Oil & Gas Inquirer January 2014

OIL&GaS january 2014 ~ $6.00

INQUIRER Western Canada's Exploration & Production Authority

DRAINING THE

High volume and liquids-rich wells make Deep Basin one of few profitable gas targets

PLUS: PM40069240

The latest in drilling technologies

OIL & GAS INQUIRER • junE 2

1

Platinum Grover “The Piling Connection”

TM

Servicing Canada and USA

CONTENTS

JANUARY.

in the news

9

Canadian Natural spending $7.7 billion in 2014

regional news

13

British Columbia

19

Northeastern Alberta

23

Southern Alberta

Montney Formation one of world’s largest gas resources, says report

Clean Harbors’ Ruth Lake Lodge opens

DeeThree spent $200 million targeting

north of Fort McMurray

Alberta Bakken and Belly River in 2013

17

21

25

Northwestern Alberta

Long Run lowers 2014 capital budget

Central Alberta

Keyera benefitting from liquids-rich activity

Saskatchewan

BlackPearl carves up Onion Lake project

features

Cover Feature

30 Draining the Deep Basin High volume and liquids-rich wells make Deep Basin one of few profitable gas targets

every issue

6 38

35

Stats at a Glance

Faster, cheaper Cost of drilling unconventional wells dropping as

Political Cartoon

combination of technologies speed up operations

Cover design: Peter Markiw Photo: @istockphoto.com/MoMorad

OIL & GAS INQUIRER • january 2014

3

Dragon Energy Double Conical Tanker Trailers

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9,000

9,500

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11,000

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Every Dragon unit is built in one of our own state of the art manufacturing facilities and we can adjust our production schedule quickly to fulfill special orders.

What you need when you need it. Work with Dragon… make it happen.

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Make it happen.

Canada

Editor’s Note Vol. 26 no. 1 EDITORIAL EDITOR

Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS

Lynda Harrison, Deborah jaremko, Pat roche, Elsie ross EDITORIAL ASSISTANCE MANAGER

Tracey Comeau | tcomeau@junewarren-nickles.com

Another boondoggle

EDITORIAL ASSISTANCE

Kate austin, Shawna Blumenschein, Sarah Maludzinski, Matthew Stepanic CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER

Michael Gaffney | mgaffney@junewarren-nickles.com CREATIVE SERVICES MANAGER

Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD

Cathlene Ozubko GRAPHIC DESIGNER

Peter Markiw

CREATIVE SERVICES

janelle johnson, Ginny Tran, Teagan Zwierink production@junewarren-nickles.com

Here we go again.

It seems the Alberta Conservative govern-

Wait, there’s more. North West is also part of the Alberta Carbon Trunk Line, running

ment can’t resist sticking its fi ngers into the

from its upgrader to oilfields in central Alberta.

private marketplace.

It is receiving $495 million over 15 years for

The latest outrage is a $300-million loan to the North West Redwater Partnership to help

this project.

The truth is none of these projects would

cover costs of its Sturgeon refi nery project,

be happening without government funding,

SALES

which recently announced the price tag for the

and that tells you something about their eco-

SALES MANAGER—ADVERTISING

50,000-barrel-per-day refi nery had jumped by

nomic viability.

Monte Sumner | msumner@junewarren-nickles.com SENIOR ACCOUNT EXECUTIVES

nick Drinkwater, Tony Poblete, Diana Signorile SALES

Terry nelson Browning, Brian Friesen, rhonda Helmeczi, Sammy Isawode, Mike Ivanik, nicole Kiefuik, David ng, james Pearce, Sheri Starko For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES

Lorraine Ostapovich | atc@junewarren-nickles.com DIRECTORS

50 per cent to $8.5 billion.

The government has also pledged it will pro-

But like her Red Tory predecessor Ed Stelmach and her mentor Peter Lougheed,

vide further loans in the “unlikely” event that

Alberta Premier Alison Redford can’t seem to

more funds are required to fi nish the project,

fi nd the line between business and government.

according to the project ownership. And, accord-

A generation ago, progressives seized

ing to newspaper reports, the government is on

control of the Conservative party, squander-

the hook for any debt if the project fails.

ing billions in an effort to diversify Alberta’s

The $300-million loan follows an announce-

economy. MagCan, a $200-million magnesium

CEO

ment in September 2012 that the Redford govern-

project south of Calgary, lasted one year, costing

PRESIDENT

ment was doling out $745 million of its $2-billion

the government $180 million.

Bill Whitelaw | bwhitelaw@junewarren-nickles.com rob Pentney | rpentney@junewarren-nickles.com DIRECTOR OF SALES & MARKETING

Maurya Sokolon | msokolon@junewarren-nickles.com DIRECTOR OF EVENTS & CONFERENCES

Ian MacGillivray | imacgillivray@junewarren-nickles.com DIRECTOR OF THE DAILY OIL BULLETIN

sustainability fund to Shell Canada Limited’s Quest Carbon Capture and Storage Project.

What is wrong with these people?

Why does the government feel the need to risk

Alberta is headed for a repeat of that disaster with no Ralph Klein in sight to save it.

I have a suggestion that could save Albertans a lot of grief.

If Redford and her party members want

Stephen Marsters | smarsters@junewarren-nickles.com

taxpayer money on private projects? If the private

DIRECTOR OF DIGITAL STRATEGIES

sector won’t fund something because it thinks it’s

to dabble in environmental projects, pipelines

too risky, does the government ever consider it

and upgraders, they should fi rst resign from

may be too risky to do with taxpayer money?

government. They should then put together a

Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR OF CONTENT

Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION

audrey Sprinkle | asprinkle@junewarren-nickles.com DIRECTOR OF FINANCE

Ken Zacharias, CMa | kzacharias@junewarren-nickles.com OFFICES Calgary

nd Flr-  Avenue N.E. | Calgary, Alberta TE Y Tel: .. | Fax: .. Toll-Free: ...

Edmonton

220-9303 34 Avenue N.W. | Edmonton, Alberta T6E 5W8 Tel: .. | Fax: .. Toll-Free: ...

SUBSCRIPTIONS Subscription rate

Given that the project is 50 per cent, or $2.8 billion, over budget, and it just broke ground four months ago, maybe the private sector knew something the government didn’t?

Furthermore, when the government is running multi-billion dollar deficits when capital

plan, form a corporation and go to the market to fi nance it.

They may fi nd that a little more of a challenge than borrowing money to give to the industry and leaving it for me, and likely my children and grandchildren, to pay for.

expenditures are included in the budget, where is this $300 million coming from?

I’ll answer that for you—the government’s borrowing it.

Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com

In Canada,  year $ plus GST,  years $ plus GST Outside Canada,  year $

Subscription Inquiries Telephone: ... Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com GST Registration Number RT. Printed in Canada by PrintWest. ISSN - | ©  JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number .

Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N E XT I S S U E February 2014 Tracking exploration in the Duvernay, plus a review of heavy oil technologies.

Want to sound off on any content in Oil & Gas Inquirer?

Send your emails to dstonehouse@junewarren-nickles.com.

Please mark them as ”Letter to the Editor” if you want them published.

OIL & GAS INQUIRER • january 2014

5

FAST NUMBERS



trillion cubic feet

Marketable gas in the Montney, according to the NEB.



years

Time period the Montney could supply Canadian gas demand at current rates.

alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

M O NTH

GAS

D RY









,









,



















,

Mar 









,



apr 





















GAS

nov 









nov 

Dec 









Dec 

jan 









jan 

Feb 









Feb 

Mar 









apr 





OTHER

MONTH

OIL

T O TA L



OIL

SERVICE

jun 









jun 

jul 









jul 











aug 









aug 











Sep 









Sep 











Oct 









Oct 









,

nov 









nov 









,

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

nov 





nov 







Dec 





Dec 









jan 





jan 









Feb 





Mar 

Feb 













apr 





Mar 









jun 





apr 









jul 





jun 









aug 





jul 









Sep 





aug 









Oct 





Sep 









nov 





Oct 









nov 









*From year-to-date

SMARTPHONE • WEBSITE • iPAD • GPS • DIGITAL EDITION • PRINTED BOOK

THE

buyer’s guide TO CANADA’S OIL & GAS INDUSTRY COSSD.COM

6

T O TA L

january 2014 • OIL & GAS INQUIRER



STATS

AT A

GLANCE

Drilling rig Count by Province/Territory

Drilling activity: Oil & Gas

Western Canada, December 11, 2013 Source: Rig Locator

Alberta, November 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada alberta

AC T I V E

OIL WELLS

Alberta

nov 

GAS WELLS

nov 

nov 

nov 







%

northwestern alberta









British Columbia







%

northeastern alberta









Manitoba







%

Central alberta









Saskatchewan







60%

Southern alberta















%

TOTaL









WC TOTaLS

Service rig Count by Province/Territory

Drilling activity: CBM & Bitumen

Western Canada, December 11, 2013 Source: Rig Locator

Alberta, November 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada

alberta British Columbia

Manitoba Saskatchewan

WC TOTaLS

AC T I V E

C OA L B E D M E T H A N E

Alberta

nov 

nov 

BITUMEN WELLS nov 

nov 







%

northwestern alberta















%

northeastern alberta















%

Central alberta















%

Southern alberta















%

TOTaL









OIL & GAS INQUIRER • january 2014

7

When your workers are at risk, so is your business.

Working around power lines is dangerous.

Learn what you need to know to protect your people and your business.

TAKE

ACTION

Visit wherestheline.ca for industry-specific information about power line safety and to book in-person power line safety training.

IN THE

nEWS Issues affecting Canada’s E&P industry

7.7 billion

Canadian natural spending $7.7 billion in 2014 Canadian natural resources Limited said its 2014 capital budget of $7.7 billion—up from $6.95 billion last year—will deliver near-term production growth of seven per cent, or 711,000–757,000 barrels equivalent per day.

T he compa ny ’s nea r-ter m foc us remains on growing production from higher-return crude oil and natural gas liquids (NGL) projects. The company forecasts the volatility in the Western Canadian Select–West Texas Intermediate heavy oil differential to decline through 2014 as heavy oil conversion capacity is added in PADD II in the first half of 2014.

This year’s crude oil and NGL production is expected to increase by nine per cent over 2013 levels from strong performance in all segments of its business, the company announced.

Output growth is forecasted from Horizon (seven per cent), primary heavy crude oil (two per cent), North America

light crude oil and NGL (10 per cent), and thermal in situ oilsands is set to improve 23 per cent as production ramps up at the Kirby South steam assisted gravity drainage project.

The product mix is forecast at 75 per cent crude oil and NGL, and 25 per cent natural gas. Total production growth from the fourth quarter of 2013 to the fourth quarter of 2014 is targeted to be 15 per cent.

North American natural gas production is targeted to increase two per cent as drilling at Septimus and in the Deep Basin offset natural declines in the gas portfolio.

Canadian Natural’s total gas production is targeted to increase four per cent.

Total crude oil and NGL production volumes are targeted to increase by nine per cent from the 2013 midpoint guidance to between 521,000 and 560,000 barrels per day.

Primary heavy crude oil production is targeted to increase two per cent from

Canadian natural  capital budget Capital natural gas

F ($million)

B ($million)





Crude oil Pelican Lake





Primary heavy

,

,

Thermal in situ

,

,

Light Canada





North Sea





Offshore Africa





,

,

Sustaining capital





Turnarounds, reclamation and other





,

,–,

Total crude oil Horizon

Capital projects Technology and Phase  Total Horizon Acquisitions, midstream and other Total





,

,–,





,

,–,

Source: Canadian Natural Resources Limited

forecasted 2013 levels to between 142,000 and 146,000 barrels per day. The company aims to drill 898 net primary heavy crude oil wells, 46 net wells more than the 2013 plan.

Woodenhouse volumes are expected to stabilize in 2014 after 19 per cent production growth year-to-date in 2013. Pelican Lake crude oil is forecasted to increase by two per cent from 2013 to between 47,000 and 51,000 barrels per day, while 2014 capital is targeted to decline by over 35 per cent from 2013 levels, with the completion of major facilities and infrastructure last year.

With the implementation of polymer flood and industry-leading operating costs targeted to remain at less than $9 per barrel, Pelican Lake continues to generate signifi cant free cash flow, said Canadian Natural.

North America light crude oil and NGL volumes are expected to increase by 10 per cent from the 2013 midpoint guidance to between 72,000 and 76,000 barrels per day. Canadian Natural aims to drill 93 net light oil wells and continues to advance horizontal well multi-frac technology in pools across its land base with 80 per cent of targeted total drilling focused on horizontal wells.

Total oilsands production from thermal in situ and Horizon is targeted to range from 227,000 to 250,000 barrels per day in 2014.

Total natural gas production is targeted to range from 1.14 billion to 1.18 billion cubic feet per day before royalties, a four per cent increase from 2013 forecasted production volumes.

The targeted 2014 capital expenditures of $590 million are largely dedicated to drilling and maintenance.

Canadian Natural aims to drill 61 net gas wells in 2014, which is a 45 per cent increase from the 42 wells forecasted for 2013.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • january 2014

9

drop

In The News

apache reports Canadian production drop apache Corporation reported a 6.5 per cent drop in Canadian 2013 third-quarter production to 113,819 barrels equivalent per day, but while natural gas output dropped, the company increased its oil and natural gas liquids (NGL) production during the three-month period.

T h e H o u s t o n - b a s e d p r o du c e r ’s Canadian oil production rose to 18,573

Apache Canadian production (third quarter 2013) Oil (bbls/d) 18,573 natural gas (mcf/d) 529,402 natural gas liquids (bbls/d) 7,012 Barrels of oil equivalent per day 113,819 Source: Apache Corporation

barrels per day (net after royalties) in the third quarter of 2013 from 15,075 reported in 2012. NGL output also climbed during the third quarter to 7,012 barrels per day from 6,036 during the prior year’s threemonth period.

These gains were off set by the decline in natural gas production, which fell during the third quarter of 2013 to 529.4 million cubic feet per day from 604.44 million cubic feet per day during the third quarter of 2012.

In September, Apache completed the sale of oil-and-gas-producing properties in the Nevis, North Grant Lands and South Grant Lands areas of western Alberta to Ember Resources Inc. The assets comprised 621,000 (530,000 net) acres and more than 2,700 wells averaging net production of approximately 69 million cubic feet per day and 247 barrels per day in the third quarter of 2013.

Also in September, Apache announced the sale of its Hatton, St. Lina, Marten

Hills, Snipe Lake, Valhalla and a portion of its Hawkeye producing properties. These are primarily dry gas developments located in Saskatchewan and Alberta and comprise roughly 4,000 operated and 1,300 nonoperated wells with average daily production of about 39 million cubic feet per day and 679 barrels per day. This sale was completed in October.

These recently announced sales in Canada have resulted in the divestment of approximately 50 per cent, 30 per cent and 17 per cent of Apache’s wells, acreage and production, respectively.

In the third quarter of 2013, Apache drilled 23 wells (18 net) in Canada and operated an average of six rigs. Canadian capital expenditures in the third quarter fell to US$155 million from US$164 million during the same period in 2012. For the nine-month period, Canadian capex has increased to $502 million from $459 million during the same period in 2012.

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— DAILY OIL BULLETIN

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B.C.

BrITISH COLuMBIa WELL aCTIVITy NOV/12

NOV/13

Wells licensed





NOV/12

NOV/13

Wells spudded





NOV/12

NOV/13





Rigs released

▼

▲

British Columbia

▲

Source: Daily Oil Bulletin

Montney Formation one of world’s largest gas resources, says report

Photo: Joey Podlubny

The national Energy Board, the BC Oil and Gas Commission, the Alberta Energy Regulator and the British Columbia Ministry of Natural Gas Development jointly released the first study ever to estimate the marketable unconventional petroleum resources in the Montney Formation, where it estimated 449 trillion cubic feet of marketable natural gas.

The report also said the Montney is one of the largest gas resources in the world.

Recent advances in technology, such as multistage hydraulic fracturing, have made it possible to economically develop unconventional gas and oil in the Montney Formation over the past several years, but little had been known about its total potential. The report estimates that there is approximately: • 449 trillion cubic feet of marketable natural gas; • 14.521 billion barrels of marketable natural gas liquids (NGL); and, • 1.125 billion barrels of marketable oil.

Although the fi ndings for marketable NGL and oil are notable, the estimated quantity of natural gas is extensive.

“At current consumption rates, the Mont ney ga s resou rce wou ld meet Canadian needs for 145 years,” said Gaetan Caron, the National Energy Board’s chair and chief executive officer. “The report clearly shows that Canadian energy markets will be well supplied with natural gas far into the future.”

By combining the Montney’s marketable gas estimate with prior assessments, the total ultimate potential remaining in western Canada is 632 trillion cubic feet.

This estimate is likely to increase as additional unconventional potential from other formations is estimated.

The Lower Triassic Montney Formation is aerially extensive, covering approximately 130,000 square kilometres. It is also thick, typically ranging from 100 metres to 300 metres, although it thins to zero at its eastern and northeastern edges and

The Montney was producing 1.7 billion cubic feet per day at year-end 2012.

increases to over 300 metres on its western side before it begins outcropping in the Rocky Mountains.

Most of the formation consists of siltstone containing small amounts of sandstone that originally collected on the bottom of a deep sea, whereas more porous sandstones and shell beds were deposited in shallow water environments to the east. The depth of the formation also increases from northeast to southwest, generally with increasing reservoir pressures and decreasing NGL and oil content. Thus, reservoir characteristics vary widely across the formation.

For British Columbia, the Montney was assessed using a process similar to one used in a 2011 study of the shale gas resources in the Horn River Basin. In the Horn River Basin assessment, the volumes of free gas and adsorbed gas were determined by connecting map grids of geological data to free gas and adsorbed gas equations. This way, gas volumes could be estimated by location and capture how the geological nature of the shales changed from place to place.

However, the Montney assessment was expanded to include NGL and oil, which are not present to any significant degree in the Horn River Basin. Dissolved gas, which is gas that is dissolved in oil deep underground but is liberated at surface under lower pressures, was also estimated for the Montney. Altogether, in-place and marketable petroleum resources were determined for dry natural gas, NGL and oil. Only overpressured areas were included in the B.C. analysis because unconventional development has so far been limited to overpressured areas.

For the Alberta portion of the Montney, the in-place volumes of dry natural gas, NGL and oil have already been estimated as part of Alberta’s two resource studies, their methodology described in the publication Quantification of Uncertainty in Shale Gas Resources. For this joint study, a marketable resource volume was estimated by applying OIL & GAS INQUIRER • january 2014

13

British Columbia

The Montney Formation

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Siltstone Siltstone with some sandstone Siltstone with sandstone and dolostone

Calgary

Erosional remnants Source: The Alberta Geological Survey

recovery factors to map grids of Alberta’s inplace resource data.

Because Montney development is occurring in both overpressured and underpressured areas in Alberta, the entire Montney unconventional play was assessed for marketable resources. Full development was assumed to occur in deeper areas (where the Montney mid-point depth was more than 1,750 metres) as these have a higher chance of being overpressured according to pressure-depth data. Shallower areas are expected to have only partial development because they are typically underpressured.

Thus, a “development risk” factor, as well as low recovery factors, was applied to shallower areas.

Conventional reservoirs within the Montney section were excluded from this analysis, as these were assessed in prior studies. Further, the methods for determining the in-place resources for each province, while similar, did have some significant differences, the report stated.

The geological mapping of the Montney Formation in British Columbia included some thin sandstones unlikely to be developed conventionally, while all sandstone was excluded from the Alberta analyses. No extra Monte Carlo simulations were run when adding British Columbia’s and Alberta’s low, expected and high values together.

The Montney’s marketable unconventional gas resource is one of the largest in the world, the report stated. While most of it is located in British Columbia, Alberta’s share is still large.

To further illustrate the size of the Montney, total Canadian natural gas demand in 2012 was 3.1 trillion cubic

British Columbia

feet, making the Montney gas resource equivalent to 145 years of Canada’s 2012 consumption. The Montney is already considered one of Canada’s most economic gas plays, the report noted.

Even though it is only in the early stages of development, the Montney’s 2012 production rose to an average of 1.7 billion cubic feet per day out of a total Canadian marketable gas production of 13.9 billion cubic feet per day. It is expected that Montney gas production will continue to increase and grow its share of Canadian production.

By combining this marketable gas estimate with prior assessments, including the most recent estimates of western Canadian ultimate potential for conventional nat-ural gas, the total ultimate potential in the Western Canadian Sedimentary Basin (WCSB) has more than doubled to 821 trillion cubic feet. Out of this total, 632 trillion cubic feet is remaining after cumulative production to yearend 2012 is subtracted.

The ultimate potential for natural gas should be considered an estimate that will evolve, likely growing over time as additional unconventional potential can be found in the Liard Basin of British Columbia and the Duvernay formation of Alberta, which are still in the early stages of assessment, the report stated. Overall, Canada has a very large remaining natural gas resource base in the WCSB to serve its markets well into the future.

The marketable unconventional NGL and oil volume in the Montney Formation is also “very large.” However, the volume of marketable oil, which is almost entirely found in Alberta, remains highly uncertain, as indicated by the wide spread between its low and high values, the report stated.

This is because the areas that are richest in Montney unconventional oil tend to be in shallower areas, where uncertainty about development is much greater.

T he Montney unconventional oil resource is only in the initial stages of development, with its 2012 production averaging only 25,845 barrels per day, a small component of total Canadian 2012 oil production, which averaged 3.23 million barrels per day. Alberta’s marketable NGL volumes are also highly uncertain, mostly because the in-place volumes are largely found in shallower areas.

— DAILY OIL BULLETIN

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N.W.

nOrTHWESTErn aLBErTa WELL aCTIVITy NOV/12

NOV/13

Wells licensed





NOV/12

NOV/13

Wells spudded





NOV/12

NOV/13





Rigs released

▲

▲

Northwestern Alberta

▼

Source: Daily Oil Bulletin

Long run lowers 2014 capital budget Long run Exploration Ltd. expects to spend $200 million on its capital programs this year, down from 2013’s current budget of $275 million.

Long Run’s 2014 capital program will focus on developing current inventory in its Peace River Montney and Redwater Viking core areas.

The company expects to drill 44 net oil wells in the Montney at Peace River this year while continuing to advance its waterfloods. Over the coming years, this pressure maintenance scheme is expected to help slow production declines while increasing ultimate recoveries.

In the Viking at Redwater, waterflood work is also underway along with ongoing development, which has added inventory as well as light oil production in 2013. Long Run expects to drill about 36 net Viking wells, with 30 net wells at Redwater and six net wells at Provost in 2014.

Total 2014 waterf lood spending is expected to be $17 million while facilities, maintenance and production optimization spending is expected to total about $45 million.

Production in 2014 is expected to average 26,000 barrels equivalent per day, three per cent more than forecast 2013 average daily production volumes.

“2014 will be a transitional year for Long Run, moving from a growth-oriented company to one focused on providing both dividend income and moderate per-share growth,” the company said.

Long Run expects to deliver annual 2014 per-share production growth of about three per cent and funds flow per share growth of about eight per cent.

“This model is supported by operating and developing assets already in the Long Run portfolio of producing properties. Long Run is confident that this model can be further enhanced by the acquisition and optimization of assets which increase cash flow per share,” the company said.

Over the past year at Peace River and Redwater, Long Run has focused on growing oil production through development, acquisitions and consolidating strategic facilities. The company said these plays have been expanded as acreage and drilling

Long Run Exploration 2014 capital spending Drilling, completions, equipment: $138 million Peace river (Montney): 44 net wells redwater (Viking): 30 net wells Provost (Viking): 6 net wells Total: 80 net wells Plants/facilities/EOr: $37 million recompletions/G&G/land/abandonments: $25 million Total: $200 million Source: Long Run Exploration Ltd.

inventories were de-risked through active development.

The company said the acquisition of lower-decline assets has helped slow corporate declines.

Long Run said its 2013 base production decline rate is 31 per cent, which is expected to slip to 29 per cent by the end of 2014.

In the third quarter, the company announced the acquisition of 1,350 barrels per day of oil-weighted production while consolidating additional acreage, facilities and key infrastructure in core operating areas at Redwater and Peace River. The company said this $51-million acquisition of low-decline assets was done at attractive production metrics and was closed subsequent to the end of the third quarter.

As a result of the recent $51-million acquisition, the company increased its 2013 production forecast to 25,200 barrels equivalent per day. Long Run was on track to meet its full-year production guidance and to exit 2013 with liquids production increasing to about 54 per cent of production.

Third-quarter production at Peace River averaged 10,101 barrels equivalent per day. Production from this area increased by 149 barrels per day during the third quarter compared to the second quarter of 2013.

In the third quarter of 2013, Long Run drilled 19.5 net successful horizontal Montney oil wells at Peace River. Results from these new wells continue to exceed the established type curve for this play and remain con sistent with the improved well results achieved in the fourth quarter of 2012 and the first six months of 2013, the company said.

Long Run expected to drill up to eight net additional development wells in this play during the fourth quarter of 2013.

Full-year 2013 development capital spending on the Montney oil play at Peace River was expected to be $124 million, resulting in a total of 50 net wells.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • january 2014

17

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Pembina Pipeline spending $1.5 billion in 2014 The $670 million allocated for conventional pipelines will account for the largest segment of Pembina Pipeline Corporation’s record $1.5-billion capital budget for 2014, said the company.

The capital budget, approximately 56 per cent higher than 2013’s capital budget of $965 million, is largely driven by the company’s success in securing growth opportunities in 2013, said Pembina.

Approximately $1.3 billion, or 85 per cent of the total capital, is associated with previously announced projects.

“Pembina’s capital spending plan for 2014 is indicative of the substantial suite of growth projects we have before us, the majority of which are under long-term, feefor-service agreements,” said Mick Dilger, president and chief operating officer.

In addition to conventional pipelines, Pembina has allocated $510 million (34 per cent of its total budget) for midstream, $260 million (17 per cent) for gas services and $60 million (four per cent) for oilsands and heavy oil.

Pembina expects to spend $215 million in 2014 to complete its previously announced Phase II of the Low Vapour Pressure Expansion project, which will increase crude oil and condensate capacity on the company’s Peace Pipeline by 55,000 barrels per day.

Pembi na a lso ex pec t s to spend $95 million to complete its previously announced Simonette Pipeline expansion on its Peace Pipeline between Simonette and Fox Creek, Alta. The new pipeline is expected to be in service in the third quarter of 2014, subject to the necessary environmental and regulatory approvals.

Once this new pipeline is completed, Pembina will have three pipelines in the corridor between Simonette and Fox Creek capable of segregating and shipping various grades of crude oil, condensate and NGL. There also are plans for several other new connections and upgrades in 2014 totalling approximately $120 million.

These investments are aimed at ensuring maximum integration and optimization of value chain opportunities, said Pembina.

— DAILY OIL BULLETIN

18

january 2014 • OIL & GAS INQUIRER

nOrTHEaSTErn aLBErTa WELL aCTIVITy NOV/12

NOV/13

Wells licensed





NOV/12

NOV/13

Wells spudded



 ▲

NOV/12

NOV/13



 ▲

Rigs released

▼

Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

Clean Harbors’ ruth Lake Lodge opens north of Fort McMurray

By Deborah jaremko

Photo: Clean Harbors Inc.

Clean Harbors Inc. opened its sixth open lodge, Ruth Lake Lodge, in the Fort McMurray area in November. The 604room facility offers guests a workforce camp in a prime location that delivers top-notch amenities including great food, entertainment and recreational activities, said the company.

With many companies looking at ways to retain employees and attract new skilled labour, Clean Harbors designed an interactive facility that enables companies to provide a comfortable, social, recreational and interactive environment to help create happier and more productive employees.

The 235,000-square-foot Ruth Lake Lodge has a number of unique features inside and out. Architecturally, the building has a contemporary design with an inverted roof and wood beam accents, something that would typically be found in

an urban setting and is new to the heart of the oilsands.

The lodge provides guest conference services with two executive boardrooms equipped with high-defi nition video conferencing capabilities and a business centre with offices and workstations.

Amenities include a golf simulator, a private theatre room, a 5,000-square-foot recreation room with pool tables, dartboards, air hockey and foosball, and two video gaming rooms that create opportunities for social interaction among guests.

The 4,000-square-foot workout facility provides a variety of cardio machines and free weights for those looking to maintain a healthy lifestyle. This area also features a women-only section, and a dedicated area for trainer-led fitness classes and massage services.

Another area designed to enhance the guest experience is the dining room. It presents

an intimate setting with a restaurant feel through various styles of seating areas and architectural features. The menu extends this feel through a wide variety of fine cuisine options that can be tailored to guests with various nutritional requirements.

The Ruth Lake Lodge has over 600 rooms with pillow-top mattresses, custom built-in furniture, a dedicated Wi-Fi service and high-definition televisions with video on demand and access to Facebook and Twitter. Depending on the needs of its customers, there are options to stay in VIP, executive, or Jack and Jill rooms.

Ruth Lake Lodge is located along Highway 63, 26 kilometres north of Fort McMurray, between the Suncor Energy Inc. and Syncrude Canada Ltd. oilsands facilities. Ruth Lake Lodge is Clean Harbors’ sixth open lodge in the Fort McMurray region.

Inside the new Ruth Lake Lodge.

OIL & GAS INQUIRER • january 2014

19

Northeastern Alberta

Suncor says no rush for joslyn mine

By Lynda Harrison

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The day after it approved the $13.5-billion Fort Hills oilsands mine, Suncor Energy Inc. said it won’t be rushing ahead to build the Joslyn North Mine, a 100,000-barrel-per-day oilsands project it would share with Total E&P Canada Ltd. When considering whether to go ahead with Joslyn, Suncor will take into account the amount of work going on in the region, and the difficulty of simultaneously managing multiple projects discourages it from overlapping with the construction of Fort Hills, said Steve Williams, president and chief executive officer.

As part of its joint venture with Suncor, Total is operator of the Joslyn project with a 38.25 per cent interest (Suncor 36.75 per cent interest).

“Of course, one of the great benefits for Fort Hills is that we ac tually believe we have a window of opportunity there where there is still lots going on, but it’s a relatively quiet period so we’ve been able to get some very competitive contracts there,” Williams said during a conference call to discuss third-quarter 2013 results.

Suncor said it has debottlenecking to thank for record oilsands production of nearly 400,000 barrels per day during the quarter, despite third-party pipeline outages in July and planned maintenance in September.

Williams said debottlenecking at its oilsands projects has produced a step-change in output, unlocked production in its mining operations, increased operational flexibility and added incremental barrels at a low cost.

Debottlenecking is a standard industry practice of removing process constraints to permit improved production and efficiency.

Also during the third quarter, the company commissioned its hot bitumen assets. These are comprised of an insulated pipeline from Firebag to Suncor’s Athabasca terminal, bitumen cooling and blending facilities, and capacity to import third-party diluents.

With that, Suncor began blending Firebag bitumen and shipping it straight to market, enabling the company to significantly ramp up its mine production, said Williams.

The company also experienced improved reliability from its upgrading complex, he said.

“When you put all of that together with favourable crude pricing, it adds up to a record quarter at oilsands,” said Williams.

Production from oilsands operations increased 16 per cent to a record quarterly average of 396,400 barrels per day in the third quarter of 2013, compared to 341,300 barrels per day in the third quarter of 2012.

Firebag’s production ramp-up continues to exceed expectations, said Williams. The in situ project with a design capacity of 180,000 barrels per day has reached more than 160,000 barrels on some days, he said.

Suncor said its integrated model enabled the company to capture the strength of inland pricing through its oilsands operations while continuing to realize incremental profit by obtaining global-based pricing through the company’s refining operations and vast logistics network.

“In August, we demonstrated the real potential of our operations when we produced a record 433,000 barrels per day at a cashoperating cost of just $29 per barrel,” said Williams.

CEnTraL aLBErTa WELL aCTIVITy NOV/12

NOV/13

Wells licensed





NOV/12

NOV/13

Wells spudded





NOV/12

NOV/13





Rigs released

C.A.B.

▲

▲

Central Alberta

▲

Source: Daily Oil Bulletin

Keyera benefitting from liquids-rich activity

By Elsie ross

Keyera’s significant organic growth projects underway Projects

responding to anticipated new production from developments in western Alberta, Keyera Corp. is undertaking a number of new pipeline initiatives, the company said as it reported higher net earnings due in part to higher operating margins from all business units.

“Increasingly, producers are looking to companies such as Keyera to assist them in their development plans by constructing the surface infrastructure necessary to turn their production into cash flow,” Jim Bertram, chief executive officer, said in a conference call to discuss third-quarter results. “This is particularly true in westcentral Alberta and in the Deep Basin where producers remain focused on liquidsrich resource type drilling.”

Keyera has received regulatory approval for the Wapiti Pipeline system, he said.

This will enable construction this winter of a 12-inch raw sour gas gathering pipeline and a six-inch segregated condensate line from the Wapiti area to the Simonette gas plant. Assuming construction proceeds as scheduled, Keyera anticipates completing the pipelines in the second quarter of 2014.

Producers are showing tremendous interest in the remaining capacity on the system, Bertram said. In order to handle the anticipated volume of raw gas at Simonette, Keyera plans to expand the plant with the addition of condensate-stabilization facilities to handle additional condensate and refrigeration.

The plant modifications, with a targeted inservice date in the second half of 2014, will add 100 million cubic feet per day of raw gas processing capacity.

Gross processing throughput for the quarter was 1.27 billion cubic feet per day (1.04 billion cubic feet per day net) compared to 1.15 billion cubic feet per day (937 million cubic feet per day net) in 2012.

Capital cost $millions*

Rimbey turbo expander

210

Wapiti raw gas and condensate pipelines

180

Simonette plant modifications

90

Strachan sulphur projects

65

Gas gathering pipelines Fort Saskatchewan de-ethanizer

26 65

Hull terminal refurbishment

35

Total *Note: Keyera’s share of estimated capital cost

Nine month throughput was essentially flat at 1.27 billion cubic feet per day (1.02 billion cubic feet per day net).

The operating margin for the natural gas liquids (NGL) infrastructure segment was $31.38 million compared to $29.91 million in last year’s period as higher fractionation and storage revenue in the quarter were off set by the lower margin earned by the Alberta EnviroFuels facility related to an unscheduled outage.

Keyera also has four new gathering pipelines in various stages of development, with three of them feeding into the Rimbey gas plant, in a liquids-rich area where operators are pursuing the Glauconite and the South Duvernay plays, said Bertram.

The company is proceeding with a debottlenecking of the Carlos Pipeline, which is approaching capacity, by constructing a short connector pipeline from Carlos to other existing Keyera pipeline infrastructure, he said. This will enable it to off-load certain volumes from Carlos for delivery initially to the Rimbey gas plant and to the Gilby gas plant in the future. The anticipated completion is in the second quarter of 2014.

Also at Rimbey, Keyera is purchasing a short gathering pipeline built by a producer that will be tied into the Carlos Pipeline.

Keyera has signed a letter of intent with a producer in the Rimbey area to build the

2014 2015

120

Alberta crude terminal Fort Saskatchewan storage projects

2013

34 825 Source: Keyera Corp.

first phase of the Wilson Creek Pipeline system to deliver raw gas and condensate to Rimbey from west of the plant. It would consist of two pipelines: a 12-inch raw gas pipeline and a six-inch condensate pipeline. The project is subject to both parties signing definitive agreements and could be completed by mid-2014.

Keyera also is working with produ-cers with respect to the construction of the Twin Rivers Pipeline, a 12-inch, 38-kilometre gathering pipeline that would deliver raw gas to Keyera’s Brazeau River and West Pembina gas plants. Construction could begin shortly, assuming timely completion of definitive agreements, and it could be completed as early as the first quarter of 2014.

Responding to a question about the Duvernay play, Bertram said there is a need to differentiate between the northern Duvernay (Kaybob area) and the southern Duvernay (Pembina and Willesden Green areas). Although there is increasing interest in the north, development initially may be delayed by the lack of infrastructure, he suggested. “We are going fast at Simonette and others are going fast on egress, but the reality is, nothing is going to happen quickly.”

In contrast, there are eight or nine potential gas processing facilities in the south, and Bertram said Keyera has been encouraging producers to consider that area.

OIL & GAS INQUIRER • january 2014

21

Central Alberta

Penn West plans Cardium spending of $800 million per year by 2018

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Penn West Petroleum Ltd. expects development capital spending on its flagship light oil play in the Cardium Formation of Alberta to climb to $800 million per year by 2018.

“Clearly the Cardium is the heart of the company, and we envision increased capital spending in the play...reaching $800 million invested per year there within five years,” president and chief executive officer Dave Roberts said.

To put the $800-million figure in perspective, Penn West’s entire 2014 exploration and development capital spending is expected to be $900 million, of which $269 million is earmarked for the Cardium.

Under its previous management, Penn West dabbled in a myriad of ventures ranging from cyclic steam stimulation in Alberta’s oilsands to an emerging shale gas play in British Columbia. Under new leadership, the company will focus mainly on primary and secondary production of light oil from its signature Cardium, Viking and Slave Point plays.

“We believe the oil resource positions we have in our control in the Cardium and Slave Point are unrivalled in western Canada, and together with other high-return, oil-weighted assets like the Viking, it allows us to focus activity and capital to create sustainable platforms for success for years to come,” Roberts said in laying out the company’s five-year plan.

Penn West believes it can grow its oil production at a compound annual growth rate of more than 12 per cent.

“Of our capital program for development activities that approaches $5 billion in aggregate over the five-year period through 2018, roughly 90 per cent of the spend will be directed to the Cardium, Slave Point and Viking areas, with over 50 per cent of total spend on the Cardium,” Roberts said.

The chief executive officer said Penn West’s Cardium well costs and cycle times are improving, and it is posting “solid” recoveries per well on primary production. Historically, the Cardium has been waterflooded successfully using vertical wells, and now “proven results from the use of horizontals are leading to further recovery improvement,” he added.

Penn West is the leading landholder in the Cardium with 600,000 net acres. “This would be a feature play in any portfolio,” Roberts said of the Cardium. “We have hundreds of well opportunities at 30-plus per cent rates of return at moderate price assumptions. The Cardium is indeed a company-maker.”

Besides its increased focus on primary light oil production, Penn West will also boost spending on waterflooding. The company may be western Canada’s biggest waterflood operator with about 135 active schemes, and it is one of a wide range of producers capitalizing on this low-cost method of boosting light oil reserves.

“We’re going to get back to our roots as a leading waterflooder in Canada, so plans will include between 10 and 20 per cent per year in investment towards our enhanced oil recovery programs, a significant increase from the past three to five years of capital programs at Penn West,” Roberts told analysts.

SOuTHErn aLBErTa WELL aCTIVITy NOV/12

NOV/13

Wells licensed





NOV/12

NOV/13

Wells spudded





NOV/12

NOV/13





Rigs released

S.A.B.

▼

▼

Southern Alberta

▼

Source: Daily Oil Bulletin

DeeThree spent $200 million targeting alberta Bakken and Belly river in 2013 Citing strong drilling results, DeeThree Exploration Ltd. increased its 2013 capital budget by $40 million to $200 million, the company announced in late November.

In the third quarter, DeeThree achieved record production for the eighth consecutive quarter, 80 per cent weighted to oil and natural gas liquids (NGLs). The company doubled its cash flow and increased its profit almost sevenfold.

The capital budget increase expanded the company’s 2013 drilling program by four more (four net) wells for a total of 35 (34.7 net) horizontal wells drilled in 2013.

The additional wells were expected to be drilled and tied in by the end of 2013, making eight more horizontal wells to be completed by year-end. The increase also accounts for acquisitions totalling 40,000 acres of Alberta Bakken (Exshaw) lands for $3 million and Brazeau Belly River lands for $8 million.

With this expanded drilling program, DeeThree increased its target 2013 exit production rate to 10,000–10,500 barrels per day (82 per cent oil and NGL) from 9,600–10,000 barrels per day (81 per cent oil and NGL).

DeeThree increased its operating netback to $48.11 per barrel from $40.57 in

the second quarter of 2013 and from $35.18 per barrel in the third quarter of 2012.

Continued success in the A lberta Bakken, also called the Exshaw, and Brazeau Belly River light oil resource plays resulted in substantial production growth in the third quarter and into the fourth quarter.

Based on field estimates, DeeThree was producing about 9,000 barrels per day (81 per cent oil and NGL) in late November, with another 2,000 barrels per day of tested volumes expected to be tied in by the end of 2013.

DeeThree continued extensive drilling on its Exshaw/Bakken play in southern Alberta in the third quarter, having drilled and completed eight (eight net) wells with a 100 per cent success rate. Two or three drilling rigs worked continuously through the quarter.

Oil production from the play rose by 43 per cent quarter over quarter to 3,935 barrels, with production in late November of about 4,600 barrels per day of oil.

DeeThree described the third-quarter drilling results as “excellent,” with seven of the eight wells drilled during the quarter on stream more than 30 days. The average

DeeThree Alberta Bakken well performance (as of August 2013) Well identification

IP 30 (bbls/d oil)

IP 60 (bbls/d oil)

IP 90 (bbls/d oil)

Current rate (bbls/d oil)

Oil cumulative (bbls) 48,500

Location 1

415

370

320

41

Location 2

520

429

390

95

89,000

Location 3

497

423

400

265

105,000

Location 4

415

333

286

190

66,000

Location 5

530

420

397

320

56,850

Location 6

442

372

334

64

39,000

Source: DeeThree Exploration Ltd.

30-day initial production rate of these wells is 472 barrels of oil per day, greatly exceeding the company’s budgeted rate of 300 barrels per day per well.

Two wells DeeThree drilled on the eastern portion of the pool earlier in 2013 continue to produce at impressive rates. The fi rst well has yielded more than 112,000 barrels of oil in six months and is currently producing 560 barrels of oil per day.

The second well has produced more than 53,000 barrels of oil in just over three months and is currently producing 585 barrels per day. The company said it has identified numerous drilling locations on its Exshaw/Bakken play that are considered to be analogous to these two wells.

DeeThree continues to add to its dominant land position in the Ferguson area. A total of 33,440 acres in the area have been acquired so far this year through Crown land sales. As a result, the company said it now holds the vast majority of on-trend Crown lands in the area.

The company planned to drill two delineation wells on its Exshaw/Bakken lands in the fourth quarter.

To maximize recovery of its Exshaw/ Bakken oil, DeeThree began a natural gas re-injection enhanced oil recovery (EOR) pilot during the quarter, injecting an average of 280 barrels equivalent per day of solution gas into its initial injector at 08-19003-16W4.

DeeThree drilled an additional gas injector at 14-16-003-17W4 and expects it be operational in early 2014. To date, the company is encouraged by the performance of its EOR pilot and will continue to evaluate results in the coming months.

DeeThree drilled and completed four (3.97 net) wells on its Brazeau Belly River property in the third quarter with a 100 per cent success rate. Toward the end of the quarter, the company increased drilling activity by adding a second drilling rig. DeeThree OIL & GAS INQUIRER • january 2014

23

Southern Alberta

DeeThree has used extended-reach horizontal well drilling technology throughout 2013 to drill wells with horizontal legs of 1.3 to two miles long to increase production rates and ultimate expected recoveries from its Brazeau Belly River light oil play.

24

january 2014 • OIL & GAS INQUIRER

also completed a major pipeline project in September. This pipeline both extends and increases the capacity of the company’s existing infrastructure in the area.

Recent drilling highlights include two horizontal wells drilled and completed more than five miles apart testing the same equivalent Upper D sand. Both wells tested at significant flow rates.

The first well, drilled late in the quarter and fracture stimulated, was flow-tested for four days up the 4 1/2-inch frac string at an average rate of 900 barrels per day of 44-degree API oil and 800 thousand cubic feet per day of gas, with a final rate of about 600 barrels per day of oil and 700 thousand cubic feet per day of gas.

After fracture stimulation, the second well, drilled early in the fourth quarter, was flow-tested for six days up the 4 1/2inch frac string at an average rate of 1,000 barrels per day of 44-degree API oil and 1,300 thousand cubic feet per day of gas, with a fi nal rate of about 1,050 barrels per day of oil and 1,700 thousand cubic feet per day of gas. Both wells exhibited new

pool pressures and, in conjunction with the mapping from existing vertical wells in the area, the company has identified potential high-impact follow-up locations.

The company continues to add to its dominant land position in its Brazeau Belly River light oil resource play. A total of 8,805 acres of highly prospective lands have been acquired year-to-date, primarily through third-party asset acquisitions.

DeeThree has used extended-reach horizontal well drilling technology throughout 2013 to drill wells with horizontal legs of 1.3 to two miles long to increase production rates and ultimate expected recoveries from its Brazeau Belly River light oil play.

In total, 12 of the 13 wells drilled yearto-date have horizontal lengths exceeding 1.3 miles.

With the cost of the longer wells being comparable to the cost of the wells previously drilled with the shorter horizontal legs, DeeThree said it has significantly increased its capital efficiency through the use of the extended-reach horizontals.

— DAILY OIL BULLETIN

S.K.

SaSKaTCHEWan WELL aCTIVITy NOV/12

NOV/13

Wells licensed





NOV/12

NOV/13

Wells spudded





NOV/12

NOV/13





Rigs released

▲

▲

Saskatchewan

▲

Source: Daily Oil Bulletin

BlackPearl carves up Onion Lake project BlackPearl asset summary Working interest

P reserves (mmboe)

C resources (mmboe)

M  production (boe/d)

Potential production (boe/d)

P reserves PV-% ($mm)

P + C PV-% ($mm)

.%–%





,

,



,

Mooney

%





,

,





Blackrod

%







,



,

Other

%



-



,









,

,

,

,

Assets Onion Lake

Total

Technology Conventional wells, EOR Horizontal wells, ASP flood SAGD Conventional wells

Source: BlackPearl Resources Inc.

BlackPearl resources Inc. has decided to develop its Onion Lake thermal project in phases, with the first phase designed for 6,000 barrels of oil per day, rather than proceeding directly with the 12,000-barrel-perday project that was originally planned.

“The phased approach allows us to reduce our fi nancial exposure and technical risks while allowing us to benefit from learnings gathered from reviewing similar-sized thermal projects near Onion Lake,” the company wrote in a press release. “A number of other operators have demonstrated that these Saskatchewan thermal projects tend to be smaller than projects typically developed in the Alberta oilsands, but they also have certain cost advantages which can provide very attractive economics.”

BlackPearl has started detailed engineering work for the smaller project but will defer procurement and construction until fi nancing is in place, which was expected by the end of 2013. Capital costs are pegged at $175 million.

During the third quarter of 2013, BlackPearl’s application to construct a 12,000-barrel-per-day thermal enhanced oil recovery (EOR) project at Onion Lake was approved by Indian Oil and Gas Canada,

which was the final major regulatory hurdle before development could begin.

With all key regulatory approvals in hand, BlackPearl estimated it could move more than 70 million barrels of oil from the resource category to the reserve category for 2013 year-end reserve reports.

Strong crude oil prices and tighter differentials contributed to BlackPearl posting record revenues and cash flow during the third quarter of 2013; however, production was fl at in the same quarter the previous year, said the company.

Output averaged 9,382 barrels equivalent per day in the third quarter of 2013, comparable to the same quarter in 2012.

Higher production associated with the alkaline surfactant polymer flood at Mooney was off set by natural production declines at Onion Lake.

A key component of BlackPearl’s strategy is to move thermal assets into development, and the company made very good progress in the third quarter of 2013, it said.

From 2009 to 2013, BlackPearl’s compounded average growth rate (CAGR) in oil and gas production was about 16 per cent.

“With Phase 1 of the Onion Lake EOR project producing 6,000 barrels of oil per day by early 2016, we will exceed that

historical CAGR with little or no dilution,” BlackPearl said. “We should be able to achieve that growth with a debt-to-cashflow under two times.”

The company’s ability to find a partner for its commercially proven Blackrod project would f ur t her en hance t hat growth rate, it added. BlackPearl has been operating the steam assisted gravity drainage pilot at Blackrod for more than two years, and it continues to produce in excess of 300 barrels of oil per day at a steam to oil ratio of between 3.5 and four, said the company.

Earlier last year, BlackPearl expanded the pilot by drilling a second well pair and initiated steam injection in early November.

The Alberta Energy Regulator (AER) is continuing to review the company’s 80,000-barrel-per-day commercial development application at Blackrod.

Blac k Pea rl has responded to t he AER’s first set of supplemental information requests and received a second set, which it was expected to respond to in early December.

The company expects to receive regulatory approval in the first half of 2014 and is looking for a joint-venture partner.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • january 2014

25

Saskatchewan

Lightstream expanding EOr schemes in 2014

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january 2014 • OIL & GAS INQUIRER

Lightstream resources Ltd. plans to expand both a well-optimization program and natural gas–based enhanced oil recovery (EOR) program in its tight oil assets this year.

Production in Lightstream’s Bakken business unit averaged 16,016 barrels per day (14,967 barrels per day of oil and natural gas liquids) in the third quarter of 2013, down slightly from the second quarter, the company said.

“We currently have two major projects underway that we’re looking to maximize future value for existing assets in the Bakken business unit,” said Rene LaPrade, senior vice-president and chief operating officer.

The fi rst is a well-optimization program that has “generated some very positive results to date,” LaPrade told a conference call after the company released its third-quarter results.

Lightstream said it has optimized more than 300 wells in the past 18 months, which has helped to mitigate production declines.

The program involves mill-outs and cleanouts of restrictions in the horizontal legs of Lightstream’s Bakken producers, along with the optimization of downhole and surface equipment.

“This program was initiated in 2012 and resulted in over 2,800 barrels per day of incremental production at capital efficiencies of less than $10,000 per barrel,” LaPrade told investors. “Based on this success, we continued on this program in 2013 with over 2,500 barrels per day of incremental production to date.

“For a relatively small capital investment, we have managed to mitigate declines on over 300 of our existing wells. We plan to continue to build on this initiative in 2014.”

Like cold heavy oil, tight oil has low recovery factors on primary production. More than two years ago, Lightstream began testing the re-injection of dry natural gas into the Bakken Formation as an EOR technique.

This has now progressed to project status from a pilot test with one injection well, LaPrade said.

“To date, we have been injecting dry gas into three wells in our Creelman project with a fourth injector presently being drilled and forecasted to be on injection in 2014,” he said.

The hydrocarbon-based EOR project is still at an early stage, but the company describes the results of its fi rst injection pilot as encouraging. The second and third wells have been on injection for much shorter periods.

Lightstream is evaluating opportunities for new dry gas injection pilots in both its Bakken and Cardium business units.

“We continue to refine our techniques to improve well response and performance,” LaPrade said.

Asked whether hydrocarbon flooding could be done on a much larger scale this year, the chief operating officer said the company has to work through “complications” such as land-tenure issues: “As you know, you need continuous sections and acreage to implement those floods, or unitizations which take even longer.”

If natural gas–based EOR is successful in tight oil formations, it could be a low-cost way of adding reserves. Lightstream is re-injecting

Saskatchewan

its own natural gas separated from produced oil. The wells are already drilled, completed and on production, and infrastructure is in place.

In the Bakken, Lightstream hopes primary production will ultimately recover up to 15 per cent of the original oil in place.

While the proof will be in the production, the company believes recovery factors could top 25 per cent with EOR success.

Asked when Lightstream will have thirdparty confirmation of the EOR potential of its gas floods, LaPrade said Lightstream’s independent reserve evaluator may have

some numbers in its year-end reserves report that will be completed in early 2014.

“We did see some small amount of reserves associated with success on the first pilot.... We would expect that we would see some more significant reserves on the 2014 reserve report,” he said.

renegade production up renegade Petroleum Ltd. reported average production at 7,464 barrels per day in the third quarter of 2013, which is 90 per cent more than during the same time frame in 2012.

According to the company’s third-quarter 2013 financial and operational results, the dramatic production increase resulted from a property acquisition that closed late in 2012 as well as Renegade’s successful 2012-13 drilling and completions program.

During the third quarter of 2013, the company drilled 20 (18.5 net) wells, including six (five net) in southeastern Saskatchewan and 14 (13.5 net) in west-central Saskatchewan, with two (1.8 net) of those wells expected to be completed in the fourth quarter of 2013.

Further, Renegade completed and brought onto production 20 (18.1 net) wells in the third quarter of 2013, including two (1.3 net) wells drilled in the second quarter.

I n s out he a s te r n Sa sk atc he w a n , Renegade continues to show strong well performance on its assets acquired in December 2012. Seven of the nine wells have production history in excess of 30 days, with an average 30-day initial production rate of 195 barrels per day. The average drill, complete and equipping costs associated with the nine wells was approximately $1.2 million to $1.4 million per well.

Renegade has initial results on nine (6.7 net) wells drilled after the 2013 spring

breakup in southeastern Saskatchewan, with a 100 per cent success rate. Of those wells, six (4.6 net) are located in the Queensdale and Cantal area, targeting the Frobisher and Alida formations, two (1.7 net) wells are in the Gainsborough area targeting the Alida Formation, and one (0.5 net) well is in the Crystal Hills area targeting the Souris Valley Formation.

It has also drilled and is in the process of bringing onto production one (one net) triple-leg horizontal well in the Silverton area. The company is drilling the second well in the Silverton area, which it planned to bring onstream by mid-December.

— DAILY OIL BULLETIN

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www.unitedcentrifuge.ca OIL & GAS INQUIRER • january 2014

27

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TMK IPSCO Opens Edmonton Threading Operations

I

n 2013, TMK IPSCO opened threading operations in Edmonton, Canada, the newest of its North American facilities. With a location selected specifically to be close to oil & gas customers near western Canada’s drilling activities, TMK IPSCO’s Edmonton pipe threading facility is ideal for short runs and quick turnarounds.

“Shortly after opening our Calgary sales office in 2010, it became clear that our customers would also benefit from a threading operation close by,” explained John Kearsey, Director of Sales, Canada. “We can do longer runs and full orders for customers, but we set up the facility for Canadian drilling operators needing to quickly replace threaded pipe or accessories like float equipment, marker joints and crossovers,” he added.

As an industry leader in welded and seamless pipe, premium connections and accessories, TMK IPSCO has a legacy of quality, exceptional customer service and innovation. “The Edmonton facility supports our mission of strategically locating operations in the key energy-producing areas of the world,” Kearsey said. TMK IPSCO also has four threading operations in the United States, including two in Houston, Texas. The company has OCTG casing and tubing operations in six North American locations.

Custom-designed from the ground up for efficient operations, the Edmonton plant features a floor plan for optimal production flow to streamline the pre-production,

swaging, annealing, threading and inspection functions. The Edmonton facility can apply proprietary ULTRATM Premium Connections threads, TMK Premium brand threads and API threads to pipe in the OD size range of 114.3 mm to 339.7 mm (4 1/2” to 13 3/8”). Kearsey pointed out that the ULTRATM Premium Connections are popular in the challenging plays of Duvernay, Cardium and Montney.

Regarding the plant’s key ability to respond to customer needs, Kearsey noted that the new Mori Seiki CNC threader at the Edmonton facility is one of the largest in Canada.

“The impressive speed rates, excellent precision and dual turret system of the CNC threader helps us keep our change over time low, so we can fill customers’ urgent orders even more quickly.”

Kearsey confirmed that all TMK IPSCO OCTG products also meet or exceed API specifications. ◆ To reach the TMK IPSCO Canadian sales team, call 403.538.2182 or visit the company web site: www.tmk-ipsco.com

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DRAINING THE

High volume and liquids-rich wells make Deep Basin one of few profitable gas targets

S

ince John Masters discovered the Deep Basin gas play on the western reaches of central Alberta in 1982, it has proven a tough puzzle to crack for Canadian explorers.

With zone upon zone of stacked tight gas formations separated by impermeable sandstone, early developers in the play completed individual formations using vertical wells. Comingling regulations then allowed operators to complete more than one zone per wellbore, making the Deep Basin more economically viable. Then came the advent of horizontal drilling and multistage fracturing that has blown the Deep Basin open, creating profitable, high-volume gas wells, even at today’s gas prices.

Tourmaline Oil Corp. is the largest landowner in the Deep Basin, with more than 1,800 sections in the play.

“We are the busiest driller in the Alberta Deep Basin,” company president and chief executive officer Michael Rose told shareholders in his third-quarter report. “We’ve got 10 rigs operating there, six are pursuing cretaceous Wilrich horizontal targets, and those are at Edson, Minehead, Banshee, Smoky-Horse and Kakwa. Two rigs are pursuing primarily Notikewin horizontal targets, occasionally Bluesky and Cardium. One rig is working the Wilrich in structure targets in the Lovett-Basing area, and the 10th rig is drilling vertical wells in pursuit of 3-D seismic defined 30

january 2014 • OIL & GAS INQUIRER

multi-objective vertical opportunities along the western margin of our Deep Basin asset base.”

The Wilrich play is currently driving Deep Basin activity, driven by huge initial production and strong volumes of highvalue condensate. Tourmaline has reported some huge wells in the play.

“The most recent two-well pad at Musreau, Kakwa tested at a final combined rate of 54.6 million cubic feet per day with 360 barrels per day of free condensate,” said Rose. “The most recent Edson Wilrich horizontal, a joint venture with Perpetual Energy [Inc.], tested at a final rate of 40 million cubic feet a day and came on through the new gas plant there at a restricted rate of 20 million cubic feet per day.”

Tourmaline expected to bring on an additional 14 Wilrich horizontal wells before year-end 2013, bringing its total to around 50 wells. It has a Wilrich drilling inventory of 1,520 locations.

Well costs are trending down as the company gains experience and knowledge of the play.

“I think we are wearing costs down. I think we’re carrying an average of $5.25 million per horizontal right now, and we think we can take that down further when we do more pad drilling,” Rose said.

Tourmaline’s first 38 Wilrich wells have been broadly positioned over an asset base that stretches about 250 kilometres from one

Photo: @istockphoto.com/ MoMorad

By Darrell Stonehouse

Cover Feature

end to the other. Rose said that with six rigs now running, optimization from pad drilling is set to begin.

“We’re going to do two- and three-well Wilrich pads and we’ll frac two or three wells at a time, and then you start seeing some cost savings, on your completions especially,” he said. “We think we will probably ultimately get the costs down to between $4.5 million and $4.75 million for a completed horizontal.”

Rose said that drilling 45–50 Wilrich wells annually is likely the company’s blueprint for Wilrich development going forward.

“I think we would maintain the pace of this year unless prices collapse and stayed low for an extended period of time, but that’s not what we think is going to happen,” he said.

Outside of the Wilrich, the company is also reporting prolific wells in other zones.

“Cretaceous Notikewin horizontal well results have also been very strong,” said Rose. “Our Marsh well tested at 14.7 million cubic feet per day at six MPa [megapascals].”

With 400,000 net acres and over 60,000 barrels of oil equivalent per day of production, Peyto Exploration & Development Corp. is also a dominant force in the Deep Basin. Like Tourmaline, Peyto is using horizontal wells and multistage fracturing to drill high-volume wells in the Wilrich and Notikewin. It is also

targeting the Falher formation and began exploring the Bluesky Formation in 2013.

“In terms of well count, if we were to look at the last several years of drilling, the Wilrich has been roughly one-third of the number of wells,” chief operating officer and executive vice-president Scott Robinson says. “It has been, and continues to be, a very important part of our ongoing program.”

Peyto is focusing on the Wilrich in its Sundance and Nosehill core areas, which means there can be slight variations in well results and costs.

“Each of these areas where we’re pursuing the Wilrich has this shoreface sand deposit, and there might be a little different depth and a little different pressure so there are variations in cost,” Robinson says. “Overall, the Wilrich program has been very consistent since inception in terms of production performance.

Year-over-year average production curves almost overlap without fail, proving that there hasn’t been any overall deterioration in the performance of the new wells we drill as compared to the first wells back in the beginning.”

Robinson says Peyto’s Wilrich wells typically have 30-day initial production rates in the four-million-cubic-feet-per-day range and after one year will decline to between 1.5 million and two million cubic feet per day. The company was producing about OIL & GAS INQUIRER • january 2014

31

Cover Feature

21,600 barrels of oil equivalent per day from the Wilrich after last winter’s drilling season.

All-in well costs have decreased to between $4 million and $5 million as efficiencies continue to be gained.

“We’ve seen drill times come down from about 25 days to sometimes in the mid-teens in terms of the number of days from spud to rig release,” Robinson says.

Peyto says it will spend between $575 million and $625 million in 2014 developing its Deep Basin assets.

This would be the largest capital program in the company’s history and involves drilling between 110 and 125 wells. It is anticipated that this record level of activity would use nine to 10 drilling rigs to develop the many stacked formations in Peyto’s Deep Basin core areas.

Peyto plans to have a higher level of rig activity in summer than in winter to reduce costs associated with heating and to take advantage of reduced service rates in summer. As in past years, it is projected that over 80 per cent of the total capital investment will be directed to the well-related activities of drilling, completions, wellsite equipment and pipelines.

The 110–125 wells will be selected from Peyto’s inventory of over 1,300 locations and are expected to add between 32,000 and 35,000 barrels of oil equivalent per day of new working interest production. A portion of this new production will offset an internally forecast 34 per cent base decline, while a portion will grow overall 2014 production to a forecast exit level between 78,500 and 81,500 barrels of oil equivalent per day.

wheRe dO we PUT

Tim Louie, vice-president of land, says that over the first three quarters of 2013, the company acquired 38 sections of land at Crown sales.

“At the end of the third quarter, our corporate acreage count was 418,000 net acres or 653 net sections,” he says. “We did purchase 11 more sections at sales in October and November, so year-to-date we’ve spent $6.4 million to acquire 49 sections.”

He also discussed the company’s new focus area at Brazeau.

“Throughout the year, we’ve continued to increase our land position here; out of the 49 sections acquired at Crown sales this year, 23 sections are located at Brazeau,” Louie says. “We also closed two asset deals in May and August, which resulted in the addition of 26 net sections.”

Drilling and completion activity in late 2013 has provided encouraging cost and well-performance results, the company reports. By combining even faster drilling times, longer horizontal laterals—most recently as long as 2,160 metres—and higher frac density, Peyto has been able to achieve even better performance for minimal additional cost. Production performance over the next several quarters will help determine the success of these changes in achieving greater overall returns.

Third-quarter drilling activity focused on the Greater Sundance core area and the many liquids-rich, sweet gas resource plays currently under development. A total of 34 wells were drilled across this land base.

Over the last year, the Bluesky and Falher formations have contributed the largest proportional increases in production with increases of 190 per cent and 80 per cent, respectively. Currently,

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Cover Feature

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Longer horizontals and greater frac density are making the Wilrich play a money-maker.

Bluesky is contributing 4,800 barrels of oil equivalent per day, and Falher is contributing 10,300 barrels of oil equivalent per day to Peyto’s total production. Proven future drilling inventory in these two formations continues to expand, and Peyto anticipates a larger percentage of future drilling activity will target these formations.

Trilogy Energy Corp. is taking a different approach to its Deep Basin operations. Trilogy reported sales volumes for the third

quarter of 2013 of 31,211 barrels of oil equivalent per day from its Deep Basin operations.

Trilogy is forecasting modest production growth in 2014, as a large portion of the company’s capital spending will be allocated to the Duvernay play, which is not expected to add significant production or cash flow until late 2014 at the earliest.

Notwithstanding the short-term production impact in 2014, management believes the allocation of capital to the Duvernay will facilitate Trilogy’s long-term growth objectives and is a prudent investment of capital at this time, the company states.

Trilogy is planning a 2014 capital budget of $375 million, of which approximately $150 million will be allocated to the Duvernay to drill approximately 11 net wells, $135 million will be directed towards drilling 30 Montney oil wells and related facilities, and the remaining $90 million will be earmarked for the Dunvegan oil, Nikanassin oil and Montney gas plays.

The company is providing the following annual estimated guidance for 2014: average production of 36,000 barrels of oil equivalent per day (roughly 45 per cent oil and natural gas liquids).

In its Montney oil play at Kaybob, Trilogy continues fi netuning its drilling and completions program. It is now drilling approximately one-mile-long horizontals with 22 fracs per well, spaced approximately 75 metres apart. Costs to drill, complete and tie in wells average around $4 million. Trilogy expects to average 12,000 barrels per day of production from its Montney oil play in 2014.

OIL & GAS INQUIRER • january 2014

33

Feature

Faster, cheaper Cost of drilling unconventional wells dropping as combination of technologies speed up operations

By Darrell Stonehouse

Photo: Joey Podlubny

T

ime is money in the drilling business, and with the cost of drilling unconventional wells in the millions of dollars, this old truism has never been more important.

The drive to push down costs has been happening across North America, and it is beginning to show results as new-­ generation drilling rigs punch multiple wells on pads to speed operations. But the new rigs and pad drilling are only part of the story. From drill bits to drilling fluids and from measurementwhile-drilling systems to casing systems, an evolution in technologies is saving operators money.

Just how much of a difference are these technologies making?

Improved drilling technologies are allowing Delphi Energy Corp. to drill two-mile-long horizontal wells with average laterals of 2,700 metres in the Montney play along the Alberta– British Columbia border. Drilling times for the company’s Montney wells have decreased 35 per cent, and drilling costs have been reduced by 25 per cent since the beginning of the Bigstone Montney program.

There have been a number of advances in drill bits to make them more durable, allowing for fewer bit changes, thus speeding drilling times.

One example is Smith Bits’ ONYX 360 rolling polycrystalline diamond compact (PDC) cutter. An industry first, this technology enables a PDC cutter to rotate 360 degrees while drilling, improving drill bit durability in abrasive formations, extending drill bit life and increasing footage drilled per run.

Positioned in the highest-wear areas of a drill bit’s cutting structure, the ONYX 360 rolling cutter uses its entire diamond edge to shear the formation as the bit rotates, distributing wear over its full circumference. Comparatively, only a small fraction of the cutter edge is used in a conventional PDC bit.

This rotation allows the cutter’s diamond edge to stay sharp longer, increasing rates of penetration (ROPs) and extending drill bit life compared to premium fixed PDC cutter technology. The new PDC cutter’s 360-degree rotation also reduces frictional heat buildup, resulting in less wear and fewer bit replacement trips.

OIL & GAS INQUIRER • january 2014

35

Feature

“

In unconventional and carbonate reservoirs, it is critical for geologists to fully understand the fracture networks that may challenge drilling operations and those that will contribute to production.

“

­­­— Steve Kaufmann, president of drilling and measurements, Schlumberger Limited

“Over the past 40 years, significant improvements in PDC materials and processes have advanced cutter performance to levels where these tools are drilling ever harder formations.

Now, for the first time, a dynamic design has been introduced for PDC cutters, allowing for a step-change in durability,” says Guy Arrington, president of bits and advanced technologies at Schlumberger Limited. “Field tests in a horizontal, abrasive sandstone interval have shown that bits fitted with the new rolling cutters drill more footage and exhibit less wear than those equipped with premium fixed cutter technology.”

In laboratory tests, the ONYX 360 rolling cutter was evaluated against a premium fixed PDC cutter drilling a block of hard granite.

After 90 passes on this test formation, the premium fixed cutter developed an extreme wear flat compared to the ONYX 360 rolling cutters, which showed virtually no sign of wear even after 540 passes, indicating a significant improvement in cutter durability.

During field testing, more than 80 runs and 130,000 feet were drilled. In the U.S. Midcontinent Granite Wash, PDC drill bits were fitted with the ONYX 360 rolling cutters. In one field test, footage was extended by 57 per cent in the abrasive sandstone formation, while ROPs increased 26 per cent. The new rolling cutters also exhibited uniform wear with no cutter loss and 100 per cent cutter rotation compared to premium fixed PDC cutters that showed greater wear with less footage drilled.

Baker Hughes Incorporated is also targeting the premium bit market with its StayCool multi-dimensional cutter, which it says helps operators drill to total depth faster and more cost effectively by extending cutter life and footage per run. Used on the Hughes Christensen Talon platform of PDC bits, these cutters incorporate a contoured diamond table, wear-resistant diamond materials and new interface designs.

“Historically, operators would design more cutters into a bit to compensate for cutter wear or damaged cutters, which isn’t always the most efficient way to drill,” says Scott Donald, vicepresident of drill bits for Baker Hughes. “The StayCool cutter allows us to offer a bit that maintains the same cutter density but can perform better when cutters are worn.”

In challenging environments such as interbedded sandstones and carbonates, bit performance is directly related to cutters and 36

january 2014 • OIL & GAS INQUIRER

their ability to withstand heat. Overheated cutters experience abrasive wear faster, which can lead to lower ROPs and higher mechanical specific energy or wasted energy that is not directly transferred into removing rock.

In the Cana Woodford field of Oklahoma, this technology provided customers with a 10 per cent improvement in ROP and a 37 per cent improvement in footage when drilling through hard sands interbedded with hard limestones.

“The StayCool cutter in the Devon Cana field has given us better penetration rates in the variable changes of formation and allowed us to have longer bit hours, thus lowering the overall cost per foot,” says Terry Wilhoit, drilling consultant for Devon Energy Corporation.

“StayCool cutters require less weight and energy input to drill the formations at the desired ROP. The cutters continue drilling long after the standard cutters slow down due to wear. These cutters save time and money by reducing the number of bit trips,” adds Justin Mullinax, drilling engineer for Devon Energy.

In the Pinedale anticline of southwestern Wyoming, StayCool cutters are being used to drill through abrasive sandstones interbedded with shale. In this area, the Talon bit with StayCool cutters has improved the distance drilled by 12 per cent in 50 runs totalling 156,000 feet. StayCool cutters have already drilled more than 289,000 feet in 89 runs in five different applications in field tests and for more than 20 customers throughout the United States.

Laboratory testing has shown that the cutters generate 20 per cent less heat on the cutter face than conventional flat-surface cutters. Less heat minimizes cracking tendencies on the diamond table, which can lead to failures and shorten run life. As a result, run lengths are extended, and the cutters remain aggressive while enabling the bit to maintain higher ROPs throughout the bit run.

Geosteering technology that allows real-time adjustments in positioning the wellbore is also saving drilling time and costs.

Schlumberger’s MicroScope HD high-definition imagingwhile-drilling service is an example of the next generation of geosteering. The MicroScope HD service provides logging-whiledrilling imaging for reservoir description to enable detailed fracture characterization and completion optimization in conductive

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drilling fluids for all well types, including horizontal and highly deviated wells.

“In unconventional and carbonate reservoirs, it is critical for geologists to fully understand the fracture networks that may challenge drilling operations and those that will contribute to production,” says Steve Kaufmann, president of drilling and measurements at Schlumberger. “This newly developed MicroScope HD technology provides detailed imaging of the formation to help prevent drilling risks, optimize completion design and potentially increase production.”

The MicroScope HD service enables detailed formation structural modelling to identify fracture orientation that contributes to production. An understanding of how formations are deposited is further enhanced with the service through sedimentology analysis. For fracture characterization, the MicroScope HD service delivers dimensions of fractures, which provides geologists with a better understanding of the fracture network.

The MicroScope HD service has been field tested extensively in reservoirs in the Middle East, Europe and Africa, as well as in unconventional reservoirs in North America. More than 45 job runs have been completed, confi rming that high-defi nition images can be obtained reliably in conductive mud environments while drilling in oil and gas carbonate, sandstone and unconventional reservoirs.

In the Middle East, Petroleum Development Oman LLC was experiencing heavy mud losses while drilling a well in an onshore carbonate reservoir. The MicroScope HD service provided highdefinition images to accurately identify intervals with mud losses, which enabled Petroleum Development Oman to isolate the challenging zones and optimize the completion design.

Another significant development in drilling technology is the growing use of monobore technology. In traditionally cased horizontal drilling applications, contractors had to drill a vertical well, run the casing and set it before drilling the horizontal leg.

With monobore drilling, the casing string is run, and then a steel cone is forced down the casing to expand it in the hole. The process is repeated with identical casing strings. Thus monobore completions have the revolutionary characteristic of installing a string with the same interior diameter from top to bottom.

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advertisers' index Allmand Bros Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . .14

DiCorp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10

Platinum Energy Services Corp. . . . . . . . . . . . . . . . 11

Annugas Compression Consulting Ltd . . . . . . . . . .16

Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . . . 4

Platinum Grover Int. Inc . . . . . . . . .inside front cover

Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . . .14

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . . .18

Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . . . 32

Beijing Zhenwei Exhibition Co, Ltd . . . outside back cover

Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . . 33

Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . . 22

Joint Utilities Safety Team . . . . . . . . . . . . . . . . . . . 8

SaskPower Corporation . . . . . . . . inside back cover

Canadian Enviro-Tub Inc. . . . . . . . . . . . . . . . . . . . . .37

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . . .37

TMK IPSCO . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 & 29

Chase Operator Training . . . . . . . . . . . . . . . . . . . . . 15

Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . . 26

United Centrifuge Ltd . . . . . . . . . . . . . . . . . . . . . . .27

City of Grande Prairie. . . . . . . . . . . . . . . . . . . . . . . 34

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . . .7

Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Phoenix Fence Inc. . . . . . . . . . . . . . . . . . . . . . . . . . 22

Western Manufacturing Ltd . . . . . . . . . . . . . . . . . 26

38

january 2014 • OIL & GAS INQUIRER

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