January 2015 Edition - Canadian Heavy Oil Association

Transcription

JMAONNUTAHRY2 021 03 1 5E DEI DT I TO INO N
JOURNAL OF THE
CANADIAN HEAVY OIL ASSOCIATION
10
13
07
16
10
COVER
STORY
FEATURE ARTICLE
Content
goes
here, UPDATE
content goes
N-SOLV
PILOT
here,
content
goesoilhere
Project
exceeds
quality
expectations
TECHNICAL ARTICLE
Content
goes here,
content goes
TECHNICAL
ARTICLE
here, content goes here
Is your bottomhole assembly
sagging?
IN THE TRENCHES
Content
here, content
goes
IN THEgoes
PUBLIC
INTEREST
here, content goes here
The way forward on improved
oilsands monitoring and regulation
CONTENTS
DEPARTMENTS
TECHNICAL ARTICLE
Q&A
NEWS
Upcoming events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 04
Speaker recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 04
Crude oil differentials update . . . . . . . . . . . . . . . . . . . . . . . 05
CHOA SPONSORS
JANUARY 2015
......................................
BOARD OF DIRECTORS
..............................
18
18
ON THE COVER
N-Solv Corporation’s
bitumen extraction solvent
technology (BEST) pilot
has produced over 25,000
barrels of bitumen since
start-up in spring 2014.
photo: n-solv
About the Canadian
Heavy Oil Association
the mission of the Canadian Heavy oil association is
to provide an appropriate technical, educational and
social forum for those employed in, or associated
with, the heavy oil and oilsands industries.
suite 400, 500-5 ave sw
Calgary, alberta t2p 3L5
p: 403.269.1755 | f: 403.453.0179
e: office@choa.ab.ca | choa.ab.ca
CHOA Editorial Committee
EDITOR
deborah Jaremko, oilsands review
TECHNICAL EDITOR
gordon stabb, durando resources Corporation
COMMITTEE MEMBERS
KC yeung, Brion Energy Corporation
adrian dodds, Kaizen Energy inc.
Bruce peachey, new paradigm Engineering Ltd.
ADVERTISING CONTACT
06
q&A with peter Howard
new study for the first
time shows real data about
oilsands economic impacts
across Canada
07
Is your bottomhole assembly
sagging?
By Brian Mracek, Brion Energy
By Melanie Collison, guest writer
IN THE PUBLIC INTEREST
10
the way forward
new monitoring, regulatory and
collaborative programs are reflective
of the current mindset in industry
By Andrew D. Miall, Department of Earth
Sciences, University of Toronto
PROJECT UPDATE
16
N-Solv pilot
a conversation with Joseph Kuhach,
CEo, n-solv Corporation
By Deborah Jaremko, CHOA Journal editor
MESSAGE FROM THE PRESIDENT
An engineer’s work is
never done! Whether it is
finding ways to increase
production in times of high
prices or focusing on ways
to decrease the cost of production during times of low
prices, there is a constant
need for innovation and
continuous improvement in the heavy oil industry.
Of course, this is why the CHOA came to be: to
bring to the forefront new approaches for delivering the triple bottom line. With this in mind, in
2014 we re-launched our fall conference, making
it bigger and better than ever before—and were
very pleased to exceed expectations, including in
our attendance targets! To give you a complete
synopsis of the event, I am very pleased to turn the
pen over to CHOA volunteer extraordinaire and
the board member responsible for CHOA professional programs, Rodger Bernar.
Rodger: The Canadian Heavy Oil Conference
(CHOC) was a year in the making and took the hard
work and dedication of many volunteers and staff. Our vision was to make this the annual
go-to conference for heavy oil industry stakeholders throughout North America. It was our
intention that, through presentations of diverse
perspectives, conference attendees would gather
a better understanding of the business and
investment. We had a buffet of topics to dine
on from project execution, aboriginal concerns,
investors, market access, diluent reduction and
steam generation to thermal well improvements
and new geological insights.
Above all, we wanted to provide plenty of
opportunities to network and talk about the ideas
generated, because that’s how work gets done.
By all accounts, our first year was an all-round success, hosting more than 600 attendees.
We had a lot of great feedback and will be
focusing on building these constructive suggestions into next year’s conference, which will start
planning in January. We are looking for more volunteers with the aim of extending the conference
to two full days, adding another track and increasing attendance to over 1,000. We will be looking
for your continued support and feedback—tell
us how we can best serve your information and
networking experience so you get value spending
your time at “the CHOC.”
Look forward to hearing from you soon—and
see you at CHOC October 2015!
Rodger Bernar, CHOA director and
Gail Powley, CHOA president
nick drinkwater, Junewarren-nickle's Energy group
p: 403.516.3484
e: ndrinkwater@junewarren-nickles.com
the Journal of the Canadian Heavy oil association
is published by Junewarren-nickle’s Energy group.
Did you know? You can join the Canadian Heavy Oil Association’s group on LinkedIn for
networking and industry-related discussions. Find us here: http://goo.gl/8f5je.
Journal of the Canadian Heavy Oil Association
3
NEWS
UPCOMING EVENTS
JANUARY
FEBRUARY
06
TECHNICAL LUNCH - BUSINESS,
TRANSPORTATION AND MARKETING
20
EDMONTON DINNER EVENT
22
BEER AND CHAT RESERVOIR AND PRODUCTION
Calgary Petroleum Club
Faculty Club, University of Alberta
04
TECHNICAL LUNCH FACILITIES AND UPGRADING
05
MARDI GRAS 2015!
Commonwealth Bar & Stage, Calgary
19
BEER AND CHAT - ENVIRONMENT
24
Faculty Club, University of Alberta
THANK YOU TO OUR EVENT SPEAKERS
DATE
EVENT
SPEAKERS
PRESENTATION
Oct. 6
TECHNICAL LUNCH - BUSINESS,
TRANSPORTATION AND MARKETING
Oliver Youzwishen, TransCanada Corporation
TransCanada’s Energy East Pipeline project
Oct. 28
Neil Camarta, Field Upgrading Ltd.
My six billion dollar education
Gerry Belyk, Bryce Jablonski, Rodger Bernar, Trent Kaiser, Don Murray, Basil El Borno
Heavy Oil 101 workshop
Barclay Cuthbert, US Oil Sands; Fred Wasden, Shell Canada; Derik Ehresman, Harris Corporation
Project updates
Ezra Levant, author and broadcaster
Keynote
Robert Skinner, School of Public Policy, University of Calgary
Keynote
Albert Mansour Innovative Steam Technologies; Chris Popoff, Terrestrial Energy Inc.;
David Pernitsky, Suncor Energy
Treatment and steam generation
Corrina Bryson, Nexen Energy; Don Hennessey, Logan Completion Systems;
Dan McCormack, PetroJet Canada; Mark Rosenbaum, Stroud International
Thermal operations
Jackie Forrest, ARC Financial; Jared Wynveen, McDaniel & Associates;
Deborah Yedlin, Calgary Herald
Market commentary
Phil Fontaine, First Nations leader
Keynote
Joe Gasca, Fractal Systems; John Howard Gordon, Ceramatec; Kevin Lee, Twin Hill Resources;
Lazarus Saidakovsky, Envirotech Green
Partial upgrading
Maurice Batallas, Berado Shaw; Trent Pehlke, Suncor Energy; Barbara Wingate, Shell Canada
Well delivery and recovery process
Cody Battershill, Canada Action; Robb Campre, Fort McKay Industrial; Chris Reynolds, Stantec
Community development and engagement
Ryan Chase, Excelsior Engineering; Mark Doig, Propak Systems; Ken James, Oak Point Energy
Project execution
Duncan Findlay, Grizzly Oil Sands; David Tam, CGG Veritas; Peter Vermeulen, Brion Energy
Geology
Steve Fekete, IHS; Randy Meyer, Altex Energy; Cory Neufeld, Inter Pipeline
Market access
Nov. 3–4
4
CANADIAN HEAVY OIL
CONFERENCE
Nov. 25
Lorraine Royer, Williams Energy Canada
Adding value to resources in Alberta
Nov. 26
BEER AND CHAT DRILLING AND COMPLETIONS
Mirko Zatka, Shell Canada; Vince Boucher, Suncor Energy; William Butler, Tervita;
Adrian Campbell, ConocoPhillips
Compatibility of wells in thermal projects: What does
this mean to operators and what is the potential impact?
Dec.1
TECHNICAL LUNCH RESERVOIR AND PRODUCTION
Sandeep Solanki, Laricina Energy
Germain SAGD project update
Journal of the Canadian Heavy Oil Association | JANUARY 2015
NEWS
CRUDE OIL
DIFFERENTIALS UPDATE
FROM FIRSTENERGY CAPITAL CORP.
WTI-WCS DIFFERENTIAL
$50
$40
$30
$20
$10
$0
JAN-12
JUL-12
JAN-13
JUL. 2014 AVG. $25.27
The much-anticipated OPEC meeting
on November 27 resulted in the cartel
agreeing to continue its collective quota of
30 mmbbl/d that was established in January
2012. This amounts to a “do nothing”
approach by the cartel in the face of crude oil
oversupply in a number of regional markets
and steadily declining WTI and Brent prices
over the past several months. In other words,
there is no immediate correction for physical
oversupply in the market that will be forthcoming from OPEC. As such, typical market
mechanisms via price signals will have to balance out the market for the near term, at a
minimum, by stimulating demand and curbing
supply growth through lower prices.
In full-on bear markets, prices can often
take on a life of their own that is divorced
from the fundamentals. We expect such a
thing will happen again in this cycle that
could see fairly low prices persist for a few
months. We think a new price low in the lowUS$60s/bbl to upper US$50s/bbl for WTI will
JUL-13
JUN. 2014 AVG. $23.25
JAN-14
JUL-14
JAN-15
JUL. 2013 AVG. $14.95
be put in before the end of the year (midUS$60s to low US$60s/bbl for Brent). From
there, we think prices will stabilize and begin
a gradual recovery back to the US$70/bbl
range by the end of the first quarter, 2015.
Beyond that, we expect stability for both
markers between US$70/bbl and US$80/bbl
for the balance of 2015.
OPEC’s decision to maintain the current
collective quota at 30 mmbbl/d means that
there will be no willful production curtailments to deal with physical oversupply in
some key markets, such as the Atlantic Basin.
This sets the stage for a continuation of
strong inventory accumulations in the market,
which could persist into the late stages of
2015. More importantly, the key Gulf members of the cartel—Saudi Arabia, Kuwait and
the United Arab Emirates—all agreed that a
cut was not necessary at this time, knowing that they would have been the member
countries to bear most of any production cuts
that would have come about in a production
curtailment scenario. Worse, the cartel has
agreed that it will not meet again until June
5, 2015, suggesting no hurry by these three
key members to deal with current weak prices
and physical oversupply. If the cartel does not
meet again until mid-2015 and, perhaps at
that time make a production cut, the effects
of such a production cut would not be felt in
global oil balances until late in the third or
early fourth quarter, 2015. This means that
oversupply and relatively low prices will be
with us for almost another year at a minimum. A return to US$100/bbl is out of the
question for at least two years.
Recognizing that market access is currently a
very high-priority issue for the heavy oil and
oilsands industry, the Journal of the Canadian
Heavy Oil Association includes this update on
crude oil differentials from FirstEnergy Capital
Corp. If you would like to contribute to or comment on our market access coverage, please
contact djaremko@junewarren-nickles.com.
5
CHOA PROFILE
Q&A
PETER HOWARD
with
CaNADIAN ENERGY RESEARCH INSTITUTE
For the first time, a new study
shows real data about oilsands
economic impacts across Canada
By Melanie Collison, guest writer
The Canadian Energy Research Institute (CERI) recently released an
update to its 2010 study of the oilsands industry’s Canada-wide
economic impacts. The study, which includes new layers of data
from Statistics Canada, definitively shows that every province and
territory shares gross domestic product (GDP) numbers, tax income
and employment. Peter Howard is CERI’s president emeritus, having
retired in November 2014. He will be replaced as president and
chief executive officer by Allan Fogwill.
CERI recently released Canadian Economic Impacts of
New and Existing Oil Sands Development in Alberta
(2014-2038). What’s the main message?
A
When we put out our last report in 2010, [SAGD] was really in its
infancy. We wanted to advance in time and see what’s going on
in the industry in terms of economic relations. StatsCan has taken
SAGD out of its mining and oil and gas extraction sector, so now our
discussion of the impact [of oilsands development] on manufacturing
in Ontario is based on real data.
The impacts on the other provinces actually double—11 per cent of
GDP and employment is felt in provinces outside Alberta. It’s a story
centred around Canada as a whole.
Our major project for the year has been to do a complete analysis
of the hydrocarbon resource sector across Canada and establish the
impacts province to province. We plan an all-encompassing report,
from [LNG] in B.C. to the Orphan Basin off Newfoundland, that we’ll
publish in March.
To test our model, we used oilsands growth as the benchmark
and decided to publish it as a briefing paper ahead of the rest. We
debated the oil price and picked $85/bbl, and suggest this is a lowerbound look at the impact.
Q
A
6
How will this paper be used?
Producers will take these numbers into context. It’s background information for them, so it won’t materially affect their planning.
For government, it exposes the value of oilsands to the provinces,
with the implication of what could be lost to the Canadian economy.
We can say the same thing—that the impact will be national—about
LNG and offshore East Coast production.
GDP and tax numbers will be useful. The equalization payment
program will probably stay in effect if this all comes to pass, but the
numbers might change.
Q
How would you characterize the outlook for the
oilsands?
A
This report assumes [that] planned pipelines or some combination of
pipe and rail will allow these barrels to get to the global market. The
production profile is realistic or cautious, with production growing
more slowly than pipeline additions.
In this briefing paper, as in CERI’s Canadian Oil Sands Supply Costs
and Development Projects (2014-2048) report last July, raw bitumen
production is forecast to plateau in 2029 and begin to fall off in 2046.
I’m bullish on both oil and gas for next year, for sure. We will move
an additional 200,000-plus bbls/d by rail. Rail has under construction
today 1.3 million bbls/d of loading capacity, expected on stream by
2017.
Moving out to the 2017 timeframe, I don’t know whether I’m bullish or just hoping Keystone XL will finally be approved.
I think the Energy East Pipeline will be approved and that’s as far as
I dare go into the future.
Trans Mountain and Northern Gateway—being an engineer I have
to believe eventually those projects will pass the test and be approved
and constructed. Both have to get over significant challenges, not the
least of which is social licence.
PHOTO: CERI
Q
TeCHNICAL ARTICLE
FLEXED DRILL COLLAR BOTTOMHOLE ASSEMBLY
BHA
WEAR-BAND
SIGNIFICANT DEFLECTION OCCURS HERE
SLOPE
DOWNHOLE
NON-FLEXED DRILL COLLAR BOTTOMHOLE ASSEMBLY
BHA
SLOPE
Is your bottomhole
assembly sagging?
Figure 3
Lab-tested BHA schematic with flex collar
vs. non-flexed collar.
Conclusions from testing BHAs:
• A flexed drill collar deflects
significantly at the first
reduced-OD section.
• S
ag BHA modelLing is unable to resolve
this deflection.
By Brian Mracek, Brion Energy
W
ell, if you are a middle-aged adult like
most of us, you probably already know
the answer to that question. However, if you
are referring to the bottomhole assembly (BHA)
that is drilling your SAGD wells in northern
Alberta, you may not. You may believe it to be
an insignificant or at worst a very small correction, but some small changes to your BHA may
be making the sag correction incalculable. If
that is the case, you may not be taking enough
care to accurately determine your well placement. This article discusses how small changes
to standard or commonly used BHAs make
major differences to the sag of a BHA, what is
being overlooked and that some changes can
make sag-modelling software erroneous.
What’s the big deal?
We know that the tool accuracy we are using
is +/- 0.12 degrees and we can live with that;
however, error in tool accuracy is random and
should have a mean of zero (un-biased) while
the sag correction addresses a systematic bias
or error. Sag is the misalignment of the directional sensors in the BHA with the wellbore
direction due to the deflection of the drill
collar they are housed in because of gravity
(ref. SPE 102088).
The big deal is that over the length of an 850metre lateral that we are drilling in the MacKay
field in northern Alberta, for typical BHAs the
bias due to sag could be in excess of four metres.
For a production engineer, this would amount
to significant stranded recoverable bitumen.
Furthermore, early steam breakthrough from a
sloping sub-cool line could greatly affect production rates and again cause stranded bitumen,
reducing the overall project economics.
Identifying the problem
While drilling our second SAGD well pad at
MacKay, our geologists became concerned that
the geometric measurements (surveys) were
not matching the geological model that they
had prepared. Knowing that the accuracy of
the tools could create an ellipse of uncertainty
that could account for some random differences, we were hesitant to jump to any conclusions, but SAGD drilling in Alberta generally
7
technical article
MWD vs wireline gyro
PROJECTED IN APPROX 50m
[WILL PASS THIS WELL AT -1100M MD]
324
320
316
312
TOP OF PAY
308
ACTUAL PRODUCER
TD (MWD):
1326.00m MD
204.89m TVD
295.55m ASL
AUG 24, 2013
304
300
DRILLED PRODUCER
FROM EM
SURVEY DATA
296
DRILLED PRODUCER
FROM GYRO DATA
292
ACTUAL PRODUCER
TD (GYRO)
1319.00m MD
208.38m TVD
292.06m ASL
BASE OF PAY
289
AUG 24, 2013
284
0
80
160
240
320
400
provides very tight geological control, with
multiple stratigraphic and observation wells in
proximity to every pad.
Some of our producers were drilled and
ranged to within 2.5 metres of observation wells,
placed at the toe end of the lateral. This point-topoint measurement contradicted the geometric
measurements or surveys. Evaluating the trajec
tories after the pad was drilled, it became apparent
that all of the surveys seemed to be showing the
same bias. As an analogy, the chances of this
being random would be like getting struck by
lightning—six times in a row.
To confirm our fears, a suite of additional wireline gyro surveys was run in all of the producers
and one injector well on this pad. While these
results (shown in Figure 1) confirmed that something was amiss, the service company’s modelling
did not have any answers, leaving us to begin a
systematic review to look for the bias.
Equipment testing
To start investigating systematic bias or compounding total vertical depth (TVD) error, we
first tried to eliminate the high-probability
causes and tighten our TVD control as much as
possible. Our service provider ran a sag-modelling
software to check for sag in our BHA and to
eliminate potential error. Considerable iterations
were run with no apparent bias found. A QC/
QA process was implemented on the directional sensors, both in the field and back in
their shop. The process looked for out-of-spec
instrumentation and processes for the service
provider’s transportation, installation and
operation. Rig operations were also verified,
including proper hole cleaning, shutting down
the pumps for noise, pulling the drill string off
bottom to ensure it was in tension and working
the torque out prior to the surveys. Machine tolerances of the collars and makeup of the survey
probes were checked, including looking for
internal sag of the instruments after placement
in the collars. Sliding and rotating sections were
confirmed and then compared to wireline gyros
8
Figure 1
MWD
measurements
from
drilling vs.
wireline gyro
performed
after liner
was run.
480
500
640
720
800
880
960
1040
that were run on every producer. Even tool joint
stiffness was considered as a possible source.
However, after all of these potential sources
were looked at, nothing of a systematic bias
was found.
BHA field testing
Field testing was then initiated to determine
if the different BHAs were the problem, and a
secondary survey instrument was mounted in an
independent collar to test for repeatability of our
measurement-while-drilling (MWD) survey tools.
A wireline gyro survey was also run in each hole
after drilling for confirmation and as another
independent source of data.
We soon discovered that, as suggested by our
geologists, our primary survey instrument—the
MWD electromagnetic telemetry (EM) tool at
the very front of our BHA—was in disagreement
with the geology, the wireline gyro survey and
our secondary survey instrument. The smoking
gun was when we drilled within 2.5 metres of an
observation well that was ranged to, with pointto-point measurements, including using a gamma
ray collar locator. This point-to-point measurement was the final confirmation.
To find a solution, all data sources were considered, including new data-measuring devices. A
gyroscope-while-drilling (GWD90) tool was then
added to the BHA in conjunction with the other
two survey probes for one well. The GWD90 was
designed to operate while drilling real time at up
to 90 degrees orientation, beyond the limit of
conventional drilling gyroscopes.
The well pair was subsequently resurveyed
with wireline gyroscopes on two additional occasions, and the vertical position was further evaluated by drilling an “inclining toe-tag” a further
30 metres downward to determine how far off
the formation bottom the well actually was. This
again confirmed that drilling with the EM MWD
tool resulted in a systematic bias but of slightly
less magnitude with respect to the pulse MWD
(about two metres), possibly due to the BHA
changes. (See Figure 2.)
1120
1200
1280
1360
Addition of toe tags and hole
wash confirmation
Toe tagging was added on all wells and then
evaluated for additional confirmation. The average
TVD difference between EM and the mapped
geology determined from the toe-tags was 4.36
metres. A further field test was conducted to
evaluate if the error could be associated with hole
wash or an increasing wellbore diameter due to
hole erosion. In this test, a pulse MWD and EM
MWD were run as before, followed by duplicating
the measurements while pulling out of the hole.
The results showed consistency between both surveys in and out, but not between the two probes,
indicating that hole wash was not a contributing
factor to the EM MWD bias.
Field trials
The BHA for wells on the next pad was configured to test if the pulse MWD tool could
provide accurate surveys if positioned in front
of the EM MWD tool. This test looked surprisingly close to the gyro wireline survey. As well,
a two-metre-long dummy flange was placed
between the EWR tool and the EM MWD tool
because it was hypothesized that interference
could be a cause of survey errors, but no difference was noticed.
Another well was drilled with the EM tool first
in front of the pulse tool, then, after pulling out
of the hole and the survey tool positions were
swapped, resurveying the well all the way back
to TD. After a wireline gyro was run, the EM surveys showed the same bias both times while the
original pulse survey was in agreement with the
wireline gyro; however, the second pulse survey
had some smaller amount of bias. Several wells
were then drilled with the pulse MWD tool as the
survey tool, with an EM tool behind it, although
this slowed down drilling due to increased survey
times, vertical survey depths (as confirmed by
wireline gyro) were within half a metre of the
expected values. Finally, dual bulk resistivity tools
were run in front of both survey tools to look for
confirmation of results.
TECHNICAL ARTICLE
sAgD survey ConFirMATion TesT
191
Figure 2
MuLtipLE survEys during
driLLing vs. duaL wirELinE
gyro pErforMEd aftEr LinEr
was run.
TRUE VERTICAL DEPTH, TVD (m)
192
193
194
195
EM
PULSE
196
GYRO 1 TIED TO EM
GYRO 2 TIED TO EM
GWD90 TIED TO PULSE AT 720mMD
197
0
550
750
950
1150
MEASURED DEPTH, MD (mKB)
1350
lATerAl, rAW surveys AnD sAg CorreCTeD
205
Figure 4
Mwd MEasurEMEnts froM
driLLing vs. rECordEd ModE
survEys in a sLiCK BHa, tHEn
sag CorrECtEd.
206
207
TRUE VERTICAL DEPTH (2m/in)
208
209
210
211
212
RECORDED SURVEYS
PULSE
213
214
GYRO 1 TIED TO EM
215
216
217
260
325
390
455
520
585
650
715
780
845
910
VERTICAL SECTION AT 314.76” (65 m/in)
The only disagreement between the survey
instruments after these runs was when the bulk
resistivity formation evaluation logging tool
was used in conjunction with electromagnetic
telemetry. With the survey bias narrowed to this
particular BHA combination, lab testing of this
BHA was instigated to better understand why the
systematic error was being acquired.
lAb tEStINg
The representative BHA was assembled in the
lab on a flat surface with different orientations
and then checked for repeatability. The results of
these tests showed survey inclinations that were
off between .15 and .25 of a degree, consistently
reading higher than the known inclinations.
These results would equate to a 2.5–3.5-metre
bias over a lateral length of 850 metres.
In particular, the deflection near the first upset
of the flex collar that housed the survey probes
was abnormal and accounted for the majority of
the change. A similar change in deflection was
not observed in the second survey probe that
was housed in a slick or stiff collar. It was felt that
the slick collar was providing more uniform and
less deflection, which also allowed for better sagmodelling corrections (Figure 3).
VERIfICAtION IN tHE fIElD
After our lab testing, we could now move back
into the field for confirmation and verification.
For the next set of wells, the flex drill collar carriers
975
1040
1105
1170
were replaced with slick drill collars to give us
that stiffer and more consistent sagging BHA.
Over the next 10 wells, the primary and secondary survey instruments showed impressive agreement, including agreement with the wireline
gyros and toe tags (Figure 4).
The results from the last 10 wells are reflected
in Figure 4; a minor sag of .1 degrees over the
850-metre lateral, which amounted to a TVD
difference of 1.5 metres. After correction for
the sag, which could be calculated in the stiff
assembly, this variance was down to less than .05
degrees with many wells having a TVD variance
of less than .15 metres.
CONCluSION
MWD systematic bias is now believed to be
caused by sag in the flex collars in combination
with the standoff bands on the resistivity tool.
As designed, the wear band measurements can
vary significantly with the usage on the band.
Furthermore, modelling of flex collars in this
BHA can provide incorrect deflection results and
therefore inaccurate inclination surveys.
Utilizing stiffer or slick assemblies provides
actual results that closely agree with the theoretical
values from the modelling software by providing a
more constant stiffness over the length of the BHA
particularly where the survey instrument is placed.
BHA modelling software can allow many
characteristics of BHAs to be predicted and corrected, but it must be noted that more complex
1235
1300
BHAs may not be modelled accurately including
the stiffness of the connections that make up the
BHA. Operator expectations of survey accuracy
must recognize the limits of this modelling software and adjust their well profiles accordingly
from all sources of data.
ACKNOWlEDgEmENtS
The author would like to thank all of the technical staff at Brion Energy for their support and
contributions, in particular in figure preparation,
data management and for allowing the distribution of this information in public benchmarking
meetings, conferences and papers. Additionally
several service companies provided expertise
and understanding of the complex nature of
this problem including empirical testing in a lab
environment and technical support.
REfERENCES
Studer, R., and L. Macresy. Improved BHA Sag
Correction and Uncertainty Evaluation Brings Value
to Wellbore Placement, SPE 102088. Sept. 2006.
Comments?
If you would like to respond to the opinions
expressed in this article, we’d be glad to
publish your thoughts for our other readers.
Please contact
djaremko@junewarren-nickles.com.
9
10
The way forward
New monitoring, regulatory and collaborative programs are reflective of
the current mindset in industry and regulators towards more conscientious
environmental stewardship of the oilsands
By andrew d. Miall, department of Earth sciences, university of toronto
ILLUSTRATION: PAIGE PENNIFOLD
T
he environmental management of Alberta’s oilsands entered a new
phase in late summer 2010 when a convergence of events and public
concerns about air and water pollution led both the Government of Alberta
and the federal government to appoint expert panels to examine the state
of the environment in northern Alberta, how it was currently being managed, and what might be done to improve public oversight and confidence.
I had the honour to serve on both the federal advisory panel and the
Alberta Environmental Monitoring Panel (AEMP).
At the time of the panel studies in 2010-11, the monitoring of surface
water and air conditions in the Lower Athabasca region was being managed primarily by three multi-stakeholder agencies: the Regional Aquatic
Monitoring Program (RAMP), the Wood Buffalo Environmental Association
(WBEA, the air quality organization) and the Cumulative Environmental
Monitoring Association (CEMA). Of particular concern was RAMP, whose
work had been evaluated and criticized several times. Concerns regarding
RAMP centred on the inconsistent quality of field sampling and analytical
work and the lack of scientific peer review and transparency of the agency.
WBEA was characterized by a better calibre of scientific management and
had showed considerable initiative in responding to local concerns regarding air quality issues.
At this time there were also major public concerns about the lack of
responsiveness from agencies such as RAMP and CEMA to the concerns of First Nations residents of the area. The occurrence of some rare
cancers in residents of Fort Chipewyan and the recovery of fish with
tumours from the Athabasca River had raised particular concerns related
to community health.
In late 2010, an independent study by the Royal Society of Canada
(RSC) on the impacts of oilsands development on health and the environment concluded that the evidence pointing to the oilsands as the cause of
these problems was inadequate. The RSC called for more field studies and
improved integrated monitoring.
Final reports by the two government panels were delivered in December
2010 and late June 2011, respectively. In short, both panels concluded that
the status of environmental monitoring—particularly water monitoring—in
the Lower Athabasca region was very inadequate, and they recommended
the establishment of an independent monitoring agency to bring the level
of oversight to world-class standards. It was concluded that the federal and
provincial governments needed to find ways to work much more closely
together, that acknowledgement of the concerns of the First Nations residents of the area was lacking, and that neither level of government was
carrying out the level of work on air, water and groundwater monitoring
that was deemed necessary.
The good news now is that the federal government and the Government
of Alberta have both—albeit slowly—responded to public concerns and
panel recommendations. The level of field monitoring has improved substantially, a provisional federal-provincial agreement is in place to manage
monitoring, and funding and management structures are being constructed
to provide the necessary framework for this improved oversight.
The federal and provincial governments jointly responded to the panel
reports with the establishment of a new Joint Canada-Alberta
Implementation Plan for Oil Sands Monitoring (JOSM), announced in
February 2012.
11
This included a plan to increase the level of regular air, water and terrestrial monitoring carried out by the two governments and to critically assess and
integrate existing efforts (e.g. WBEA, RAMP, CEMA) to meet JOSM monitoring and assessment objectives as deemed scientifically necessary. This resulted in
more sampling sites with planned increased geographic coverage.
THE NEW JOINT OIL SANDS MONITORING PROGRAM
HAS INCREASED MONITORING EFFORTS BY ADDING:
FROM
NEW WATER SITES
21 TO UP TO
11
43
FROM
NEW AIR SITES
21 TO UP TO
32
The JOSM includes an information portal where monitoring results
are posted. Data sets and brief analytical commentary are available. This
answers a concern that air and water quality data were not being shared
with the public, although the highly technical nature of the data means that
interpretations by qualified scientists are still required. The work of environmental scientists within the corporate sector and the academic world has
continued to improve and has undoubtedly been made easier by the greater
accessibility of raw data.
The most important panel recommendation—that an independent
agency be established—has now also been implemented. As a first step,
the Alberta Environmental Monitoring Management Board was established
in October 2012. The work of this board led to the founding of the Alberta
Environmental Monitoring, Evaluation and Reporting Agency (AEMERA) in
May 2014.
AEMERA was designed to answer a key observation of the advisory
panels: that the Alberta government lacked the capacity to carry out
environmental monitoring. Management plans were being formulated by
the government—for example, the Lower Athabasca Regional Plan was
announced in August 2012—but the technical capacity to implement, monitor and manage this program was not in place. This is why the establishment of AEMERA has been so important.
AEMERA assumes responsibility for provincial monitoring programs and
networks, including:
 water quantity data collection (lakes and rivers);
 water quality monitoring (lakes and rivers);
 meteorological monitoring (precipitation, temperature, wind speed);
 air quality monitoring (by airsheds);
 monitoring of soil acidification; and
 biodiversity monitoring (by the Alberta Biodiversity Monitoring Initiative).
The following overarching principles apply.
 Alberta regulation now directs that AEMERA collect fees and disburse
all funding; and
 Further clarifies the need for monitoring, planning, evaluation and
reporting to be done
12
37
35 TO OVER72
FROM
22
NEW BIODIVERSITY/
WILDLIFE
CONTAMINANTS
SITES
3 TO OVER 25
FROM
• collectively;
• according to common principles, standards and protocols; and
• to achieve an overarching, statistically robust design for governments to
meet their legislated mandates.
As of the time of writing, the board of directors and a chief executive officer are in place, with a chief scientist and science advisory board still to be
appointed and technical staff to be hired. For the time being, Environment
Canada is carrying the main load of the field monitoring program, and the
first phase of the joint program will continue until September 2015.
In addition to an increase in field sites relative to 2010-11, the JOSM
has been undertaking a complete re-evaluation of the design of the field
monitoring program, upgrading analytical procedures, standardizing measurement and reporting protocols, etc. What will happen beyond this time
remains to be negotiated.
INCORpORAtINg tRADItIONAl ECOlOgICAl KNOWlEDgE
One of the most serious concerns about industry activity in the Lower
Athabasca region has been that of accommodating First Nations concerns. Representatives of First Nations have been appointed to the various
organizations managing the environment, but often have expressed frustration at being bypassed or ignored. The new board of AEMERA includes
Mike Beaver, elder of the Bigstone Cree Nation and former regional chief
for the Assembly of Nations representing Alberta First Nations.
AEMERA has also committed to the inclusion of Traditional Ecological
Knowledge (TEK) into its system through a TEK advisory panel. AEMERA
documents assert that the TEK advisory panel will play an essential role in
its monitoring, evaluation and reporting, which will promote mutual respect
between the domains of TEK and conventional science.
It was the opinion of several members of AEMP that employing First
Nations observers to monitor the health of animals and plants in their
traditional hunting areas could provide a very useful supplement to the
measurement of air and water pollution being undertaken by the JOSM
scientists. The employment of First Nations youth as observers could provide
an excellent opportunity for the training of interested individuals in the
methods of field-based observational science.
ILLUSTRATIONS: PAIGE PENNIFOLD
22
NEW BIODIVERSITY
HABITAT SITES
THE LEVEL OF FIELD MONITORING HAS IMPROVED
SUBSTANTIALLY, A PROVISIONAL FEDERALPROVINCIAL AGREEMENT IS IN PLACE TO MANAGE
MONITORING, AND FUNDING AND MANAGEMENT
STRUCTURES ARE BEING CONSTRUCTED TO
PROVIDE THE NECESSARY FRAMEWORK FOR THIS
IMPROVED OVERSIGHT.
CuRRENt ENVIRONmENtAl CONCERNS
So what are the current concerns regarding the environmental management
of the oilsands? In September 2013, Geoscience Canada published a special
set of papers dealing with this issue.
Kevin Percy, chief scientist of the WBEA, reported as follows with regard
to air quality:
“In 2012, ambient air concentrations of sulphur dioxide (SO2), nitrogen
dioxide (NO2), and ammonia (NH3) did not exceed the Alberta Ambient Air
Quality Objectives (AAAQO). There was one exceedance of the AAAQO for
ground-level ozone (O3), and 62 exceedances for fine particulate matter
with aerodynamic diameter ≤ 2.5 microns (PM2.5), most associated with
controlled biomass burning or forest fires. There were 170 exceedances of
the 1-hour hydrogen sulphide (H2S) or total reduced sulphur (TRS) AAAQO
odour threshold.
Exceedances have decreased since 2009, yet odours remain a concern in
some communities. Based on the Air Quality Health Index (AQHI), the risk
from ambient air quality to human health was calculated to be low 96 to
98 per cent of the time depending upon monitoring location, moderate 1
to 3.4 per cent, high less than 0.4 per cent, and very high less than 0.2 per
cent of the year.
In a highly regulated setting like the [Alberta oilsands], it is critical for
stakeholders to quantify the spatial influences of emission source types
for explaining any consequential environmental effects. Source apportionment successfully matched source chemical fingerprints with those
measured in terrestrial lichens throughout the region. Forensic receptor
modeling showed source types contributing to elemental concentrations
in the lichens included: combustion processes (~23 percent); tailings sand
(~19 percent); haul roads and limestone (~15 percent); oilsand and processed materials (~15 percent); and a general anthropogenic urban source
(~15 percent). Re-suspended fugitive dust from operations, tailings dikes,
quarrying, on-road transportation, and land clearing was found to contribute enrichment to a much greater degree than the hitherto assumed
combustion source type.”
David Schindler, professor of ecology in the Department of Biological
Sciences at the University of Alberta, summarized concerns about water
quality issues in a companion article:
“Adequate data are available to show that mercury, other trace metals, and
polycyclic aromatic compounds are being added by industry to the river system
and its watershed, although the relative contributions of industrial development
and natural sources remain in question. Recent improvements in water monitoring by Environment Canada show promise of resolving the controversies,
although independent governance for Canada’s and Alberta’s water monitoring
programs in the lower Athabasca River will be necessary to rebuild public confidence in the data and their interpretation by government and industry.”
It is to be hoped that the establishment of AEMERA and the functioning
of the JOSM will answer these problems.
My own article in the publication addressed groundwater issues:
“Increasing efficiencies in processing technologies have reduced water
use substantially, and currently at least 75 percent of the water used in
most operations is recycled water. Much concern has been expressed
regarding contamination of surface waters by seepage from tailings
ponds, but hydrogeological studies indicate that this is not happening;
that seepage capture design is effective. Oilsands mining and in situ project licensing and operation regulations include Environmental Impact
Assessments that mandate considerable hydrogeological measurement
and monitoring work. However, little of this is independently evaluated for accuracy or synthesized and interpreted for the public. Recent
changes in Alberta environmental regulation, including the establishment
of the Alberta Environmental Monitoring Management Board (in October
2012) are expected to bring new transparency to environmental management of oilsands operations.”
According to the JOSM, its results up to spring 2013 “are showing evidence
that substances of concern released during oilsands development are present
in air and water. Levels are highest close to mining sites and upgraders [and]
decrease with distance. Generally, observed levels do not exceed guidelines
and are not cause for concern.”
Earlier work by the RSC had concluded that the air quality in the vicinity of Fort McMurray was comparable to that of industrial areas in major
cities, although transient odours in communities such as Fort McKay are
an ongoing problem.
futuRE CONCERNS
It would appear that the public attention paid to air and water quality issues
caused by oilsands activity has resulted in a significant improvement in
monitoring and oversight by responsible authorities. Industry itself, through
the formation of Canada’s Oil Sands Innovation Alliance (COSIA), has taken
its own major initiative to improve environmental practices and performance
in a cooperative and coordinated manner. The founding of AEMERA and the
JOSM and the development of the appropriate relationships between these
programs and the new Alberta Energy Regulator with regard to such issues
as compliance monitoring provide hope that an appropriate level of environmental management can be achieved for the immediate future. However,
concerns remain about long-term issues.
Habitat disruption and the consequent decline or loss of plant and animal
species is a major concern. This is caused not just by the development of
open-pit mines, but also by the forest clearance required for in situ projects,
roads, seismic surveys, processing plants and all other infrastructure and
human activity in general.
13
The Alberta Biodiversity Monitoring Initiative has developed techniques for systematically evaluating the health of some 2,000 species across the province. The program commenced in 2003 and provides regular reports for scientists, landowners and resource managers. An index—termed the Intactness
Index—is calculated for each monitoring station and each species and ranges from 100 per cent for undisturbed environments to zero per cent for mine
sites. In ABMI’s 2014 update, the program reports that of 425 species in the oilsands region the Biodiversity Intactness Index is, on average, 88 per cent.
BIODIVERSITY INTACTNESS IN THE OILSANDS
80 %
88 %
FOR
NATIVE BIRDS
91 %
90 %
FOR
WINTER-ACTIVE MAMMALS
FOR
NATIVE VASCULAR PLANTS
91 %
FOR
ARMOURED MITES
FOR
MOSSES & LIVERWORTS
SOURCE: ALBERTA BIODIVERSITY MONITORING INITIATIVE
14
sector to keep companies and governments focused on the continuation
and completion of the necessary environmental programs.
As noted by fellow AEMP panel member Ron Wallace, all the necessary
components of a management program were in place in the 1990s in the
form of the Northern River Basins Study. Unfortunately, for various reasons
this successful, cooperative and integrated basin management approach—
which explicitly recognized the inclusion of TEK in program design and
implementation—was allowed to devolve into poorly coordinated multistakeholder monitoring and governance structures. Current indicators are
that this will not be allowed to happen again.
Deployment of the JOSM by the federal and Alberta governments and
the establishment of AEMERA and COSIA are reflective of the current
mindset in industry and regulators towards more conscientious environmental stewardship and retention of social licence in hydrocarbon extraction from oilsands.
ACKNOWlEDgmENtS
I thank my former colleagues on the federal advisory panel and on AEMP
for the stimulating discussions that formed the basis for our joint recommendations. I would particularly like to thank Ron Wallace, David Schindler
and Kevin Percy for their contributions to the special issue of Geoscience
Canada. Fred Wrona read an earlier draft of this paper and made many
useful comments.
Andrew Miall completed his Ph.D. at the University of Ottawa in 1969 and
spent three years in Calgary’s oilpatch before joining the Geological Survey of
Canada to work on regional Arctic Island studies. In 1979, he took a position
as professor of geology at the University of Toronto and has been there for
35 years; he currently holds the Gordon Stollery Chair in Basin Analysis and
Petroleum Geology. He became a Fellow of the Royal Society of Canada in
1995. In 2012, Andrew was inducted as an Honorary Member of the Canadian
Society of Petroleum Geologists and in 2014 was awarded the Pettijohn Medal
by the Society for Sedimentary Geology and the Logan Medal by the Geological
Association of Canada for distinguished achievement in earth science.
ILLUSTRATIONS: PAIGE PENNIFOLD
The report stated that “Woodland Caribou has the highest public profile
of all the species at risk; there are seven caribou populations whose ranges
overlap with the [oilsands region]. The abundance of Woodland Caribou
declined in five of the ranges between 1991 and 2011.”
These values are likely to decrease as development proceeds, and some
steps might need to be taken to limit or space out development in the interest of the long-term ecological health of the oilsands region.
Open-pit mines generate significant land disturbance. Restoration of
the boreal forest is to be carried out wherever possible, and the long-term
plan also includes the creation of artificial water bodies called end-pit lakes.
According to Schindler, “These consist of leaving a company’s final mine pit
only partially refilled with overburden, instead allowing it to be left partially
filled with tailings, over which a 5 meter layer of clean river water is then
placed as a ‘cap.’ It is believed that bacteria will eventually detoxify the pollutants in the tailings, that there will be little or no mixing of tailings with
overlying water, and that by the time water levels rise high enough to discharge into the Athabasca River, outflow water from these ‘lakes’ will meet
provincial water quality guidelines.”
Schindler expressed skepticism about the viability of this plan, pointing out that there will be release of gases from decomposition of the
contaminants and that these will necessarily escape into the atmosphere.
There are also concerns about the possible contamination of groundwater over the long term and questions about the possible impact of the
buried pollutants on soils, plants and animal life. It is expected that 100
years might be required for completion of the restoration process. The
problem is that there is no experience to draw on with regard to these
very long-term issues.
The large-scale disposal of process-affected water in deep saline groundwater systems is also a possible concern over the long term. Could such
waters displace existing water bodies, causing saline groundwater or the
process-affected water itself to seep gradually to the surface, contaminating
these surface waters?
In the future, as the era of exploitation of the oilsands draws to a close,
as revenues decrease while environmental costs continue, much will depend
on the willingness and ability of citizens, the public sector and the private
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15
PROJECT UPDATE
Location
Dover lease
Owner
N-Solv Corporation—a venture
of Hatch, Enbridge and Nenniger
Inc., with funding from Sustainable
Technology Development Canada and
the Climate Change and Emissions
Management Corporation
N-Solv pilot
A conversation with Joseph Kuhach,
chief executive officer, N-Solv Corporation
PRODUCTION
Over 25,000 barrels since
start-up in spring 2014
By Deborah Jaremko, CHOA Journal editor
We’re very pleased with what we’re seeing.
We’ve had a safe operation throughout the life
of the project, [and] we’re seeing validation of
the lab work and the experiments that were
done in the past. We’ve now produced over
25,000 barrels of oil, and I would say we’ve considerably de-risked the project for going to the
commercial stage.
What would you say are some of the
key lessons that have been learned?
16
The technology looks very promising when you
look at the lab data, but when you take anything to the field there is always the question of
whether it is going to work when you actually
put it into a non-ideal environment. So validating
all of the learnings that were developed during
the pre-pilot phase is really the key thing that
we’ve learned to this point.
We’ve been able to successfully start up with
no water involved, and I think that is a first in the
industry. We’ve demonstrated that we can operate
the facility with essentially no upsets and no interruptions; it is a very robust process. I think some
of the surprises that we’ve seen have actually
been to the positive side. For example, the level of
upgrading that we are seeing in our product oil is
a bit better than what we had anticipated.
What would you say are stakeholder
benefits of this project?
There are huge benefits I think when you move
toward solvents and away from SAGD. First, the
technology uses no water to exploit the resource,
unlike SAGD.
If you look at a SAGD plot plan and the equipment required, you have a huge amount of space
PHOTOs: N-Solv
How would you describe recent
performance at the N-Solv pilot?
Project update
that is necessary because of all of the water
handling, cleaning up the water and creating
the steam and injecting it and that whole recycle
loop that isn’t part of our equation at all; N-Solv
is just a gas plant. We have a much lower cost of
entry from a capital standpoint, and that takes a
lot of risk out of performance as well.
One of the big challenges in the industry
right now is this continuous upward pressure on
pricing regardless of what oil prices seem to be
doing. Whether they are flat or even declining,
that upward pressure on costs just isn’t going
away. With a process like ours, we can really dial
down the requirement to get into a project on
the upfront side.
From an operating standpoint, it is very efficient. We’re going from 200–220 degrees Celsius
SAGD-type of operation to 40–60 degrees
Celsius so you don’t have that energy requirement and therefore we have a dramatic reduction
in greenhouse gases.
You don’t need as much diluent because the
oil comes out of the ground upgraded, [which
reduces] diluent consumption and effectively
frees up pipeline capacity.
We’re leaving all of the nasties behind in the
reservoir and the refiners no longer have to
deal with that, so the product becomes a lot
more valuable and transportation is a lot easier.
There are lots of bells that are rung with this
technology.
Overall it is just a more environmentally friendly
process. With all of the focus on social licence
in the industry, when you look broadly from a
global standpoint, the oilsands is “dirty oil,” and
I think this technology really provides an opportunity to change that view. Essentially you’re
creating a clean oil, a clean way to produce the
oil—no water consumption, smaller footprint,
much lower greenhouse gas emissions and a
lower carbon product.
What environmental achievements
have been made at this project?
We plan to continue to operate the pilot for a
period of time. We’ve got a number of partners
Can you talk about solvent recovery?
The process is very forgiving economically. The
operating costs are so low we can actually afford
to lose more solvent than we think we’re going to
end up with. We’ve tried to be very conservative
and say 20 per cent is what we’re going to leave
behind. I think we’re on the path to see that, but
frankly it doesn’t matter if it is 20 or more.
It’s obviously reservoir-dependent—it depends
on a number of things—but if we take what we’d
call a typical reservoir in the oilsands, we’re quite
economic, and I’m talking 15–20 per cent rate of
returns down at $40/bbl.
One of the benefits of this technology is being
robust economically down at those low oil prices.
It can really remove the oilsands from being that
marginal barrel. If you can remove that from the
equation you can create a lot more stability in the
industry, and that would be good for everybody.
What are the future development plans?
that we have signed up and we’re pleased with
advances in discussions that we are making
towards commercialization with them.
We’re also looking to commercialize
through other avenues and new potential partners and investors. We think we’ve answered
enough questions that we’re ready to go to
a commercial project. One of the nice things
about this technology is you can go commercial at small scales, like 5,000 bbls/d so we’re
in the process of looking for JV partners to
advance that as well as potentially licensing
with the right arrangement.
[Within] three to five years, I would expect us
to have a plant up and running and producing
commercial levels.
What makes N-Solv unique?
It’s a unique process in that it is a low-pressure
process and consumes no water. I think it is fair
to say that our operating pressure is lower than
anything that has been done. The AER has had
a big focus on shallow SAGD projects; there is
a lot of scrutiny around those and [the AER is]
really putting the clamps down because there
are a lot of concerns. Because we are such a
low-pressure operation, caprock containment
isn’t really a concern.
I think in total we have the ability to really
enable stability in the oilsands in an econom
ical and environmentally friendly way. That is
something that we really haven’t seen with SAGD
or with any of the incremental improvements
around SAGD to this point.
17
THANK YOU 2014 CHOA SPONSORS
DIAMOND SPONSORS
GOLD SPONSORS
ANNUAL CORPORATE SPONSORSHIP
Sponsoring the Canadian Heavy
Oil Association (CHOA) provides a
significant opportunity to support
a multidisciplinary, volunteerbased, not-for-profit association
focused on heavy oil and oilsands
projects and development. The
association has a current 2015
membership exceeding 2,000
professionals employed in heavy
oil exploration and production,
service and supply, government
and consulting.
Corporate sponsors reach the
CHOA membership through:
• Recognition as a Corporate
Sponsor at CHOA technical
events including Technical
Luncheons and Beer & Chat
functions in Calgary and
Edmonton.
• Recognition as a Corporate
Sponsor at the Annual General
Meeting.
• Logo placement and
recognition on the CHOA
website, including a “hotlink” to
sponsor website.
• Logo placement and
acknowledgement in the
CHOA Journal.
• Recognition at the annual
sponsor appreciation event.
For more information or to
express interest, please contact
jhone@choa.ab.ca.
CHOA BOARD OF DIRECTORS
2014-16
SILVER SPONSORS
Past President
Kym Fawcett
Enerplus Corporation
403-693-5054
Secretary
Bruce Gray
Access Pipeline Inc.
403-691-5791
Director
Scott Rempel
Wood Group Mustang
403-537-8811
President
Gail Powley
Willowglen Systems
780-465-1530
Director
Rodger Bernar
Husky Energy Inc.
403-750-4958
Vice-President
Stephen Arseniuk
Laricina Energy Ltd.
403-718-8821
Director
Simon Davies
Canadian Natural
Resources Limited
403-386-5198
Director
Bill Whitelaw
JuneWarren-Nickle’s
Energy Group
403-209-3500
Treasurer
Pushkar Rao
TG Engineering Inc.
403-290-5415
Director
Nancy Wu
Government of Alberta
780-643-1660
Director
Martin McDonald
SAIT Polytechnic
403-210-4596
BRONZE SPONSORS
DISCLAIMER: The purpose of the Journal of the CHOA is to publicize the association’s
activities and provide an appropriate technical, educational and social forum for those
employed in or associated with the heavy oil and oilsands industries. Association
publications shall contain no judgmental remarks or opinions as to the technical
competence, personal character or motivations of any individual, company or group.
Further, technical remarks, opinions and conclusions expressed in articles published
in the Journal of the CHOA are those of the author and are not officially endorsed by
the CHOA unless otherwise noted. Material contained in the Journal of the CHOA is
intended for informational use only.
18
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People Oriented…Project Driven™

January 2015 Edition - Canadian Heavy Oil Association

Transcription

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