associated water body; and either, • the commitment to construct and maintain a berm around the perimeter of the equipment that will prevent any spill from reaching the water body (this berm should not be confused with the secondary containment requirements set out in Directive 55) or, • a description of an alternative method or operating condition that would demonstrate how the water body is protected. The board had scheduled a public hearing after receiving objections from four persons, but all objections were withdrawn following engagement in the ERCB’s appropriate disputes resolution program. — DAILY OIL BULLETIN
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Central Alberta
Perpetual reports loss, changes focus to heavy oil
MAR/11
MAR/12
MAR/11
MAR/12
WELLS SPUDDED
297
182
WELLS DRILLED
299
209
Photo: Joey Podlubny
The company’s board has approved a capital-spending budget to remain within funds flow for 2012. Capital activity for the remainder of the year will be focused on Mannville heavy oil exploration and development. Perpetual estimates 2012 annual production of 3,600 barrels per day of oil and natural gas liquids, 103 million cubic feet per day of natural gas, a $28-perbarrel differential between West Texas Intermediate and Western Canadian Select (WCS) reference prices, $96 million in operating costs, $28 million in cash general and administrative expenses and a 5.5 per cent interest rate on long-term bank debt. I n Nov e m b e r 2 011, Pe r p e t u a l announced that initiatives were underway for the sale of certain assets in the fourth quarter of 2011, and 2012 targeting proceeds of $75 million–$150 million to
be used to strengthen the company’s balance sheet and provide for the redempt ion of the company ’s $75-million, 6.5 per cent convertible debentures on June 30, 2012. In the fourth quarter of 2011, Perpetual closed multiple non-core asset dispositions for net proceeds of $3.8 million. Subsequent to the end of 2011, several additional non-core asset dispositions have been closed for net proceeds of $63 million, including the disposition of a portion of the company’s common shares of TriOil Resources Ltd. The disposed assets are primarily non-core properties located in eastern and westcentral Alberta and include approximately eight million cubic feet per day of gas production, and oil and NGL production of 390 barrels per day. Perpetual is continuing to pursue additional asset sales, including the disposition of all or a portion of its gas storage facility at War wick, to reach the previously announced targeted proceeds in 2012. The company reported a net loss of $95.92 million in 2011, compared to a $100.72-million loss the previous year. The loss in 2011 was driven primarily by reduced funds flow and impairment losses related to low natural gas prices. Natural gas production fell 10 per cent to 130.2 million cubic feet per day in 2011, as a result of non-core asset dispositions; the shut-in and sale of natural gas production at Liege in November 2010 due to gas-over-bitumen concerns; and natural production declines, partially offset by high-impact drilling at Edson and low-cost workover and recompletion activities in its eastern district to mitigate decline rates. In 2011, Perpetual added 61.1 billion cubic feet equivalent (10.2 million barrels of oil equivalent) of proved-plus-probable reserves, excluding production and net
Perpetual is focused on developing its Mannville heavy oil play for the remainder of 2012.
Perpetual Energy Inc. is nearing completion of a $34-million capital-spending program in the first quarter of 2012, with expenditures directed principally toward the advancement of horizontal development of the Wilrich in greater Edson, and exploration and development of heavy oil at Mannville. One vertical and two horizontal (2.3 net) wells were drilled at Edson, in addition to facility construction to tie-in new production. Two vertical and 17 horizontal (19 net) wells were drilled and tied-in at Mannville, and tie-in operations were completed for one well drilled in 2011. As gas prices reached levels below $3 per thousand cubic feet in mid-January, investment in all natural gas projects, including the Wilrich program, was suspended and funds will be redirected to highly profitable Mannville heavy oil activities, Perpetual said. CENTRAL ALBERTA WELL ACTIVITY
MAR/11
MAR/12
WELL LICENCES
347
242
▼
▼
▼
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
47
Central Alberta
dispositions. The majority of the reserve additions were related to activ ities driven by Perpetual’s asset base transformation and diversification strategy, adding natural gas and liquids reserves in the Alberta Deep Basin, and in eastern Alberta adding Mannville heavy oil reserves. At year-end 2011, oil and NGL represented 10 per cent of Perpetual’s total proved-plus-probable reser ves (12 per cent of proved), up from six per cent (eight per cent of proved) at yearend 2010. E x plor at ion a nd de v e lopm e nt expenditures, excluding land, were $122.8 million in 2011, up f rom $101.4 million for 2010. Capital spending was concentrated on exploration and development of liquids-rich
n at u r a l gas in the west-central district, heav y oil drilling at Mannville in eastern Alberta, and evaluation of Perpetual’s oilsands leases in northeastern Alberta. Easter n dist r ic t ex pendit ures of $65 million were focused on the drilli ng a nd complet ion of 29 (29 net) heav y oil wells at Mannville, facilityoptimization projects designed to reduce production costs, low-cost shallow gas recompletions to maintain production levels and evaluation of the company’s oilsands leases at Panny and Liege. West-central district capital spending totalled $75 million, directed primarily to Cardium drilling in the first quarter of 2011, Wilrich delineation and development, and land expenditures to
extend Perpetual’s Wilrich operations to western Edson. Perpetual drilled 62 wells (60.5 net) in 2011 with a 100 per cent success rate, compared to 70 (63.9 net) in 2010. Drilling activity included 35 (34 net) oil wells, 16 (15.5 net) gas wells, seven (seven net) oilsands evaluation wells and three (three net) wells at the Warwick gas storage facility. Land acquisitions totalled $16.5 million in 2011, a $2.6-million increase from 2010. Current-year spending was directed primarily towards several exploratory parcels in the western Edson area of west-central Alberta, as well as expanding Perpetual’s land position in Mannville and Elmworth. — DAILY OIL BULLETIN
Tourmaline enjoys strong 2011, cuts spending again in 2012 Tourmaline Oil Corp. reported record full-year 2011 earnings of $42.68 million, compared to a profit of $8.81 million for 2010, while average production for the year of 31,007 barrels of oil equivalent per day represented a 74 per cent increase over 2010. Production for the fourth quarter of 2011 averaged 37,912 barrels equivalent per day, a 65 per cent increase over the fourth quarter of 2010 average production of 22,953 barrels per day. Production was 88 per cent natural gas weighted in the fourth quarter of 2011, which is consistent with the fourth quarter of 2010. The company said its significant production growth can be attributed to 80.5 (net) new wells that were brought onstream in 2011, as well as property and corporate acquisitions during the year. Tou r ma l i ne reac hed produc t ion levels of 50,000 barrels equivalent per day during the first quarter of 2012 and has increased full-year 2012 production guidance from 47,000 to 50,000 barrels per day. This represents 61 per cent growth over 2011 average production levels. Current production has now reached 53,000 barrels equivalent per day and Tourmaline said it has an additional eight wells to tie-in prior to spring breakup. 48
MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
Oil and liquids production has recently reached the 7,000-barrel-per-day level, and the company expects to reach 10,000 barrels per day of oil and liquids in the fourth quarter of this year. In total, Tourmaline drilled 89 wells (72.7 net) in 2011 with a 100 per cent success rate. In addition to record well results in all operated areas announced in January and March, the company has had additional strong successes (three-day test or
with 1.6 million cubic feet per day of gas. • The Horse vertical Dunvegan well f lowed at a final test rate of 17.6 million cubic feet per day, at 19.6 megaPascals with approximately 230 barrels per day of condensate. • The Edson 15-34 Wilrich horizontal flowed gas at a final test rate of 15.5 million cubic feet per day, at 14.0 megaPascals with condensate and liquids.
The Spirit River 5-4 Charlie Lake horizontal flowed oil at a final test rate of 875 barrels of oil per day, with 1.6 million cubic feet per day of gas. longer—production tests are not indicative of long-term performance or ultimate recovery). These include: • The Kakwa-Falher horizontal flowed at a final test rate of 25 million cubic feet per day, at 14.8 megaPascals with liquids. • The Spirit River 5-4 Charlie Lake horizontal flowed oil at a final test rate of 875 barrels of oil per day,
• The company’s most recent Sunrise Montney well is producing gas at a rate of 18 million cubic feet per day, with approximately 700 barrels per day of condensate. Tourmaline noted in its March release that it had elected to reduce its 2012 capital program by an additional $25 million– $375 million. — DAILY OIL BULLETIN
Southern Alberta
AltaGas Gas expects liquids, Harmattan project, to drive results
MAR/11
MAR/12
MAR/11
MAR/12
WELLS SPUDDED
72
17
WELLS DRILLED
89
29
Photo: Aaron Parker
of approximately $8 million, comprised of the gains recorded from the sale of the Groundbirch facility and settlement of a take-or-pay contract. AltaGas attributed improved results in 2011 to higher volumes at extraction facilities, strong frac spreads, higher power generated from the wind and gas-fired generation portfolio along with the addition of Pacific Northern Gas Ltd. (PNG) in the fourth quarter. The increases were partially offset by the impact of two major scheduled turnarounds in the Gas division, lower volumes at some field processing facilities and transaction costs primarily related to the acquisition of PNG. Net income applicable to common shares for the three months ending Dec. 31, 2011, increased by 12.8 per cent to $29.9 million from $26.5 million in the
comparable 2010 period. Full-year net income attributable to common shares declined to $83.6 million in 2011 from $97.2 million the prior year. On a segment basis, Gas contributed $1.18 billion in revenue in 2011 compared to $1.06 billion the previous year. Power and Utilities revenue was $356.46 million and $165.61 million, respectively, versus $261.56 million and $151.7 million the previous year. “Overall, we expect to deliver stronger results in 2012 over last year,” David Cornhill, president and chief executive officer, said. “Our operating assets are performing well, and we expect to see throughput increase in our Gas business.” AltaGas plans to bring on nearly $1.8 billion in new assets this year, he noted. Last month, A ltaGas announced t he acquisition of SEMCO Holding Corporation for US$1.135 billion, including the assumption of $355 million in debt. The addition of SEMCO will add approximately $725 million in rate base. Various gas initiatives are also under way. The Gordondale and Harmattan costream facilities are both underpinned by long-term contracts and are expected to begin operations this year. An expansion at the Blair Creek facility is expected to add approximately 50 million cubic per day of processing capacity, increasing licensed capacity to 82 million cubic feet per day, beginning in the second quarter of this year. Three active producers in the area contractually support the expansion. In the fourth quarter of 2011, the planned turnaround at the Harmattan complex reduced operating income by approximately $6 million. During the turnaround, AltaGas completed tie-in work required for the co-stream and cogeneration projects, also expected to be in service in the second quarter.
With dry gas prices below $2, AltaGas is looking to liquids processing from drilling in the foothills for future growth.
AltaGas Ltd.’s Gas segment is expected to deliver stronger results this year as producers look to increase netbacks from liquids-rich gas, said the company as it reported improved results in its Gas, Power and Utilities businesses in 2011. The company expects to benefit from the completion of the Harmattan costream project and Gordondale gas plant, as well as expansions at other field processing and extraction assets. Stronger results are also expected as no major turnarounds are planned this year compared to 2011. However, these increases are expected to be partially offset by lower volumes in areas where there are fewer opportunities for producers to benefit from liquids-rich gas, and lower daily contract quantity commitment on the Suffield natural gas transmission system. Other reductions for 2012 include one-time items from 2011 SOUTHERN ALBERTA WELL ACTIVITY
MAR/11
MAR/12
WELL LICENCES
78
23
▼
▼
▼
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
49
Photo: Joey Podlubny
Southern Alberta
If gas prices remain low, AltaGas predicts processing volumes will drop eight per cent this year.
The Harmattan co-stream project will use 250 million cubic feet per day of existing spare capacity to recover ethane and other NGLs from natural gas sourced from the NOVA Gas Transmission Ltd. western system. The project is expected to be slightly over the budget of $130 million, plus 20 per cent contingency ($156 million), said AltaGas. It attributed the cost over-run to higher engineering costs, rock formations along the pipeline route, increased equipment costs and in-plant construction costs. The project also was delayed due to an additional unanticipated National Energy Board process, but AltaGas has now obtained board approval to connect its pipeline to the TransCanada pipeline. By the end of 2011, AltaGas had $146 million in committed capital costs. Pipeline construction was 95 per cent complete by year-end, as was the first phase of construction. As of Dec. 31, 2011, 70 per cent of expected costs had been incurred. The company said it has experienced the impact of labour and engineering shortages but has managed to mitigate some of those increases by employing smaller, local contractors. Management will continue to look for ways of managing the rising costs of construction in Alberta. Based on current capital cost estimates, AltaGas expects the annual EBITDA contribution to be slightly over $25 million. On April 5, 2012, the Alberta Court of Appeal will hear a reexaminaton of the Energy Resources Conservation Board decision to approve the co-stream project. AltaGas said it continues to believe that 50
MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
the grounds set forth by the intervening parties for appeal are without merit and that they remain committed to its planned construction schedule. The 120-million-cubic-foot-per-day Gordondale gas plant in the Montney resource play is also experiencing cost pressures primarily related to the shortage of labour and engineering expertise, said AltaGas. Management continues to oversee construction to mitigate rising costs, for example by moving to shop manufacturing of modules that require less field labour than on-site construction. Management will continue to look for ways to deal with the rising costs of construction in Alberta. The Gordondale plant will be equipped with liquids extraction facilities, and is supported by a long-term gathering and processing agreement, with a major natural gas producer to supply natural gas to the facility. AltaGas expects the annual EBITDA contribution to be bet ween $30 million and $35 million. The facility and associated gas–gathering system is expected to cost approximately $236 million and be in service late this year. AltaGas had approximately $180 million of committed capital costs by the end of 2011. In total, approximately two-thirds of costs are expected to be fixed (by contract) over the course of construction. The remainder will be subject to cost and labour productivity risk. In 2011, average ethane extraction volumes increased by 1,112 barrels per day, up to 26,565 barrels, while natural gas liquids volumes grew by 1,859 barrels per day
up to 14,513 barrels. Volumes were higher at most extraction facilities as a result of higher inlet volumes, successful contracting efforts for Empress extraction facilities, and commencement of the Septimus pipeline in December 2011, partially offset by the Harmattan and Younger turnarounds. In contrast, throughput in field gathering and processing declined by 7.6 per cent to an average of 391 million cubic feet per day from 423 million per day in 2010, for a utilization rate of 33 per cent, despite the addition of the Marlboro gas processing plant in May and the expansion of the Alder Flats facility completed at the end of April. The lack of producer activit y in response to low natural gas prices has resulted in overall lower-average processing volumes of approximately 70 million cubic feet per day, from natural declines or well shut-ins during 2011 compared to the same period in 2010. These reductions were offset by increased production at certain facilities that saw higher throughput on average of 39 million cubic feet per day over the prior year. AltaGas expects higher volumes within the field processing business, as a result of the completion of Gordondale and the expansion of the Blair Creek gas plant. These projects—a full year of operation of the Marlboro gas plant, the Henderson pipeline, expanded gas processing capabilities at the Alder Flats gas plant, along with higher volumes at the Bantry and Princess facilities due to high producer activity in the area—are expected to more than offset the volume declines at other facilities. A reas experiencing higher activity levels are being driven by producers focusing on high NGL-content gas plays or light oil plays that create significant solution gas, thereby increasing throughput at some of the field processing plants. In 2012, more than half of the throughput volumes for the field processing business are anticipated to be captured through facilities near or inside the Montney, Wilrich, Notikewin and other liquids-rich gas formations and associated gas from oil or solution gas production. Despite these encouraging developments, if natural gas prices remain at current pricing levels for most of 2012, management has estimated that average gas processing volumes would be eight per cent lower than expectations, but still higher than last year due to the addition of the Gordondale gas plant and other expansions. — DAILY OIL BULLETIN
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Saskatchewan
Saskatchewan drilling builds speed By Lynda Harrison
MAR/11
MAR/12
MAR/11
MAR/12
WELLS SPUDDED
223
179
WELLS DRILLED
270
268
Photo: Joey Podlubny
the Bakken formation in the southeastern part of the province, said Boyd. Output from the Bakken has increased from 950 barrels per day just a few years ago to the current rate of about 65,000 barrels per day, he said. “We have had some 50 years’ experience in Saskatchewan and there isn’t one documented case of problems associated with fracturing. Not one,” he said, adding that this is a result of the province’s shallow aquifers. He is aware, however, of problems in other places, such as the United States. His government believes Saskatchewan’s oilsands resource will eventually be developed, perhaps through in situ techniques because it lies too deep to be mined, he said. While cap rock integrity is an issue, a number of companies are investigating a solution, said Boyd.
He said he had returned from China just 10 days ago and found “tremendous interest” in Canadian resources. China has an almost insatiable need for resources and is looking at Canada as one of the sources, he said. The proposed Gateway pipeline, in which one of China’s stateowned companies is a potential investor, is viewed as a big opportunity, he said. “They want a secure supply,” said Boyd. “They have two goals in mind in terms of their country right now. One of them is energy security and the other is food security.” Canada can provide both of those, he said. T he Sa sk atc hewa n gover n ment expects oil production to rebound from last year’s lower-than-expected output, due to the wet spring and summer. Oil production for the 2012-13 fiscal year is expected to rise to 176.9 million barrels, with a West Texas Intermediate oil price of US$100.50 per barrel, and a wellhead price of C$82.45. The province’s annual budget, tabled in March, forecasts oil revenue of $1.6 billion for 2012-13, up from $1.47 billion for the 2011-12 fiscal year. Crown land sales are forecast to fall to $220 million for 2012-13 compared to $234.1 million for 2011-12. Oil producers drilled 3,528 new oil wells last year, 29.2 per cent more than in 2010, in response to rising prices. Natural gas revenue, meanwhile, is headed in the opposite direction. Provincial revenue from the hydrocarbon resource will continue its rapid fall to $12.5 million in 2012-13, compared to $18 million the previous fiscal year. Production is expected to fall to 135.6 billion cubic feet in 2012-13 from 153.6 billion cubic feet in 2011-12. Likewise, fieldgate prices are also expected to drop to C$2.98 per gigajoule in the coming fiscal year, from $3.29 in 2011-12.
Pumpjacks at Weyburn. Oil production climbed to around 151 million barrels last year in Saskatchewan.
Despite last spring’s flooding that delayed drilling, Saskatchewan had its secondbest year ever for drilling in 2011, and that record could soon be broken as activity is catching up already this year, an industry conference heard recently. Saskatchewan’s oil production last year was an estimated 151 million barrels with a value of around $11.7 billion, Bill Boyd, minister for energy and resources for the Saskatchewan government, told the Canada & U.S. Western Midstream Summit in Calgary. The province’s oil and gas industry invested approximately $4.5 billion into exploration and development in 2011, and provides 33,000 direct jobs. The industry injects about $7 billion into the province’s treasury, he said. Technology such as multistage hydraulic fracturing has opened up production in SASKATCHEWAN WELL ACTIVITY
MAR/11
MAR/12
WELL LICENCES
647
393
▼
▼
▼
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
53
Saskatchewan
Crescent Point buying Reliable Energy Crescent Point Energy Corp. announced an agreement to acquire Reliable Energy Ltd. in March, before announcing its yearend results. Crescent Point boosted average daily production in 2011 to 73,799 barrels of oil equivalent, up from 61,623 barrels per day in 2010. The company continued to develop and exploit the Viewfield Bakken and Shaunavon resource plays, while also acquiring significant positions in two emerging plays, the Beaverhill Lake light oil resource play in Alberta and the North Dakota Bakken/Three Forks play along the Canada-U.S. border. Crescent Point now has over 7,150 net low-risk drilling locations in inventory, representing more than 550,000 barrels per day of risked potential production additions. The company said that it has entered into an agreement with Reliable, a publicly traded company in which Crescent Point owns a 12.8 per cent equity interest. Reliable has production of approximately 1,000 barrels per day from the
Bakken light oil play in the Kirkella/ Manson area and a land base of more than 135 net sections in southern Saskatchewan and southwestern Manitoba. The assets of Reliable include internally assigned provedplus-probable reserves of 4.1 million barrels as of Dec. 31, 2011, and an internally identified drilling inventory of 36 net locations.
Crescent Point believes has upside potential through both infill and step-out drilling, as well as waterflooding. The Reliable arrangement is expected to close on or around May 1, allowing Reliable shareholders to receive Crescent Point’s anticipated May dividend, which is expected to be paid on or around June 15.
Crescent Point expects to spend approximately 36 per cent of its 2012 budget in the Viewfield Bakken and Flat Lake areas of southeastern Saskatchewan. T he complet ion of t he Reliable arrangement will allow Crescent Point to consolidate the assets currently held through a joint venture with Reliable in the Bakken light oil play in southwestern Manitoba, and is complementary to the company’s previously announced Manitoba asset acquisition. The Bakken light oil play in southwestern Manitoba is a low-cost, high-netback play that
As a result of the Reliable deal, the company increased its guidance for the year. Crescent Point’s average daily production is expected to increase to more than 86,500 barrels equivalent per day from 86,000 barrels per day, and its 2012 exit-production rate is expected to climb to more than 94,000 barrels per day from 93,000. The company’s capital expenditures budget for 2012 remains unchanged at roughly $1.2 billion.
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MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
- Service Trucks - Mud/Pump Trailers - Boiler Units - Water and shale tanks - 400BBL and 750BBL storage tanks
- Towers, Catwalks, Ladders, Stairs, etc.
Photo: Joey Podlubny
Saskatchewan
A wet year slowed development in the Bakken last year for Crescent Point, but it's full-speed ahead in 2012.
The 2012 capital program will focus on several organic growth projects across the company’s asset base, as well as on advancing its emerging resource plays in Beaverhill Lake and North Dakota Bakken/Three Forks. Crescent Point will continue to apply and refine new techniques and concepts in each of its core resource plays, which will provide a competitive advantage in developing new prospects. Crescent Point expects to spend approximately 36 per cent of its 2012 budget in the Viewfield Bakken and Flat Lake areas of southeastern Saskatchewan, 22 per cent in the Shaunavon area of southwestern Saskatchewan, 14 per cent in the Beaverhill Lake light oil resource play and 11 per cent in the Bakken/Three Forks resource play in North Dakota. The remainder of the budget will be allocated to other core conventional properties and to exploration and development projects in southern Alberta. In total, Crescent Point expects to drill approximately 389 net wells in 2012, and to spend approximately $150 million on facilities infrastructure, primarily in the Bakken and Lower Shaunavon resource plays. The company will continue to expand and develop its waterflood programs in the Viewfield Bakken and Shaunavon resource plays. By year-end 2012, Crescent Point expects to have approximately 60 injection wells in the Bakken play, and 10 in the Shaunavon play.
454526 Edmonton Exchanger & Manufacturing Ltd LET’S ROLL! STEEL PLATE ROLLING UP TO 12” THICK. 2/3v · dcv Edmonton Exchanger specializes in the fabrication of large-scale pressure vessel components and features steel plate forming capacities that are some of the largest available. We offer the most extensive one-stop pressure vessel head forming and shell rolling capabilities in North America, and feature one of the largest inventories of SA516-70 N steel plate in the world. www.edmontonexchanger.com
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— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • MAY 2 0 1 2
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Patent Pending
Northern Frontier
N.W.T. Canol oil shale play taking shape
Photo: Joey Podlubny
By Elsie Ross
A major oil shale project is taking shape in the Mackenzie Valley, led by MGM Energy.
The emergence of the Canol oil shale play in the Central Mackenzie Valley of the Northwest Territories is a potential game changer, but there are major challenges—including regulatory issues— that need to be addressed, an exploration and production company executive said in March. “Many of us who have worked in the north for a number of years find that it is probably one of the most difficult and unpredictable regulatory regimes across the country,” John Hogg, vice-president of operations and exploration for MGM Energy Corp., told delegates of CI Energy Group’s 12th Annual Arctic Oil & Gas Symposium. “The time for reviewing and improving the regulatory process is now, not during the development of the Canol shale resource.” In July 2011, Aboriginal A ffairs and Nor thern Development Canada (A ANDC) awarded MGM, as operator, and its partner three exploration licences totalling 254,000 gross hectares in the Central Mackenzie Valley (two in the area of the Canol shale) for a gross work
commitment of $5 million ($2.5 million net to MGM) over the next five years. The company was among five companies that paid more than $500 million in work commitments for a total of 11 parcels. Among those acquiring licences were global players including Husky Oil Operations Limited, ConocoPhillips Canada Resources Corp., Shell Canada Limited and Imperial Oil Resources Ventures Limited. Husky rig released the second of two wells it drilled this winter in March on one of the two parcels for which it paid the top price of $188 million per parcel. The Devonian-era Canol shale is about 375 million years old. It was deposited below the water in what was then a warm sea, and the life forms that died created the organic content that made the shale a source rock for the Norman Wells oilfield, said Hogg. The first discovery at Norman Wells in 1920 was drilled into the Canol shale. Later drilling discovered the deeper Kee Scarp carbonate reef where oil had migrated laterally from the organic-rich shales. The
remaining oil is still trapped within the Canol shale, although it is slowly moving. The Norman Wells reservoir has already produced more than 300,000 barrels of oil with a significant amount of oil remaining, Hogg noted. When MGM first started up five years ago, “we knew the Canol shale existed; we didn’t have a way of getting it out.” Today, industry can drill horizontal wells and fracture the rock so that it is able to exploit the resource inside. The Canol shale has an extremely high total organic content (TOC) of between three and 27 per cent and an average of nine to 12 per cent TOC, which Hogg suggested is probably two or three times that of the average shale that is exploited in North America. The resource is liquids prone and has other geochemical characteristics that indicate it has produced some oil and has some oil left to be produced. “All of these things are very good when it comes to looking at this source rock from the point of view of exploration.” As geologists, MGM understands the Canol shale very well, as about 20 wells had been drilled through it, he said. The rock found at an average depth of 1,800– 1,950 metres has low permeability but high porosity for a shale. “And we know the pores in the rock are filled with hydrocarbons,” said Hogg. While the company doesn’t know how much of it will be oil or natural gas, based on the logs of previous wells, “we do know that it’s filled with hydrocarbons.” While the Canol is the major focus, there’s also a secondary target—the Bluefish, a thinner shale at a greater depth. One of the attractions of the plays is that they are within 10–30 kilometres of Enbridge Inc.’s Norman Wells crude pipeline. In addition to regulatory issues, the basin presents major challenges for industry including construction, the expense of exploration drilling and timelines. All of the exploration work for the Canol shale will be on the west side of the Mackenzie River while the winter ice road runs on the east side of the river. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • MAY 2 0 1 2
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523428 PTI Group full page 路 fp
Technology News
CEPA supports pilot project for monitoring health and safety best practices
Moyno EF Leakless Stuffing Box released
The Canadian Energy Pipeline Association (CEPA) supports a new pilot project designed to review health and safety processes within pipeline contractor management systems. The pilot project will utilize a riskbased management methodolog y to examine various aspects of participating organizations' safety management systems, including documentation, investigations, metrics, primary controls and objectives over a six- to 12-month period. “We realize that the contractor management process can be onerous for some of our contractor partners to manage,” said Ziad Saad, vice-president, safety and sustainability. “The pilot project will help participating organizations identify areas within their business that could prevent,
Robbins & Myers Energ y Ser v ices Group has developed the Moyno EF (Environmentally Friendly) Leakless Stuffing Box that is designed to reduce costs and prevent the risks associated with unwanted environmental issues caused by leaking stuffing boxes. Stuffing-box leakage is a controllable issue that can be easily addressed with the installation of a Moyno EF Leakless Stuffing Box. Unwanted stuffing-box leakage results in costly loss of product, unnecessary cleanup expenses and potential fines for environmental damages. This environmentally friendly solution is critical for all field installations. With a cost-effective return on investment, the money you save with this stuffing box goes directly to the bottom line. A s i mpl i f ie d c l a mp i n g s y s t e m ensures quick and easy installation— whether in a new installation or retrofitting an existing installation—to m i n i m ize dow nt i me a nd reduce incurred costs. The Moyno EF Leakless Stuffing Box is adaptable to most electric or hydraulic driveheads for optimal versatility in preventing unnecessary f luid leakage at the wellsite. It is also designed to provide increased bearing support for enhanced stability and to eliminate premature internal drivehead wear, saving you time and money. Additional features of the Moyno EF Leakless Stuffing Box are as follows: • Design features a floating primary seal, isolated in a f luid bath for reliable performance and long service life; • Pressure equalization on the primary seal ensures effective, leakless sealing; • Increased bearing support optimizes stability; and • Modified and mounting procedure helps to eliminate premature internal drivehead wear.
minimize or recover from potential health and safety incidents.” The pilot project, led by Calgarybased Pragmatic Solutions Ltd., will be looking for contractor partners that are willing to participate and provide feedback into the process. CEPA represents Canada’s transmission pipeline companies who operate more than 100,000 kilometres of pipeline in Canada and t he United States. These energy highways move approximately 1.2 billion barrels of liquid petroleum products and 5.5 trillion cubic feet of natural gas each year. Our members transport 97 per cent of Canada’s daily natural gas and crude oil from producing regions to markets throughout North America.
Ulterra PDC drill bit saves operator over $500,000 For the first time, a single Ulterra bit has drilled the entire intermediate section of the Tattoo field, located in northwestern Canada. An 8.5-inch (216-millimetre) U513M drilled both the vertical and build sections with the same bottomhole assembly, saving the operator two trips and $72 per meter versus the best offset and $570,000 when compared to the average of six section offsets in the field. Ulterra’s aggressive directional philosophy and a high rate-of-penetration (ROP) design enable the U513M to maintain the high instantaneous ROP required in the drill-out, as well as the ability to aggressively build angle with good toolface control. This single run is especially difficult in areas such as the Tattoo field, where a bit is required to drill through several hard carbonate packages only to
kick off and build into formations like the very hard Muskwa, known for abundant pyrite and chert which is normally very damaging to polycrystalline diamond compact (PDC) bits. “Solely focusing on ROP in individual sections for this application in northwestern Canada has cost operators a lot of money. Being able to balance ROP in the vertical section while maintaining directional control and cutter durability not only saved the operator over half a million dollars, it also reduced HSE risk exposure and [non-productive time] due to unnecessary trips,” said Aron Deen, product engineering manager. “Ulterra is continuously and actively using lessons learned on this excellent run to benefit other drilling applications around Canada and the rest of the world.”
O I L & G A S I N Q U I R E R • MAY 2 0 1 2
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Technology News
AMGAS Services Inc. launches full-service H2S treatment in the Middle East Oil and gas producers in the Middle East are experiencing the challenges of produci ng resources laden w it h hydrogen su l f ide ( H 2 S) f i rst-ha nd. Working in this environment, companies must account for the increased risks to the safety of workers and corrod i ng equ ipment i n t hei r projec t operating costs. Product recovery and f laring during well operations have a significant impact on the environment and are difficult to manage when H 2 S is present. AMGAS Ser vices Inc. has created innovative ways to safely handle and process H 2 S. AMGAS offers a wide range of services, including H 2 S removal and control measures aimed at mitigating the dangers associated with processing sour oil and natural gas. T he company ’s team of professionals is trained in using the specialized and proprietar y equipment, chemicals and processes. “H 2 S is very
dangerous, so the chemicals and equipment used must be dependable,” says January McKee, president of AMGAS Ser v ices Inc. “For A MGAS, dependable i n novat ion ha s a lway s mea nt that chemicals and equipment have been tested and proven to be reliable.” Fluids containing H 2 S emit vapour equally as dangerous to workers and the environment. Treating the vapours requires dependable and innovative scrubbers to ensure that risks are eliminated and that the produced f luids can be stored, transported, processed or disposed. A MGAS has partnered with Rutledge E&P Pte Ltd., who prov ide ser v ices for upstream drilling and exploration activities. Rutledge is based in Singapore and has operat ions t h roughout t he Middle East. “ T he Rut ledge Group st rongly believes that health, safety, environment a l protec t ion a nd qua l it y a re
SPRING
BREAKUP
of ut most i mpor ta nce to t he longter m busi ness success of t he compa ny whose pr i ma r y occ upat ion is to protect lives and preser ve assets. Our pa r t nersh ip w it h A MGA S w i l l definitely provide more cost-effective and efficient H 2 S solutions to our clients,” says Anne Joseph, chief executive officer of Rutledge E&P Pte Ltd. AMGAS’s strategic partnership with Rutledge provides complete detection, protection and removal technologies for H 2S environments. The Canadian-based company has over 25 years of experience working to reduce H 2 S and other noxious emissions. Their scavenging and scrubbing chemicals are supported by personnel with the knowledge and experience necessary to reduce costs, environmental impact and increase safety. A MGAS is based in Alberta and has been a leader in H 2S treatment since the late 1980s.
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advertisers' index Abacus Datagraphics Ltd . . . . . . . . . . . . . . . . . . 8 ABB Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Activated Environmental Solutions Inc . . . . . . . 56 Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . 52 American Jereh International Corporation . . . . . . . . . . . . . . . . inside front cover Annugas Compression Consulting Ltd . . . . . . . . 10 ASAP Heating & Well Servicing Corp . . . . . . . . . 41 Baker Hughes Canada Company . . . . . . . . . . . . . 23 Barrett Tax Law . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 61 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 61 Bilton Welding and Manufacturing Ltd . . . . . . . . 22 Brent Gedak Welding . . . . . . . . . . . . . . . . . . . . . 61 Brother’s Specialized Coating Systems Ltd . . . . 33 CanElson Drilling Inc . . . . . . . . . . . . . . . . . . . . 42 CG Industrial Specialties Ltd. . . . . . . . . . . . . . . 34 Clean Harbors . . . . . . . . . . . . . . . . . . . . . . . . . . 36 ClearStream Energy Services . . . inside back cover Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . 46
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MAY 2 0 1 2 • O I L & G A S I N Q U I R E R
Diversified Glycol Services Inc . . . . . . . . . . . . . . 22 Do All Metal Fabricating . . . . . . . . . . . . . . . . . . . 37 Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . 24 DSI Thru-Tubing Inc . . . . . . . . . . . . . . . . . . . . . . . 13 Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . 52 Edmonton Exchanger & Manufacturing Ltd . . . . 55 EV Canada Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Expertec Van Systems Inc . . . . . . . . . . . . . . . . . 54 Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . . 19 Fort Nelson & the NRRM . . . . . . . . . . . . . . . . . . 20 Frac Rite Environmental Ltd . . . . . . . . . . . . . . . . 27 Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . 51 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . 56 Kokanee Springs . . . . . . . . . . . . . . . . . . . . . . . . 60 Lloydminster Heavy Oil Show . . . . . . . . . . . . . . 30 MaXfield Inc . . . . . . . . . . . . . . outside back cover MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Millennium Directional Service Ltd . . . . . . . . . . 38 Minimal Impact . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Ministry Energy and Resources . . . . . . . . . . . . 45 NAIT Corporate and International Training . . . . 46 NCS Oilfield Services Canada Inc . . . . . . . . . . . . . 5 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 18 Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . 29 PTI Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Schneider Electric . . . . . . . . . . . . . . . . . . . . . . . . 4 Smart Completions Ltd . . . . . . . . . . . . . . . . . . . . 18 SMS Equipment Inc . . . . . . . . . . . . . . . . . . . . . . 28 Stewart Steel Inc . . . . . . . . . . . . . . . . . . . . . . . . 54 Tartan Controls Inc . . . . . . . . . . . . . . . . . . . . . . 38 TCA Marketing Ltd . . . . . . . . . . . . . . . . . . . . . . . 52 Tervita . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . . 42 Trans Peace Construction (1987) Ltd . . . . . . . . . 46 U F A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 ULTERRA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Viking Pump of Canada Inc . . . . . . . . . . . . . . . . 32 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . 12 ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . 17
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400250 MaXfield Inc full page 路 fp OBC - PAID
For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project. From custom vessels to structural steel, piping and modular packaged equipment; MaXfield is now your one stop shop for industrial fabrication.
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