IOL-051

The Potential For CO2 Reductions From
Additional Energy Efficiency
Esso Resources Canada Ltd.
May 1991

By: L F Mannix
RGAuld

 1

There i~ gro~ing concern ~ha~increasing atmospheric concentrations of greenhouse
ga~es, inclu~mg Carbon D1ox1de(CO2), may be leading to potential global warming.
This report _d1~cusses E~so Resources Canada Ltd's (ERCL's) potential for reductions
in CO~ em1ss1onsfrom increased energy efficiency in oil and gas production
operations.
Oil and gas production for Esso is geographically distributed across Alberta
Saskatchewan, British Columbia, and the North West Territories. Within this '
geographic area, a wid~ly varying infrastructure of support facilities is required, a
direct result of production from a number of different reservoirs, each with individual
energy requirements. Natural gas and electricity are used in the production process
to supply energy necessary to lift fluids, and condition or treat them prior to sale. In
1989 ERCL emitted approximately 4.41 M tonnes of CO2 from .its operations, with an
additional 1.8 2 M tonnes of CO2 associated with electrical energy use by ERCL.
Esso Resources has already achieved significant energy improvements in it's
operations in the past 2 decades. Energy efficiency improvements implemented after
1975,are estimated to have reduced ERCL's 1989 energy useage by over 20%
relativeto 1972 standards. Without these energy conservation measures, the
cumulative incremental CO2 emissions between 1972 and 1989 would have been an
additional 7000 kt, with yearly emissions in 1989 close to an additional 1700 kVyr.
The potential for further energy efficiency related CO2 redu~ions_ha~ been estimated
in this study for the years 1990 to 2005. Results are summarized in Figure 1 and
Table 1 below, and indicate the degree of CO2 re~uction associated with two different
levels of additional energy efficiency implementation:
* Implementation of opportunities that meet a simple payback of 5 years. ~CurveC)
These efficiency measures have economics that exceed the cost of capital.
* Implementation of all technically feasible opportunities. (Curve D)

1 Ern·
1 .

2

.
bY others (eg Syncrude).
ss1onsexclude working o/oin operations
Assumesaverage electrical CO2 emissions of 0.983 kt/GWhr

 2

·-·-·-·-·
·-·---

10000
9000

kt I yr
CO2

8000

-·- Base

7000

-0- Curve C

-•· Curve D

6000
5000
4000
1997

1993

1989

2005

2001

Figure 1 ERCL Projected Yearly CO2 Production

Reduction
Description

Percentage

(%2005)
Curve C
Curve C to D
Total (Curve D)

* Average

6.5
7.5
14.0

~

kt/yr

630
730
1360

Capital
M$

Iner. Op.
M$/yr

Net Op.*
M$/yr

20
425
445

2.5
14.5
17.0

>4
17

Years

<5

>5

N/A

net operating savings • Fuel + Elect cost savings - Incremental operating costs

The baseline increase shown for CO2 emissions is consistent with Alberta Energy
projedions of 50 + o/ofor the Alberta oil and gas produdion industry 3 and with
ERCL's significant share of Alberta's crude bitumen and oil sands mining production.
This baseline curve is highly sensitive to energy prices, and a wide range of baseline
CO2 emissions is possible if higher or lower prices than those assumed were to occur.
The potential range of baseline CO2 emissions arising from alternate energy prices
may up to +I- 30% of emissions estimated.
From this baseline curve, full implementation of energy efficiency measures with less
than a 5 year simple payback (Curve C), could reduce ERCL CO2 emissions by 6.5%
relative to year 2005. These measures would cost 20 M$ (1990 $) capital, with an
extra 2.5 M$/yr (1990 $) of other incremental operating costs to allow fuel and
eledrical cost ·savings to be realized. Significant energy efficiency opportunities
under Curve C are:
3

A~be.rtaDepartment of Energy. Energy Efficiency Branch. Energy Related Carbon Dioxide
Emissions In Alberta 1988 to 2005, May 1990. Table 1.

 3
- Opera io s a d maintenance improvements from increased monitoring activities
- I prove e s to bu er controls
- I proved eat integration in the crude bitumen production sector
CO~ red ction. potential shown between Curves C to D represents other technically
ea b red <?li
on measures with simple paybacks greater than 5 years. These
easure.s . h1ch are not s~~n to be economic, have the potential to further reduce
CO2 em1~ ,o~s by an add1t1onal 7.5 °/o in year 2005. Significant energy efficiency
oppo un 1es inc luded under Curve C to D are:
- Coge nerati on of steam and power in crude bitumen and gas plants
- Power ge nerat ion from flared gas
- Other waste heat recovery schemes
Curve .c to D opportunities require very high capital investments and incremental
operating costs. These opportunities also reflect the difficulty in retrofit of new
technology in existing facilities. Besides this high cost, the major barriers to
implementat ion of most of these opportunities are:
- Reliability
- Current cost sharing arrangements with electric utilities
- Techno logy limitations
When compared with other projections by the Alberta Department of Energy 4 for the
potential of energy efficiency related CO2 improvements for the oil and gas
production sector, this study shows a significantly lower total reduction potential of
14°/ovs 29°/o. To the extent that the results of this study may be representative of other
oil and gas companies, and recognizing that only about one half of these
opportunities are economic, this large difference shows that governments need to be
cautious when it comes to expectations that energy efficiency can significantly
reduce greenhouse gas emissions in the oil and gas production sector.
The challenge for energy efficiency technology development is to widen the scope of
influence that additional energy efficiency measures might have relative to total E RCL
CO2 emissions. This effort will require particular focus on finding more innovative
and cost effective technologies for reducing energy intensity in the production and
processing of bitumen.
For energy efficiency reduction opportunities ident~fi.edas ha~ing the potential to be
economically feasible, it is recommended that add1t1onaldetailed engineering studies
be conducted consistent with the intent to implement these opportunities where
possible. For operating and maintenance related improvements, a renewed focus
within operating groups on energy e~iciency is recom~ended to capt~re economic
opportunities. However, CO2 reductions from economic energy eff1c1ency
improvements, are unlikely to stabilize projected ERCL CO2 emissions at 1990 levels .

 4

IABlE Of CONTENTS
Vo lume

1

EXECUTIVE SUMMARY

1

ACKNOWLEDGEMENTS

6

INTRODUCTION

6

DISCUSSION OF RESULTS

7

Historical Energy Efficiency

7

Forecasted Energy Requirements and Baseline CO2 Emissions

10

Opportunities to Reduce CO2
- Summary of Reduction Potential
- Comparison to Other Energy Efficiency Potential Estimates
- Barriers
- Energy Efficiency Potential vs Potential Supply I Demand
Response
- Technology Development Needs
- Reduction Progress Tracking System

12

CONCLUSIONS & RECOMMENDATIONS

20

GLOSSARY I ABBRREVIATIONS

21

APPENDIX 1: METHODOLOGY
Energy Consumption
- Calculation Procedures: Historical Energy Consumption
- Calculation Procedures: Energy Consumption Without Energy
Conservation Initiatives
- Baseline CO2 Calculations: Future Energy Requirements
- Calculation Procedures on Impact of Acquisitions

22

Future Reduction Potential
- Description of Generic Energy Efficiency Items
- Site Specific Items
- Operations and Maintenance Reduction Potential

29

 5

Volume

2

APPENDIX

Page#

2: ERCL DATA

Specific Assumptions - Generic Energy Efficiency Items

35

Specific Assumptions - Oil Sands Efficiency Items

39

Technology Development Needs - ERCL

42

Computer Spreadsheets Used

47

 6

· · d'vidua
ls who co ntributed to the
I
ffc1 iency potential estimates ·
The authors would like to thank the following in
•
development of the generic and oil sands energy e
Robbert Hoffmann
Paul Slobodnik
Rudolf Stromer
Michele Mitchinson

nfNlJRODUCJnOfNJ
The enhanced greenhouse effect has received much attention in ~he las~ several
years in terms of its possible implications on potential global warming . Since the
industrial revolution atmospheric concentrations of these greenhouse gases have
been steadily increasing with growth of the predominant anthropogen ic greenhouse
gas, CO2, attributed to increased combustion of fossil fuels and deforesta tion.
In March of 1990 Imperial Oil Limited issued a position paper outlin ing
recommendations to Governments on "Potential Global Warming". To furt her
understand the implications of potential global warming, a seven point work program
was undertaken within the company. This reports completes the ERCL com mitment for
item 2, namely:
Determination of the technical and economic potential for addit ional energy
efficiency opportunities in all of its operations, with and eye to reducing carbon
dioxide emissions.
The scope of potential energy efficiency improvements is intended to include the
reduction potential associated with both fuel and electricity from all fac ilities and fields
where Esso is the operator. Reduction potential associated with ERCL working
interest in prod~ion operations by ~thers (eg Syncrude Canada Ltd.) and with
contractor operations has not been included.
'
The accuracyof results is intended to be of scoping quality only .

 7

Historical Energy Efficiency
To estimate the potential for additional energy effici ency in upst ream facilitie s
operated by ERCL, it is important to understand that a number of initiatives have
already been completed . Esso Resources Canada Limited started a formal energy
conservation program in 1975. This program was implem ented t hrough the
appointment of "Energy Coordinators" in each operating are a wh o had the
responsibility to monitor energy consumption and to identify areas for improvement.
This program was particularly successful in tuning the burners in direct fired heaters
and power boilers. It was also effective in understanding our electrical power usage,
ensuring that power factor corrections were made, and optimizing electrica l power
contracts. A number of fuel meters were also installed at that time to monito r fuel
consumption.
Since then energy conservation initiatives have been sporadic. Between 1979 and
1980 some emphasis was put on energy conservation in the gas processing plants.
In particular, the glycol dehydration units, amine sweetening units, direct fired heaters
and burners, and flare stack temperatures were optimized. In this program , the largest
gain was made in burner optimization which showed a reduction of 5% of the fuel
requirement simply by monitoring and adjusting the burners . In later years, little
emphasis has been placed on energy conservation although burner surveillance
programs and compressor optimization programs have continued . In the conventional
oil and gas sector, the installation of updated instrumentation, particularly distribut ed
control systems, and wellhead managers, has provided better monitoring , control ,
and optimization of the processes. In the crude bitumen sector, which is more energy
intensive than either conventional oil production or natural gas proce ssing , much
more attention has been paid to energy efficiency . Over the year s improvem ents
have been made to burner controls, steam generator design, and steam utilization .
The energy utilized in the upstream facilities operated by Esso Resourc es between
1972 and 1989 is shown in Figure 2, in terms of the energy required as a percentage
of the energy in the product. 5 There is little or no data on the actual fuel and
electrical consumption In the conventional oil and gas sector except for 1989 .
Consequently, the data shown In Figure 2 has been recreated from annual production
data, current energy consumption, and energy consumption data known for 1979 and
1975.

5 Include ERCLestimatedelectricalend use energy requirements.

 8
40
35
30
%of
Energy In
Product
Used to
Produce

25
20

."·--·
/" .\
/ ..........
.
.
·-·~· \ .....__.,.,.
/
·-·-·

."

..........

15
10
5
0
1976

1972

I•

OIL

1980

II

GIG

1988

1984

··- BITUMEN

-0-

TOTAi.

Figure 2 ERCL Energy Utilized for Production
From Figure 2 it can been seen that there has been an overall increase in energy
utilization from' 4 to 7.5 % of the energy produced over the 18 year period shown.
Examining the energy utilization on a sector basis, indicates that the energy required
to produce conventional oil has increased primarily due to the larger volumes of water
that must be handled and processed as the reservoirs are depleted. The contribution
of the crude bitumen production sector to the overall energy utilization is significant;
particularly as the volume of crude bitumen has been increasing. The cyclic nature of
the energy requirement in this sector corresponds to the intensive reservoir steaming
that occurs as new production phases are brought on stream. The downward trend in
energy required in the production of crude bitumen reflects the effect of the energy
efficiency initiatives, production f~om higher quality oil sands, and the increased unit
efficiency of a large ~cale operat10~. Lower gas sector energy utilization trends from
1986 to 1989 reflect improvements m gas plant capacity utilization and acquisitions of
reserves with lower energy requirements for production.
~he. ~isto~cal fuel energy utilization for upst~eam o~erations (Figure 3) shows a
s1gnif1~nt !~crease over t~e past 18 years. Th_1slarge increase is directly attributable
to the s1gnif1cantchange m scale of the operations as the volumes of crude bitumen,
gas, and conventio~al oil ~reduction have increased due to the implementation of the
Cold ~ke Produ<:tion ProJects, the Norman Wells Project, and from acquisitions of
producing properties.

 9

P J /yr

100
90
80
70
60
50
40
30
20
10
0
1972

./

./

I

•

•

/;

•

1976

1980

1984

1988

-•- Fuel Energy (PJ/yr) Without Energy Conservation
-0,

Fuel Energy (PJ/yr) With Energy Conservation

Figure 3 Effect of Historical Fuel Energy Conservation

Measures

Also shown on Figure 3 is the total fuel energy requirement for upstream operations
that would have been expected if none of the energy efficiency initiatives had been
implemented. The implementation of these initiatives which included such items as;
increased insulation levels, improved combustion controls in boilers and heaters, and
improved automation and control, has been estimated to improve the total fuel
efficiency for 1989 relative to 1972 by over 20 %. Without these energy conservation
measures, it is estimated that incremental fuel related CO2 emissions in 1989 would
be about 1000 kt/yr. As this study includes the potential for CO2 reductions from
reduced electrical power useage, a similar energy efficiency improvement applied to
historical electrical energy use results in a total cumulative incremental fuel and
electrical CO2 related savings between 1972 and 1989 of 7000 kt, with yearly
emissions savings in 1989 close to 1700 kt/yr.
The historical trend of estimated yearly total CO2 emissions, including CO2 emissions
associated with electrical power consumption, is shown in Figure 4. As the overall
energy utilization has increased, clearly the related CO2 emissions have increased .
The large CO2 increases from 1985 to 1989 reflect a significant volume increase in
the production of crude bitumen. Other CO2 increases between 1978 and 1989 are
related to acquisitions associated with increased gas production and between 1988
and 1989 the acquisition of Texaco Canada Resources Limited. Since Esso
Resources Canada Limited produces close to 70% of Alberta's total crude bitumen, a
very energy intensive sector, and since the energy requirements in the conventional
oil and gas sectors are increasing due to more production from depleting reservoirs,
(ie increased water production and declining reservoir pressures,) it is expected that
the energy requirements, and hence, CO2 emissions will continue to rise.

 10
7000
6000
5000
kt / yr

4000
3000
2000
1000
0
1976

1972

1984

1988

.OIL

•

BITUMEN

0

ACQUISITIONSII TOTAL(BEFOREACQUISITIONS)

Figure 4 ERCL Yearly CO2 Production

Forecasted Energy Efficiency and Baseline CO2 Emissions
To estimate the potential for CO2 reductions a forecast of future baseline CO2
emissions was developed from a combination of energy needs on a per m3 of
production basis, and from forecasted production volumes.
Future baseline total energy needs on a sector basis have been estimated up to the
year 2005 as shown in Figure 5, in terms of the energy utilized for product ion as a
percentage of the energy in the product. 6 This baseline energy requiremen t
assumes current levels of energy efficiency implementation with no allowa nce
(except crude bitumen) for future technology improvements which might significant
lower energy requirements. For new facilities, current state of the art tech nology is
assumed.
Total ERCL energy utilization for production is anticipated to continue to remain
relatively flat as slight ~nergy efficiency improvements in crude bitume n production
are projected from continued development of existing high quality oil sands . This
efficiency gai~ negates th~ eff~cts _ofincreased gas compression needs for the gas
water oil ratios m ~nventional oil production . Incre ases in late~
sector, and h1ghe_r
years f~r crude b1!~menreflect production from poorer qual ity oil sa nds and declining
reservoir product1v1ty.

6

IncludesERCLestimatedelectricalend use energyrequirements.

 11

25

................
' ·-·-'
.
1
·-·,,.~
·-·
•L

20

%Of

........

.......

•

.........

.........
.........

.

15

OIL

mlG\5

Energy In
Product
Used to
Produce 1 O

·•-B ITUMEN
0-TOTAL
,

5

I

0

1989

1993

!!:.·,:
....
. I:':.:I'.

ii:::
i I

,i·....
,i

~WI) m;;;a.i
} ~,a;,.ii-,;;;a,

1997

.

2001

ill

:!....
...
'!·.,.1,

2005

Figure 5 Projected Energy Utilized for Production

Given projections of relatively flat total ERCL future energy utilization, future CO2
emissions are then closely tied to production volumes. Although a summary of
anticipated future production has not been provided, the following general
assumptions were used to establish ERCL future production profiles that are
consistent with Energy Mines and Resources' (EMR) 2020 7 vision forecasts.
• Average oil prices remain relatively flat with only minor real price growth.
• Future production volumes for conventional oil are assumed to continue to
decline, with higher cost secondary or tertiary recovery schemes remaining
uneconomic.
• Natural gas production is assumed to increase from continued development
of proven reserves including those in frontier areas.
• Continued divestment or shut in of uneconomic properties will occur as
current fields continue to mature.
• The development of oil sands crude bitumen and mining projects will be
required to assist in fulfilling Canadian and world wide energy needs. As
such, significant production growth for crude bitumen is assumed to contin ue,
with implementation of state of the art lower cost insitu thermal and other
recovery technology.

7 EnergyMines and ResourcesCanada. 2020 vision, Canada'sLong Term Energy Outlook, a
Working Paper, 1989 issue.

 -- 12

Opportunitiesto ReduceCO2
Estimated Reduction Potential

.
as process ing plants with in the
No significant expansion ?r construction of n:~ gAs such, future ener?Y efficiency
Western sedimentary basin ha~ been ~~~~~al ~rude bitumen produ ction and frontier
improvements, with the exception of a I t,o ft or equipment upgrade s in existing
gas development, are largely related to re ro 1
facilities.
· 1f both retrofit of existing facil ities and for
and costs associated ·
To estimate future improvement potent.,~ or .
with
new facilities, estimates for energy eff1c1encyimprovements
the following 3 areas were developed:
• Application of generic opportunities for conventio.nal oil and gas o~e~ations
• Application of site specific opportunities with particular focus on ex isting
crude bitumen operations
• An estimate of continued operations and maintenance improvements
The economic potential of each of these opportunities was caJculated by simple
payout based on constant 1990$. This is the number of years required before initial
investment and additional (or other incremental) operating cost is offset by savings
from fuel or electricity reductions. For economic calculations the follow ing was
assumed for both retrofit and new facilities:
* Project life 15 years
* lncren:,~ntalelectricity cost of 0.02$ I kw hr. (For cogeneration incremental

electricity saved or generated was estimated at 0.045$ / kw hr)
* Incremental fuel gas cost of $70.60 I s m3.
To diff~rentiate those e~ergy efficiency opportunities that were thou ht to have
9 t f
or
potential for cost of capital recovery, opportunities with a simpl
less were grouped together. Opportunities with r
e payo~ o 5 years
represent the maximum potential for energy effici~n~ayter~an 5 year simpl e payout
economically attractive to the private sector.
an were not ass umed to be
A summary of the overall potential within Esso R
increased energy efficiency is shown in Fi
esources for CO2 reduction from
CO2 reduction associated with these 2 le~~~e bdedl~~
and indicates the degree of
a 1t1onalenergy eff iciency
implementation:

o1

• Implementation of opportunities that meet a ·
.
simple payback of 5 ye ars. (Curve C)
•
Implementation of all technically feasible opportunities .
(Curv e D)

 13

·-·--·--·-·-·-·

10000
9000

kt I yr
CO2

8000

-· - Base

7000

-o- Curve C
-• · Curve D

6000
5000
4000
1989

1993

1997

2001

2005

Figure 6 ERCL Projected Yearly CO2 Production
Increases in ERCL total CO2 emissions (base case 1989 to 2005), assume current
levels of energy efficiency implementation. This baseline total increase of 50°/o is
consistent with Alberta Energy projections of 50 + o/ofor the Alberta oil and gas
production industry, and with ERCL's significant share of Alberta's crude bitumen and
oil sands mining production.
Reductions in CO2 emissions from the baseline curve as shown by Curves C and D,
reflect a phased in implementation of identified efficiency measures. Retrofit
efficiency improvement measures with less than a 5 year simple payout were
assumed to require 10 years for 100 % implementation. For new facilities constructe d
between 1990 and 2005, energy efficiency measures with less than a 5 year simple
payout were assumed to be incorporated into these facilities as they were
constructed.
For retrofit opportunities with greater than a 5 year payout, a 15 year implementatio n
period was assumed for 100% implementation in existing facilities. For new fac ilities
constructed between 1991 and 2005, opportunities with greater than a 5 year simple
payout were also assumed to be included with these facilities as they were
constructed.
With reference to Figure 6, results for the year 2005 are summarized in tabular form
below:

 14

Resources
Canada Limit~
ear200sEsso
Table2 Prolei:t1on
for the Y
·
811Tech,Eefconom
1c
(B
1
O
(B - C)

- )

Potential CO2emissions in 2005
Projected 2005 Operation (k tonnes/yr)
- Without additional energy efficiency
Improvements (Figure 8, Curve B)
- With additional energy efficiency
improvements

9700

9700

9070

8340

630

1360

- Decrease from business as usual
(kt/year)
0

/o6.5

- % decrease

0

/o14.0

EnergyConsumption
(fuel GasandEnduse Electacity)
Projected 2005 Operation
( Petajou les/yr)
- Without additional energy efficiency
improvements (Figure 8, Base)

133

133

- With additional energy efficiency
improvements

124

118

- Decrease from business as usual
(PJ/year)

9

16

- o/odecrease

o/06.S

%12.0

Costs l1990$'s)Io Achieve
saving~
- Additional Capital

(M$)

- Incremental Op. Cost (M$/yr)*
- Range of Capital Cost per tonne of
CO2 saved (1990$Nyr)

20

445

2.5

17.0

20 - 100

100 - 10000

* Excludes fuel and electrical operatin
.
savings would include fuel and elect~c~ost savings. Net ope rating cost . d
1
to payout capital.
Y and are of course (-)ve as require

 15

Full implementation of energy efficiency measures with less than a 5 yea r simple
payback (Curve C) could reduce ERCL CO2 emission by 6.5°/o relative to 2005 and
would cost 20 M$ (1990) capital. An extra 2.5 M$/yr (1990) of other incremental
operating costs is required to allow fuel and electrical cost savings to be realized. Net
ERCL operat ing costs are fuel and electrical savings arising from reduced energy
consumption, minus this other incremental operating cost, and are negative for all
items that achieve simple payback . All new facilities associated with produc tion
growth (ie non retrofit), constructed between 1991 and 2005 are assumed to include
the energy efficiency measures associated with Curve C at little or no additiona l cost.
Significant energy efficiency opportunities included under curve C are :
- Operations and maintenance improvements, (resulting from
increased monitoring activities.)
- Improvements to burner controls
- Improved heat integration in the crude bitumen sector.
To achieve the projected operating and maintenance improvements, additional focus
is required in all operating areas. This will require at least initially, the appointment of
operating personnel dedicated to energy efficiency. The estimated 2.5 M$/yr
additional operating cost includes an estimate of this manpower cost.
Full implementation of energy efficiency measures with greater than a 5 year simple
payback (Curve C to D) could reduce ERCL CO2 emissions by a further 7.5°/o relative
to year 2005 and would cost 425 M$ (1990) capital with an extra 14.5 M$/yr (1990)
other incremental operating cost. Those opportunities listed between Curves C to D
represent other technically feasible reduction measures up to the estimated maximum
improvement potential. Based on the fuel gas and electricity costs assumed, Curve C
to D includes several minor opportunities and one major opportunity (elimination of
flare gas makeup for sour gas flaring), that do not recover their projected costs (i.e.
don't meet a simple payback criteria). The more significant efficiency measures for
Curve C to D that do meet the simple payback criteria include:
- Cogeneration of steam and power in crude bitumen and gas plants
- Power generation from flared gas.
- Other waste heat recovery schemes
Approximately 20% of the projected CO2 reductions associated with Curve C to
related to potential implementation of these measures in new facilities.
A detailed listing of all energy efficiency measures considered is included in the

Append ix.

o are

 16
Eff ·ency Reduction Potential
Comparison to Other Estimates of Energy
ici
.
b rta Department of Energy for t.he potential
When compared with projections .bythe Al :nts tor the oil and gas pro duct1on sector,
otential of 14o/ovs 29 0Yo.The major
of energy efficiency related CO2 1mprovem.
this study shows a significant.lyl~wer reductif;epassumptions for cogeneration in the
difference in reduction potential 1srel~teh~tf he oil and gas sector.
gas processing and oil sands areas wit in
.
b representative of other other oil and
To the extent that the results of this study ma~ tegovernments need to be cautious
gas companies, this large difference shows t ff~ . ncy can significantly reduce
when it comes to expectations tha~energy e ic,e . sector
greenhouse gas emissions in the 011and gas production
·

Barriers
It should be recognized that the degree to which actual implementation of energy
efficiency measures will occur, is influenced by many. other fact~rs than the energ~
efficiency improvement alone, eg manpower and capital const~amts. Furthermore,
most of the projects identified as having greater than a 5 year simple payback are
unlikely to be implemented unless technology development can significantly reduce
the costs of implementation. As such 100 o/oimplementation of all energy efficiency
measures is very unlikely.
The major barrier to faster implementation of those opportunities included under Curve
C is their ability to compete with other economic opportunities for scarce capital
resources.
Alt~o~gh Curve C0 to. D opportunities h~ve the potential to further reduce CO2
~m1ss1onsby 7.5 ~ m 2005, they require very high capital investment and
incremental ope~atm~~st. T~~~e opportunities also reflect the difficulty in retrofit of
~ew technol~gy m ex,stmg fac1ht1es.Besides this high cost the major barriers to
1mpl~m~ntat1on
of most of these opportunities for both retrofit and
f ·1·t
apphcat,ons are:
new ac11Y
- Reliability
.
- Current cost sharing arrangements "th
- Technology limitations
wi e 1ectnc utilities

c

A significant portion of the reduction Potential fo
electric power savings from cogeneration or el r . urve C to D is associated with
allow these projects to proceed, a cogenera iectnc 9ener~tion from flare gas. To..
companies and oil and gas producers needs \~nbpodhcysuitable to both electric utility
e eveloped.
.
For the opportunities included under Curve t
0
for improved economics as a result of syne . D, there appear to be limited potential
facilities. One exception to this appears to ~es associated with construction of new
incorporation in original designs mayallow :~ste heat recovery measures, where
8
become more economically feasible.
ltional waste heat recovery to

c

 17
Energy Efficiency Potential vs Potential Supply I Demand Response
Given current assumptions on growth and energy utilization, it is clear that energy
efficiency improvements will not be able to stabilize projected ERCL CO2 emissions at
1990 levels. In addition it should be noted that a wide range of ERCL CO2 emissions
is possible if higher or lower energy prices that those assumed under EMR's 2020
vision were to occur. The potential range of CO2 emissions and the effect that
possible energy efficiency measures might have to base projections for overall CO2
emission levels for ERCL is shown in Fig 7 below for a +/- emission scenario of 30°/o.

14000
13000

-·- 8ac;e
.c; Curve C

12000

CO2

····i···

-•· Curve D

11000
kt/yr

+30% range
of emissions

~

Range of Additional Energy
Efficiency Potential
• • ,~-

Base with Oslo

·-·-·-·
·-·-·---

,

10000

~,
~

9000

,

8000
7000
6000
5000

........

...~.~~~

I·-.

4000
1989

.../·

I I I I I
1993

-30% range
of emissions

I

I

I

1997

I

I

I

2001

I

I

I

I

2005

Year
Fig. 7 Effect of Possible Emission Ranges vs Energy Efficiency Potential

Overall the range of emissions for CO2 is consistent with a supply I demand response
to Canadian and world energy demands. The +30 °/orange of potential CO2
emissions reflects a potential price environment with significant real oil price growth,
which is reflected in significant increases in production of heavier crudes and natural
gas. The lower limit of potential CO2 emissions reflects shut in of marginal reserves
and deferred oil sands and frontier gas development, and is generally consistent with
EMR's alternate price scenario in the 2020 vision forecast. Should ERCL become the
operator, the potehtial effect of inclusion of 1OOo/o
of the OSLO project's CO2
emissions on ERCL's base operating emissions is also shown.

The net effect of these price sensitivities to total Canadian and World CO2 emissions
is summarized below.

 18
Energy Eff

Sensitivit¥

iii.ceotiY05-

ERCLCO2
[roissioCS

Total Ca~arusn
Q02 Em1ss
jo~
Higher

1 . Lower prices

2. Higher prices

Lower
Higher

?

Higher

t tal ERCL CO2 emissions as marginal
.
In general, lower energy prices will reduce e~vier crudes , a major component of the
production is shut in and development_of hlower prices prov ide little incentive for
CO2 growth is deferred. At the same ti~~ nt and assuming ene rgy demand continues
consume~ to become more energy ~fficie d World CO2 emissions are likely to rise
to be fossil fuel base?, over~II Canadian an C nadian sources co mprises
·
Although the production of oil and ~as from a_ ·
a overa ll Ca nadian CO2
.11
th
-approximately 7.5% of total Canadian CO2 _e~issi_ons '
emissions are likely to rise as consumer em1ss1onincreases .WI more an
compensate tor reduced emissions tram the energy production secto r. Furthermore
the displaced emissions from reduced Canadian petroleum productio n will be made
up somewhere else in the world!
Alternatively, higher energy prices while allowing some additiona l up~tream energy
efficiency improvements, will also permit further development of marg inal reserves
and heaver crudes, in effect raising ERCL CO2 emissions sign ifican tly from current
projected levels. Higher prices will however provide significant incen tive for
consumers to become more energy efficient, with corresponding bene fits to CO2
emissions. The corresponding level of total Canadian CO2 emiss io ns will depend on
demand response to these higher prices.

Technology Development Needs
Es~?'s retrofit en~rgy efficiency improvement potential mainly focuses around more
efficient
combustion
and waste energy
·
developed
tor these applications
b t utilizaf
.
_ion, wi·th various
techno logies alreactY
1
;n wi~e use due I? cost and reliability. As
such, technology development n~~s
delivery cost of these technologies lower. etrofit are pnmanly related to making the

~~r

The more highly leveraged areas for improvement .include:
Combustion Equipment Upgrades:
- More _efficientreciprocating en in
.
m~tenals ~e.eded)
g e combustion (eg high te mperature
- Higher eff1c1encyburners in fir
- Process control and other autoetu~e applications
mat1on improvements (eg combustion controls)

8 Based on estimated oil and gas CO
2

Includes estimated CO2 emissions f romprOduction
.
electricity of
us40 Mt/yr to Canad ian totals of 530 MtJyr

e.

 19
waste Energy Utilization :
- Power generation from flared gas
- Alternate H2S recovery and flare techno logies to reduce fuel gas make up
volumes
Other:

- Reduced wellbore heat loss (steam stimulated crude bitumen production)
- Improvements to hydrate control

The effect of other as yet unidentified technologies could improve the efficiency
potentials noted in this report, however it is impossible to identify the magnitude of this
potential or the timing. In addition, it should be noted that the introduct ion of new
technologies typically requires long lead times before their use becomes econo mic.
Considering future ERCL CO2 emissions related to growth in oil sands developme nt
and frontier gas, (reference Figure 7), the challenge for energy efficiency tech nology
development for new facilities is to widen the scope of influence that additional
energy efficiency measures might have relative to total ERCL CO2 emissions . This
effort will require particular focus on finding more innovative and cost effective
technologies for reduced energy intensity in the production and processing of
bitumen.
Should stabilization of CO2 emissions be required, additional technology
development needs are related to reducing the cost of potential CO2 capture and reinjection or disposal.

Reduction Progress Tracking System
Canada's Nation Action Strategy on Global Warming calls for a detailed inventory
and reporting system on all greenhouse gas sources and sinks. For CO2, this
reporting system and its application to the oil and gas production industry has yet to
be determined. However, historical tracking of the effects of future energy effic iency
improvements on CO2 emissions will likely be necessary to establish the contrib ution
of these measures to CO2 trends.
It is recommended that ERCL through its participation in industry associations, wo rk
towards establishment of the appropriate level of energy efficiency and CO2 repo rting
for the oil and gas production industry. Any reporting systems developed will have to
recognize the potential for masking of CO2 improvements from energy efficie ncy with
emissions increases due to production growth.

 20

QQ~ClOJS~o~s
A flECQM~HE~Pf\I~Q~S
y efficiency measures is unlikely for
• Stabilization of ERCL CO2 emissions fr~m en~~mended on alternate CO2 reduction
the conditions assumed. Further stu1/s/:~hanced
oil recovery.
O
0
opportunities, such as the use of C
.
. .
easures with less than a 5 year simple
• Full implementation of energy efficiency ~
by 6 5o/orelative to year 2005 and
payback could reduce ERCL .co2 .emissio;~a 2 5 ·M$/yr (1990) incremental
would cost 20 M$ (1990) cap1t~Iwith an e ctri~it cost savings. Additional
operating co~t re9uired t~ realize fuel or el~ed fcir these opportunities, cons istent
detailed engineering studies ar~ recommen
'ble Additional operating
with the intent to implement pr~J~CtSwh~lrlejOStle r~quired to capture economic
manpower focus on energy eff1c1encyw1 a so
operating and maintenance measures.
• The maximum potential for CO2 reduction (100°/oimplementation - including
uneconomic measures) is 14°/o based on year 2005 levels.
• A significant portion of the maximum reduction potential. is ass~ciated with
cogeneration of power and steam. To all~w c~~enerat1on proJects t~ proceed, a
cogeneration policy suitable to both electric ut1htycompanies and 011and gas
producers needs to be developed.
• Technology development for energy efficiency within ERCL should focus on new
energy efficient technologies for bitumen production and processing , and on
combustion related equipment retrofits. These requirements should be included in
ERCL's technology planning process.
• CO2 reduction estim~te~ from energ~ efficiency in this study are significantly lower
than government pr~Ject1onsfor the 011and gas production sector. To the extent
th~t the res_ultsof this study may be representative of other oil and gas companies,
this larg~ difference shows t~~t governments need to be cautious when it comes to
h
as
expectations that energy eff1c1encycan significantly reduce
emissions in the oil and gas production sector.
green ouse 9
• A wide range of CO2 emissions is possible con i t
.
.
d
requirements. The effect of energy efficien~
s s _entwith pnce I _supply deman
0
significant technology breakthrough in biturle n this ra~ge 1s relatively small. ~
conventional oil tertiary recovery is required t~ prdoduct1onand processing, or in
re uce potential emissions growth.
• Through its participation in industry associati
. .
towards establishing the appropriate level fns, it is recommended that ERCL work
0
reporting for the oil and gas production indu tenergy efficiency and CO2 emissions

s ry,

 21

Amine Sweeting
Crude Bitumen
CO2
EMA
Encon
ERCL
ERCB
Firetube Heaters
Flare gas make-up
GJ
Glycol Dehyration
Hydrates
lnsitu Thermal
k
kw hr
M

MJ
m3
sm3
Sour Gas
OSLO

PJ
Properties
t
Tertiary
Upstream
Wellhead Manager

A process for removing Hydrogen Sulphide (H2S) from
natural gas streams
Heavy oil obtained from steam stimulated oil sands deposits
Carbon Dioxide
Energy Mines and Resources Canada
Energy conservation
Esso Resources Canada Limited
Alberta Energy Resources Conservat ion Board
Fired heaters with combustion products directed through
the inside of heat exchanger tubes
Natural gas added to flare streams to ensure comple te
combustion
(1 E +09 joules)
Gigajoule
A process to remove water from natural gas streams
A water lattice in which light hydrocarbon molecu les are
embedded. Hydrates normally form when gas streams are
cooled below their hydrate formation temperature .
A reservoir recovery process utilizing heat to assist in t he
production of hydrocarbons
Thousand
Kilowatt hour
Million
Megajoule (1 E +06 joules)
Cubic meter
Standard cubic meter
A gas containing an appreciable quantify of hydrogen
sulphide, mercaptans, and/or carbon dioxide
Other Six Leases Operations Project
Petajoule (1 E + 15 joules)
Oil and Gas mineral leases
tonne
Enhanced oil recovery
Oil and gas production operations
An automated control system for oil field pump ing units

 22

ENERGYCONSUMPTION
r y consumpt ion
Calculation Procedures: Historical Ene g
1 sed in the produ ction and processing of
Since there is no record ?f the actual fue f ucilities operated by Esso Resources
conventional oil and gas m the ups~re~~ !stimate the histor ica l consumption from
0
Canada Limited, a method w~s devise
re orts Alberta Oil and Gas Industry
1
production ~ol.umes reported m the annu:now~ en~rgy requirem ent~ in 1989 and
Annual Stat1st1cs(ERC~ S~89-17), and .
ants for convent iona l 011 and gas were
1
1979. The estimated historical Juel r~~~ ~~~e bitumen productio n, the estimated
then added to the fuel data available .
f the total electrica l power requirements
0
ene~gy consumed by flare, and an estimatl~ .t d historical energ y consumption. The'
to give the total Esso Resources Canada 1m1e
.
.
. .
method and assumptions used in reconstructing the h1stoncal ene rgy consumption1s
outlined in the following steps 1 - 12.
1) Find Historical (Annual Report) Production Volumes.
Production volumes for conventional oil, gas, NGL, and crude bit umen were taken
from the Imperial Oil Limited Annual Reports for 1972 thru 1989 .
2) Determine Volumes Processed in 1989.
Since it is recognized that the volumes reported in the annual reports include v?lumes
that are produced by others and credited to Imperial Oil's accoun t, and do not include
volumes that are processed by Esso Resources Canada for others, so me estimate
was required to determine the volumes actually processed in the upstr eam facilities.
operated by ERCL. To do this, the volumes of conventional oil and gas processed1n
1989 (reported as part of the greenhouse gas inventory project) were compared to the
annual report production volumes. This indicated that ERCL only proc essed 85%of
the oil volumes reported yet processed 150% of the gas. Similarly a comparison of
the gas volumes processed in 1979, and the volumes reported in the 1979 annual
report, indicates that, Esso Resources processed 18% more gas tha n was reported
as Imperial Oil production in 1979.
3) Calculate Volumes Processed in ERCL Operated Facilities.
The volumes proce~sed in.the ERCL operated facilities were calc ulated assumingthe
volumes of conventional 011 processed prior to 1986 (i.e. before major acquisitions)
were equal to the. volumes produced as reported in the annual reports Volumes of
0 of the total gas
gas processed pn~r to J~86 were assumed to be constant at
118 10
produced to Imperial 011s account. ~etween. ~ 986 and
it was assumed that
1989
Esso Res~urces proc~ssed ~ubstant1alquantities of gas fo th
h'I more of
Imperial Oil's conventional 011 was actually bein
r
r O ers w I e
b others
.
The resulting factors used to calculate the actua~ ~d~ced and prodc~sst~~fXcilitieS
0
operated by ERCL were as follows;
es proce sse in

t

 23
Ratio of Processed to Produced Volumes
1972-85

1986

1987

1988

1989

Oil Processed to Produced

1.00

0.90

0.88

0.88

0.85

Gas Processed to Produced

1.18

1.35

1.40

1.40

1.50

Year

4) Determine Industry Conventional Oil and Natural Gas Energy Use
It was assumed that the overall fuel energy required by Esso Resources to process
conventional oil and gas would be essentially the same as that reported for the
industry in Alberta. The fuel gas used by the industry is reported in the Alberta Oil
and Gas Industry Annual Statistics (ERCB ST89-17). Raw gas production,
conventional crude production, condensate, and pentanes plus production are also
listed. To determine the overall industry energy consumption, the total gas,
·
conventional oil, condensate and pentane plus production was converted to their
energy equivalents and the total fuel used expressed as a fraction of the total energy
produced.
5) Calculate Total ERCL Conventional Oil and Gas Energy Production
The volume of conventional oil processed by ERCL was converted to its energy
equivalency by multiplying by a factor of 42.53 GJ/m3. A separate factor was not
used for the NGL production but rather these liquid volumes were included with the
conventional oil volumes. A conversion factor of 40.48 MJ/s m3 of gas was used to
estimate the energy content of both processed gas and fuel gas. This factor was
based on the assumption that the higher heating value of gas with 90% methane and
10% ethane would be representative.
6) Determine Fuel Requirements for Conventional Oil and Gas Processing
The overall fuel requirement for conventional oil and gas processing was assumed to
be the same as industry and the factors obtained under Item 4 above were applied to
the volumes processed. The fuel required for processing of natural gas was taken as
a percent of the raw gas processed on the bases of the 1979 and 1989 known
requirements. Some adjustment was made between 1986 and 1988 for the
acquisitions (which had a high proportion of gas processing) and for the fact that the
utilization in the gas processing facilities was high during this period. An adjustment
was also made for the effect of energy conservation programs in 1979-80 such that
the resulting factors were as follows;
Fuel for Processing Natural Gas
Year

1979

Fuel as o/oof Raw Gas

7.26

1980 1981-85
7.0

6.65

1986

1987

1988

1989

6.0

5.7

5.7

4.99

 24
.
oil was taken as the ?iff err;nuj
. conventional
uired for processing natural r.
. d for processing
h,
· r u,r
· d and the energy req
t t I energy require
Hstorical
Data
I
Crude Bitumen
taken from internal ERCL data
duce crude bitumen wa;onvention al oil and gas to give
1 n rgy used to pro required to proc~ss ir u stream facilit ies. In
~
s
d to th~ e~~i~sso Resources in th~udepbitumen was burned in the
el n rgy require e uivalents, since som~ c value for the bitumen was
t

i

:i:1s9~ra~~!it~atiiral gas, a _ht:~::1f~~~alue

--~ e to be 41.4 GJ/m3 and the h1g e
a 37A MJ/s m3.

s

tor the gas was assumedto

E rapolate 1979 to 1972 Energy Requirements

.
urned that the percent fuel energy to process
a · extrapolate from 1979, it was as~ o/c
and that the energy requ ired to
51 0
entional oil would be unchanged a~ ~ged at 7.26o/o of the raw gas volumes. The
ess natural gas would also beduncb·ta
men from 1972 - 75 inclusive was assume
d
ent energy used as fuel for cru e I u
2 0°1c
· 1972 28°/c ·n 1973
0 1
e directly related to the oil/steam ratio and taken as 3 · 0 m
,
,
in 1974 and 34.4% in 1975.
1

9) Add Energy of Flare and Electrical Consumption

T e volume of gas flared as reported in the greenhouse inventory study was
verted directly to energy equivalents and added as a constant factor for each
ear. Similarly what information was available for end use electrical power
co sumption was converted to the energy equivalence and added to each year to ge
e total ERCL energy requirements.

O) Calculate Percent Energy (Total)
T e pe,:cent total energy used in the processing of conventional oil, natural gas.and
crud~ bitumen, wa~ ~.lculat~d by adding the total electrical, flare, and fuel energy
requirements and d1v1dmgthis total by t~e total energy in production (step 5). A
sumn:iary t<?talfor each of these production sectors was also determined by this
applying this same method to each production sector .
. ) Calculate CO2 Emissions
The CO2 emissions from energy used w·th· E
ct r
of 49._7kilotonnes of CO2/ PJ of gas en~r in RCL were calculated by u.sing a fa 0

electncaJpower usage were calculatedb gy ~urned. The CO2 contributions frorn
GW h.r of elE:ci~calenergy use. Total ER~ ulsing an ~verage factor of o.983 kt C02d1
electncal em,ss,on totals.

CO2 emissions were the sum of gas an

12) Normalize CO2 Emissions
The normalized CO2 emissions

processing,crude bitumenPl"Oducii~~
~~~u~~ted for conventional oil processing,gas
e overall ERCL by divid ing the

 25
. .
ropriate CO2 emissions from each segment by the total ene
app
t
rgy produced in that
segrnen.

Calculation Procedures: E~~rgy Consumption Without Energy Conservatlo
lnit1at1ves
n
An estirnaJe ~a~. m_adeof the ene~gy consumption that would be required if no energy
conservation m1t1at1~es
had been 1mpleme~t~d a~ov~ normal design practices at the
time. In essen_cethis meant that. burne_r ~ff1c~en~1es
in the conventional oil sector were
ignored, electrical_ p~~er a~d boiler eff1c1e
_nc1es in the gas processing sector were
ignored as were s1grnf1cantimprovements in the gas to steam performance for crude
bitumen. The following steps 1 - 5 illustrate methodology used.
1) Estimate the percent energy used as fuel for conventional oil and gas
For conventional oil and gas a base year of 1979 was taken to represent the energy
requirements without energy conservation. Consideration was given to the fact that
water production has increased since 1980 and that the Norman Wells project came
on in 1985. Some consideration was also given to the effect of better facility utilization
in the gas facilities between 1986 and the present. As a result the factors used were
as follows;
0
{q Energ~ Used fQr PrQductiQnFactQr~
1987 1988-89

1980-84

1985

1986

% Energy for conv. oil

2.51 2.53 to 2.61

3.26

3.5

3.5

3.5

% Energy for gas

7.26

7.26

7.26

6.6

6.3

5.6

1972-79

Year

2) Estimate fuel requirements for crude bitumen production
The fuel requirements for crude bitumen, without any en~rgy co~servation i~itiatives,
was determined by assuming an equivalent gas/steam ratio varying from 92 .in 1972 to
90 in 1978 and then remaining constant to 1989. On this basis the fuel requirements
are as shown on the following table;
Yearly Fuel Requirements for Crude Bitumen

Year
Fuel Requirement ksm3/d

1972
80

1973
69

1974
64

1975
230

1976
251

1977
197

1978
214

Year
Fuel Requirement ksm3/d

1979
278

1980
301

1981
480

1982
458

1983
584

1984
747

1985
1489

Year
Fuel Requirement ksm3/d

1986
3053

1987
3233

1988
3695

1989
3747

 26
F I Requirements
3) Calculate Percent ue
percent of the energy
·
.
nt both as a
For each sector the fuel energy requireme ~ar) was calculated using an energy
recessed and ~s total energy (i.e. PJ pe_rYconventional oil or natural gas pro_cess
ing
1
40
8
factor of
.4 MJ/s m3 for the fuel used ~s used in the processing of crude bitumen.
and a factor of 37.4 MJ/s m3 for the fuel g
4) Calculate CO2 Emissions

.

The CO2 emissions for each sector were ca 1c ulated using a factor of 49. 7 k1lotonnes
of CO2 per PJ of energy consumed.
5) Determine Energy Utilization Improvements

oue to

Energy Conservat ion Initiatives

·
ts between
the caseforwith
no
The percentage reduction in energy requ~emen
as calculated
1989.
conservation initiatives and the a.~ua~pe odrm~ncedw tion of CO2 emissions
overall improvement in energy ut1hzat1onan t e re u_c
.
also calculated as the difference between the summation of the requirements
energy conservation initiatives and the actual performance .

Baseline CO2 Calculations:

energy
The
was ·
.h
wit out

Future Energy Requirements

The future energy requirements were estimated by using EMR's 2020 Vision
(Canadas Long Term Energy Outlook) as the basis for oil and gas product ion
volumes. Assumptions were then made for increased energy required to produce
conventional oil as more water is produced, and an estimated increase in energy
required to J?roducenatural gas as reservoir pressures deplete. Crude bitumen
energy requirements were assumed to be very cyclic and were estimated with
assumption.s as to when additional production might be commissioned. The following
steps 1 - 8 illustrate methodology and assumptions used.

1) Production Volume Forecast
t
b d
day) for
Internal ERCL volume forecasts (expressed as oil equival t
en me er cu e per
to
conventional oil, crude bitumen, natural gas Ii Uid
reflect conditions outlined in EMR's 2020 .. q ( sand ~atural gas were adJusted.
in 1999 or 2000).
vision eg frontier gas development starting
2) Estimate Volumes of Conventional Oil and Gas Processed

For purposes of the forecast, the volumes of NGL
d
to be equivalent on an oil equivalent basis and
and conventiona l oil were assume
of conventional oil produced. The gas was
were summed to give the total volume
1000 meter cubed/meter cubed of oil. Crud~umed to have an oil equivalence of
itumen Volumes were taken to be
equivalent to conventional oil volumes.

 27
) Estimate Volume of Oil and Gas Actually Processed
3
of th
.
assumed that the conventional oil processed would be aso,
10
E
R
,
t F
e conventional
It waS
oil produced to. sso esource s ?ccou.~: or natural gas it was assumed that the
gas processed in Esso Resources fac1ht1eswould be 150% of the gas produced by
Esso Resources.

4) Calculate Total Energy Processed
The energy values for conventional oil, crude bitumen and natural gas were taken to
be 42.53 GJ/m3, 41.40 GJ/m3, 40.48 MJ/s m3 respectively.
5) Estimate Percent Energy Required for Fuel

To compensate for the anticipated increased water handling in the processing of
conventional oil, the 1989 fuel requirement of 3.5 percent was escalated at 3% per
year throug.h2005. To compensate fo~ t.he expected increased compression required
for processing natural gas, and recognizing that some compression would be
electrically driven, the fuel gas requirements were escalated at 1% per year from the
baseof 4.99 percent irJ 1989. Crude bitumen fuel requirements were taken from
internal company projections.
6) Calculate Fuel Requirements and CO2 Emitted

The fuel requirement for each sector was calculated using the percent fuel energy
and the total energy processed. From this energy requirement the carbon dioxide
emitted was calculated using the factor of 49. 7 kilo tonnes per CO2 per PJ of energy
consumed.

7) Calculate Electric Requirements and CO2 Emitted.
F.utureelectrical end use energy needs were estimated by escalating conventional
011and gas 1989 load requirement by 2% per year. Adjustments were then made for
major project additions in the crude bitumen sector. CO2 emissions were calculated
by assuming that all future incremental power was supplied with CO2 emissions of
0.983 kVGWhr.

8) Calculate Baseline CO2 Emissions
Baseline emissions were determined by summation of emission.s from electrical, fuel,
and process CO2 emissions. Process CO2 emissions were estimated at 480 kt/yr of
CO2 from sour gas recovery processes.

Calcutatlon Procedures: Impact of Acquisitions
Acquisitions of Sulpetro Limited in 1986, of Ocelot, United Canso and JCIP in 1987
and ~f Texaco Canada Limited in 1989 had significant impacts on the total e.n~rgy
requirements of Esso Resources Canada Limited. To make an estimate of this impact,

 28
companies and repo~ed in their last
·1 d gas producedby the!~ming the energy requirement and Co2

the volumes of o1 an d as the basis for as
annual reports was use .
emission from this production.

for Last Year Operation
1) Volumes Reported
.
reported for Su lpe tro, Ocelot, United
5
The following table lists the prod uction volume
Canso and Texaco;

°

. Y 1umes
of Acguisitioos
Product100
Oil M3/d
Sulpetro
Ocelot
Canso (From ERCL 1988 Outlook)
Texaco

Gas ksm3/d

7827

2057

19

507.

323

765

24469

4200

2) Estimate Energy Processed
The energy associated with the reported production was calculated using a f~ctor of
42.53 GJ/m3 for the oil production and 40.48 MJ/s m3 for natural gas production.
3) Calculate Energy Requirements
The energy requirements were assumed to be the same as that for the overa ll Alberta
Oil
and gas
Gas production.
Industry and taken as 4.22o/oof the combined conventional oil and
natural
4) Calculate CO2 Emissions
The CO2 emissions were taken as being equivalent t
k'I
f CO2 per PJ
of energy consumed.
o 49 .7 1o tonnes o

 n r lY lficl ncy (and associated CO2
tdcl n J up th potential contributions (Jnd
'\ • \ I

'.t

IC)

I

tpJ II bl to II operations .
11t;c I f ,1111h npJ t It Ill I
1 111
t tlc>d II pc , r1 ,ppoll11nll
lc (w th p ttlcular focus on
1 111
ic
tiltllll\clll
'
I
c
dlh
It
n
polt
111
ti)
11
1 tlill'd«d 1, d111I 011 twill u nllrnu cl P r tlo ns nd Maintenance improvements
rtpl n r

n rl l n r y

Ulcl ncy Opportunities

,lmrt II lit d by prioritizing opportunities in terms of CO2 potential

*

mbu tlon ontrol lmprov m nt from th use of portable 02 analyzers
( ndfi d unit wh r po lbl ), to nsur efficient combustion .

* Addition I w t

nd proc

h t r cov ry from engin s to supplement building heat
h ting r qulr m nts.

* Combustion Ir pr h

t for fired equlpment.(both forced draft and natural

dr ft firedequipment)
• Miscellneouscontrol upgr des to optimize heat utilization (particula rly in
reboilersystems).
• Cogenertion of ste m and electricity.
• Powergener tlon from continuous flare locations (eg oil batteries).
• CFlare
volumereductionsthru ltern te processesfor low level H2S and

02 removal.

* Fl

re volumereductionthru altern te flare designs.
* Alt
ematereservoirrecovery processes.

 30

Site Specific Hems
The major impact for site specific efficiency opportunitie~ comes fr~m the crude
bitumen sector where a list of potential items and redu~_,on potent,~I was deve loped
from previous energy efficiency work . These opportunities are mainly focused on
improvements to overall plant heat utilization.
For the conventional oil and gas production areas, a reduction potential and cost
applie? base~ o~ feedback to date f~om an int~rnal facilities review process . The Was
total s1.te spec1fi~improvement potential was estimated at 2.25°(0 for 1989, with 1.?S°lc
0
r~duct1o_n a_ssoc1ated
with minor investments (Curve C), and with 0.5°/o assoc iated
with maJor investments (Curve D). Examples of site specific opportunities include:

Processchanges
*

Solvent changes
lower circulation rates
higher absorption

*

(Waste) heat recovery from aerial coolers

*

R~-configuring of heat exchanger trains
(Pinch technology)

*

Using process heat for heat tracing needs
Eguipment Upgrades

*

Reduced electrical
consumpt·10n
.
installation of high eff .
high efficiency lightin~iency motors

*

Installation of unloaders on compressors

*

Installation of high efficiency bl
.
ades on aerial coolers
Installation of variable speed drives

*
*

Installation of recovery t rb'
u tneS/expanders

*

Elimination of burn pits

*

Installation of thermostaticall

*

Y

co

ntrolled elect .

Use of solar power panels for
nca1heat tracing
(telecommunication)
power supply in re
mote areas

 31

•

. of pressure drops in piping, e.g. orifice meters
Elimination
. n additions or improvements
insulat10
nsfer pumps instead of compressors
Masst ra
Heat recovery from stack gase s

•

Installation of better contro l on ae rial coolers

operationsand Maintenance Reduction Potent ial
Additionaloperations and maintenance efJiciency actiyities _areestimated to result in
to % reduction of current CO2 production. A long 11
st of items/programs that could
1 2
beimplementedwas developed and includes the follow ing items:

Qperations and Maintenance Surveillance
*

Pay close attention to process sett ings

*

Pay close attention/maintenance to fuel consumers

*

Conduct energy conservation surveys

*

Monitor electrical power consumption

*

Monitor steam balances

*

Set energy targets for various modes of operat ion

*

Make better use of automated control systems

*

Minimize/optimize heat flux

*

*
*
*

Repair steam leaks/traps
Maintain analyzers
Monitor flue gases

Repair
· leaking valves to flare

 32

.
e Planning
Operation~
Mamtenanc

.

a

*

.
h operating are
d'
ator
in
eac
Assign energy coor ,n

*

Minimize shutdowns

*

Reduce causes/effects of unsc heduled shutdowns

*

(sc hedule cleaning)
.
Monitor heat exchanger fouling

*

Promote networking between areas

Operations
and Maintenance
ConservationMeasures
*

Shut off steam tracing in the summer

*

Shut off electric tracing in the summer

*

Shut off steam utilities not needed

*
*

Shut down glycol heating boilers when not needed
Shut down glycol pumps when not needed

*

Shut down pumps on recycle

*

Recover steam condensate