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Final Report
Potential Release of Heavy Metals and Mercury from the UOG
Industry into the Ambient Environment
- Literature Review
prepared for:
PETROLEUM TECHNOLOGY ALLIANCE CANADA
Suite 400, Chevron Plaza
500 – 5th Ave. S.W.
Calgary, Alberta
T2P 3L5
prepared by:
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Allan Chambers, P.Eng., Stephanie Trottier, EIT
and Mehrdokht Behnam-Nikoo, EIT
October 16, 2009
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Heavy Metals - Final Report
EXECUTIVE SUMMARY
Natural gas, conventional crude oil and bitumen contain heavy metals in trace amounts and their
production, processing and use can contribute to emissions of heavy metals to the environment.
Some of these elements, such as mercury, are potentially toxic and can lead to damage to
processing equipment. Due to its toxicity, mercury has been studied and characterized in several
studies from the United States and Europe.
The objective of this project was to review the existing literature and data available on heavy
metals concentrations and potential emissions from the oil, gas and bitumen industry. This
interim report would provide the basis for further work, if necessary, to better characterize these
emissions.
Based on a review of the open literature, the following observations are made on the potential for
heavy metals emissions from natural gas, oil and bitumen production and processing in Alberta:
1. Studies of U.S. natural gas deposits suggest that mercury in North American natural gas
is typically low, from 0.005 to 0.04 µg/m3. The existing data on Alberta natural gas
indicate that most Alberta gas contains less than 0.08 µg/m3.
2. Reported data on heavy metals content of Alberta crude oil sampled near the well head
was from a 1975 study of 88 samples. The average mercury content was 50.9 ppb, with a
range from 1.6 to 399 ppb.
3. Mercury content in conventional oil as delivered to the refinery was well characterized in
recent studies using modern sampling and analysis methods. The average mercury
content of Western Canadian crude feeds was 1.6 ppb, in contrast to the average 50.9 ppb
reported for the wellhead samples.
4. Bitumen contains higher levels of trace elements than conventional crude. Only limited
data was available for mercury content. Based on analysis of diluted bitumen and
synthetic crude feeds to a refinery, bitumen contains 5 to 11 ppb while synthetic crude
contains 0.4 to 1.6 ppb.
5. There is little information on mercury or other heavy metal concentrations in the various
pathways for emissions to the environment, such as solution gas flaring, refinery gas
combustion and tank vents.
Further work is recommended to better characterize potential heavy metal emissions to the
environment from the natural gas, conventional crude and bitumen production and processing
industry. Considering annual production rates and the estimate of mercury concentrations from
the available information, the recommended highest priority for further work is to better
characterize the potential emissions of heavy metals to the environment during bitumen
production and processing. Both the natural gas and conventional crude well head data is over
20 years old and could benefit from analysis with newer sampling and analysis techniques with
lower detection limits. In particular, the existing data shows a significant difference between
mercury concentration in crude samples collected near the wellhead and samples of crude feed
collected at refineries.
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TABLE OF CONTENTS
1.
BACKGROUND ................................................................................................................... 1
2.
OBJECTIVE OF PHASE I.................................................................................................. 1
3.
METHODOLOGY ............................................................................................................... 2
4.
OVERVIEW OF HEAVY METAL EMISSIONS FROM UOG...................................... 2
4.1
Definition of Heavy Metals............................................................................................... 2
4.2
Heavy Metal Emissions reported to the NPRI ............................................................... 3
4.3
Upstream Oil and Gas Industry in Alberta.................................................................... 6
4.4
Current activities .............................................................................................................. 7
5.
SAMPLING AND ANALYSIS ............................................................................................ 7
6.
NATURAL GAS ................................................................................................................... 8
6.1
7.
Pathway of release to the environment for Natural Gas ............................................... 9
CONVENTIONAL OIL ..................................................................................................... 10
7.1
Conventional Oil Pathway of Release to Environment ............................................... 12
7.2
Mercury in Conventional Oil......................................................................................... 12
7.3
Mercury Content of Crudes Sampled at the Refinery ................................................ 13
8.
BITUMEN ........................................................................................................................... 16
8.1
Mercury in Bitumen ....................................................................................................... 17
8.2
Pathway of release to the environment ......................................................................... 17
9.
RELATIVE POTENTIAL FOR HEAVY METAL EMISSIONS IN ALBERTA ....... 18
10. CONCLUSIONS AND RECOMMENDATIONS............................................................ 19
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Potential Release of Heavy Metals and Mercury from the UOG Industry
into the Ambient Environment
1. Background
Fossil fuels contain heavy metals in trace amounts and the production, processing and
consumption of fossil fuel contribute to anthropogenic emissions of heavy metals to the
environment. Concerns due to heavy metals in oil and natural gas include:
- potential toxicity if released to the environment during processing and end use,
- accumulation in processing equipment, leading to potential health and safety issues
during equipment maintenance and decommissioning,
- sludge from separators, desalters, heat exchanges and water treatment systems may
contain mercury contamination, limiting disposal options,
- negative impact on equipment, such as mercury interaction with aluminium, and
- contamination of catalysts during downstream processing.
Extensive research concerning heavy metal emissions, particularly mercury, from waste
incineration and coal combustion has resulted in new analysis methods to better quantify
emissions and development of technologies to reduce these emissions. Less work has been done
to identify and quantify heavy metal emissions from the production and processing of natural
gas, conventional oil and bitumen.
A significant sampling and analysis program would be required to fully determine heavy metal
emissions from upstream oil and gas (UOG) operations in the Western Canadian Sedimentary
Basin. The purpose of this project was to review available information on heavy metals in oil,
natural gas and bitumen and on recent developments in sampling and analysis techniques. At the
completion of the project, a sampling and analysis program would be proposed if appropriate.
2. Objective of Phase I
The objectives of this Phase I project were to:
- Identify and review previous studies and/or measurements of heavy metal emissions
from upstream oil and gas production in the Western Canadian sedimentary basin,
concentrating on work reported since 2001.
- Identify and review recent work in the United States and worldwide.
- Prepare an interim report on the findings for review by the Steering Committee.
If warranted, the remainder of the project would:
- Review the sampling methods and analytical methods for heavy metals analysis and
determine recommended methods and detection limits.
- Recommend a program of work to further quantify heavy metal emissions from
upstream oil and gas production.
This interim report summarizes the findings of the literature search and contacts with researchers
in other jurisdictions concerning the available data on the potential for heavy metals emissions
from the UOG industry.
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Heavy Metals - Final Report
3. Methodology
The following interim report summarizes a review of existing literature and reported data on
measurements of heavy metals relevant to the UOG industry. Sources of information included:
- scientific literature databases, including NTIS, University of Tulsa’s Petroleum
Abstracts, Energy Scitech, Ei EncompassLIT, AESIS, CA SEARCH and Ei Compendex
- US Environmental Protection Agency (EPA) reports and personal contact
- Environment Canada reports and personal contact
- web-based searches.
The literature review included information published up to July 2009. Where possible, the
authors of key papers and reports were contacted. Although the emphasis was on production
from the Western Canadian sedimentary basin, information from the rest of world was also
examined.
4. Overview of Heavy Metal Emissions from UOG
This project considered heavy metal emissions due to heavy metals that were present in the
natural gas, oil or bitumen. There is the potential to introduce heavy metals during processing.
Examples include contamination during processing by instrumentation that contains mercury or
by process chemicals, such as amine, that may contain trace concentrations of heavy metals.
This report does not consider the potential contribution of these secondary sources of heavy
metals.
4.1
Definition of Heavy Metals
‘Heavy metals’ is a term often used in the literature and in environmental legislation however
there is no well defined list of metallic elements that are included as heavy metals. Toxicity is a
major concern for some heavy metals, such as mercury and lead, or compounds formed by the
metals. Some semi-metal elements, such as arsenic, may be included due to their toxicity rather
than a strict definition as a heavy metal.
In addition to their potential toxicity and persistence in the environment, heavy metals may also
cause equipment damage. At locations with high mercury levels in the natural gas, gas
liquefaction plants have experienced damage to heat exchangers due to mercury in the feed gas.
Trace amounts of metals can also reduce catalyst performance and lifetime in refinery processes.
The potential for mercury accumulation in equipment should be considered when maintaining or
decommissioning equipment. Special precautions may be required to prevent release of mercury
to the environment and to minimize exposure of workers to mercury vapour or dermal absorption
of organic mercury compounds.
The European Union ESPREME project (http://espreme.ier.uni-stuttgart.de/) was set up to
develop methods and to identify strategies for reducing emissions and harmful impacts of heavy
metals. The priority metals in this program were mercury, cadmium, lead, nickel, arsenic and
chromium. Major identified sources of emissions in the EU were coal and oil combustion,
cement production, metals industry, waste incineration and caustic soda production.
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Heavy Metals - Final Report
The Canadian National Pollutant Release Inventory (NPRI) simply defines heavy metals as
‘Metals that have a relatively high atomic mass. Some examples are Lead (Pb), Cadmium (Cd),
and Mercury (Hg)’. The following Section 4.2 provides further information on heavy metals
emissions reported in the NPRI database.
4.2
Heavy Metal Emissions reported to the NPRI
Industrial facilities that meet the reporting requirements set out by Environment Canada report
annually their emissions to the environment of certain heavy metals. Facilities need to report
cadmium or mercury emissions if they were manufactured, processed or otherwise used at the
facility in a quantity of 5 kg/y or more and need to report arsenic (As) or lead emissions in
quantities of 50 kg/y or more. Other heavy metals, such as vanadium or nickel, need to be
reported to NPRI if they were manufactured, processed or otherwise used at the facility in a
quantity of 10 tonnes or more per year. Where feasible, the reported numbers are based on
measurements. If measurements are not feasible, the values are based on estimates. These
reports are available in the National Pollutant Release Inventory (NPRI) at
http://www.ec.gc.ca/inrp-npri/.
Table 1 to Table 4 summarize the information available from the 2007 NPRI database report for
Western Canadian UOG industries that reported emissions of Hg, Cd, Pb and As. The tables
also include the Canadian total reported to NPRI to give a relative impression of the contribution
reported by the UOG industry to total emissions reported in Canada.
The oil and gas related companies reporting heavy metal emissions to NPRI are primarily oil
sands and heavy oil producers or refineries. In 2008, natural processing facilities did not report
emissions of mercury, arsenic or lead above the NPRI reporting threshold. One oil field waste
management facility reported mercury emissions of 0.001 kg/y. A natural gas processing plant
reported cadmium emissions of 15 kg/y.
Emissions of mercury from the bitumen industry and refineries were equivalent to about 2% of
Canada’s total reported mercury emissions in 2007. In Alberta, the major source of mercury
emission is the coal-fired utility industry (828 kg/y) followed by bitumen processing and
refineries (93.4 kg/y).
UOG related emissions of cadmium, lead and arsenic were small relative to Canada’s total
reported emissions, contributing less than 0.5% of the total releases. The bitumen industry is one
of the major sources of lead and cadmium emissions to air and water in Alberta.
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Heavy Metals - Final Report
Table 1: Reported Mercury Emissions Related to Oil and Gas
(NPRI 2007 Database)
Facility
Suncor Energy Inc. Oil Sands
Syncrude Canada – Mildred Lake
Consumers Refinery, Saskatchewan
Imperial Oil – Strathcona Refinery
Petro-Canada – Edmonton Refinery
Shell Canada – Scotford Refinery
CCS – Lindbergh (oil field waste mgt.)
Air
51
31
17
5.9
4.9
0.557
0.001
Total reported in Canada
5,199
On-site Releases of Mercury
(kg/year)
Water
Land
Total
0.186
0
51
0
0
31
0
0
17
0
0
5.9
0.712
0
5.6
0
0
0.557
0
0
0.001
278
1.1
5,478
Table 2: Reported Cadmium Emissions Related to Oil and Gas
(NPRI 2007 Database)
Suncor Energy Inc. Oil Sands
Imperial Oil – Cold Lake Heavy Oil
Syncrude Canada – Mildred Lake
Imperial Oil – Strathcona Refinery
Petro-Canada – Edmonton Refinery
CNR – Wolf Lake & Primrose Plant
Shell Canada – Scotford Refinery
Shell Canada – Scotford Upgrader
On-site Releases of Cadmium
(kg/year)
Air
Water
Land
Total
67
11
0
78
31
0
0
31
19
0
0
19
19
0
0
19
14
2.8
0
16.8
15
0
0
15
4.6
0
0
4.6
0.032
0.37
0
0.402
Total reported in Canada
26,962
Facility
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Heavy Metals - Final Report
8,173
909
36,044
Table 3: Reported Lead Emissions Related to Oil and Gas
(NPRI 2007 Database)
Facility
Suncor Energy Inc. Oil Sands
Syncrude Canada – Mildred Lake
Imperial Oil – Strathcona Refinery
Petro-Canada – Edmonton Refinery
Consumers Refinery, Saskatchewan
Total reported in Canada
Air
477
299
82
33
15
255,794
On-site Releases of Lead
(kg/year)
Water
Land
116
0
0
0
3.5
0
3.9
0
0
0
14,256
195,945
Total
594
299
85.5
36.9
15
465,950
Table 4: Reported Arsenic Emissions Related to Oil and Gas
(NPRI 2007 Database)
Facility
Suncor Energy Inc. Oil Sands
Syncrude Canada – Mildred Lake
Shell Canada – Scotford Upgrader
Consumers Refinery, Saskatchewan
Air
58
46
0.032
1.7
Total reported in Canada
81,163
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On-site Releases of Arsenic
(kg/year)
Water
Land
60
0
0
0
0
0
0
0
26,180
1,562
Total
118
46
0.032
1.7
108,905
4.3
Upstream Oil and Gas Industry in Alberta
Table 5 gives the amount of natural gas, crude and bitumen production for Alberta in 2008 both
in terms of quantity and in the equivalent amount of energy based on the higher heating value of
the fuel. In 2008, conventional crude accounted for about 12% of the total energy production for
these three products. In addition to the produced natural gas, about 0.7 x 109 Nm3 of solution gas
was flared or vented in 2008. On an energy basis, natural gas is the largest production, followed
by bitumen. Crude production represents less than 25% of the energy produced as natural gas.
Table 5: Relative Production of Natural Gas, Oil and Bitumen in Alberta
(data from 2008)
amount produced in
2008
equivalent energy
(GJ/y)
natural gas
130 x 109 Nm3
4.8 x 109
crude
29.2 x 106 m3
1.1 x 109
bitumen
75.7 x 106 m3
3.2 x 109
mined
55%
in-situ
45%
solution gas
(flared or vented)
0.7 x 109 Nm3
Production of conventional crude is declining in Alberta while the production of bitumen is
increasing. Figure 1 shows the Alberta supply of crude oil and equivalent in years 1999-2008. In
2008, total conventional crude oil production was about 80,000 m3/d. In the same year Alberta
produced 207,400 m3/d of bitumen, with surface mining accounting for about 55 per cent and in
situ accounting for about 45 per cent. From surface mineable bitumen, about 104,000 m3/d of
synthetic crude oil (SCO) was produced.
Heavy metal emissions can occur during production and processing of natural gas, crude and
bitumen or at the point of end use. Alberta exports over 60% of its natural gas production and
over 80% of its liquid hydrocarbon production. Most of the heavy metal emissions associated
with end use will occur outside of the province.
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Heavy Metals - Final Report
Figure 1: Alberta Production of Crude Oil and Bitumen
(ERCB Year in Review, 2008)
4.4
Current activities
The authors of previous mercury studies in both Environment Canada and the US EPA were
contacted concerning current and planned heavy metals studies related to the oil and gas
industry. At the time of this study neither the US EPA nor Environment Canada have active or
planned projects in heavy metal emissions related to the oil and gas industry. The primary
current emphasis is on reducing mercury emissions from the combustion of coal. Several
technologies for removal of mercury from coal combustion stack gases have been developed and
are nearing commercial application. Operating mercury capture systems will be required for
Alberta’s coal-fired power plants by 2011.
5. Sampling and Analysis
Some heavy metals, such as Hg and As, can be present at low concentrations and may be present
in gas, liquid or solid forms. Hg is particularly difficult to determine accurately and its toxicity
is highly dependent on the Hg compound. Recent studies on Hg in crude oil in North America
spent significant effort to develop sampling, sample handling and sample analysis methods to
improve the accuracy of Hg determination (Wilhelm, 2005). Some of the cautions concerning
earlier studies of Hg content in hydrocarbons include:
- sampling and sample handling methods may not be well documented. As Hg may be
present in vapour, liquid or solid forms, details of sample handling and treatments are
critical.
- in the order of ½ the elemental mercury in a liquid hydrocarbon sample can be lost by
opening a sample jar.
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Heavy Metals - Final Report
-
mercury can absorb on and react with inappropriate sample container materials.
multiple samples and samples from different batches and even different times of the year
are needed as Hg content can vary significantly.
concentrations of heavy metals are low, increasing the impact of contamination.
detection limits may not have been low enough in previous studies, leading to reporting
of concentrations at the detection limit and a resulting overestimation.
6. Natural gas
Natural gas production may contain trace amounts of heavy metals in the condensate and water
co-produced with the gas. Mercury and arsenic have sufficient vapour pressure that they may be
present in the natural gas. The only heavy metal emissions reported to NPRI by the natural gas
industry in western Canada is 15 kg/y of cadmium emissions reported by one natural gas
processing plant.
Essentially all of the reported work on heavy metal emissions from natural gas production and
processing is related to mercury. Mercury is a trace element often found in natural gas. In some
natural gas reserves the mercury concentration is high enough to require mercury removal prior
to natural gas processing to prevent equipment damage or to meet sales specifications. Past
catastrophic equipment failures due to mercury weakening of aluminium heat exchangers is one
reason that mercury in natural gas has been studied extensively.
Some general observations on mercury in natural gas include (Wilhelm and Bloom, 2000):
- elemental Hg is the dominant form in natural gas phase and will be present in the
processed natural gas and condensate,
- organic Hg will partition to separated liquid hydrocarbons (soluble) on cooling of the gas,
- ionic Hg, such as HgCl2, is the dominant form of mercury in filtered condensates,
- elemental Hg has low solubility in water, thus Hg that is present in produced water will
be mostly ionic or suspended forms,
- HgS may be present in sour natural gas.
Natural gas in North America is generally low in mercury concentration, from 0.005 to
0.04 µg/m3, although some sites in Texas contain up to 400 µg/m3.
A review by the Alberta Research Council completed for Environment Canada (Chambers and
Supeene, 2002) covered existing literature and data in the public domain up to 2001.
Information on mercury in Canadian natural gas was limited to a 1972 study that tested gas from
18 Alberta wells. The sampling and analysis methods used had a relatively high detection limit
of 0.08 µg/m3 for the gas and 10 ppb for water and condensate samples. As a result, 15 of the
18 wells were below the detection limit for mercury in gas and most of the condensate and water
samples were below the detection limit. The highest concentration measured in the gas was
1.3 µg/m3. This data may put an upper bound on the mercury contents in Alberta gas and
condensates, however, a sampling and analysis program using modern techniques was
recommended to accurately assess potential mercury emissions.
Determining mercury in natural gas is challenging due to both the low concentration and
variability in concentration. Ryzhov et al., 2003 reports data from continuous, real-time
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Heavy Metals - Final Report
measurement of mercury concentration using an atomic absorption spectrometer method with a
detection limit of 0.01 µg/m3. Mercury concentration varied with periods from several minutes
to several hours, with fluctuations as much as 80% of the average value. Longer term studies
showed mercury variation during several years of production, with some wells decreasing in
mercury content and some wells increasing.
Technologies are commercially available for removal of mercury from natural gas streams. Most
applications used a treated activated carbon to absorb elemental mercury from the gas stream.
(Ela et al., 2008).
6.1
Pathway of release to the environment for Natural Gas
There is potential for heavy metal emissions to the environment from various steps in natural gas
production and processing. Major steps in natural gas processing include:
- drilling,
- well test flaring,
- primary separation,
- dehydration,
- natural gas processing to remove acid gases,
- flaring of acid gas at some sites,
- sulphur recovery,
- hydrocarbon recovery,
- compression.
Potential pathways of heavy metal release to the environment from natural gas and condensate
production include:
- disposal of drilling wastes,
- flaring,
- glycol dehydrator vents
- sulphur plant tail gas incineration,
- disposal of waste waters and sludges,
- condensate tank vents,
- equipment decommissioning,
- end use of the natural gas and natural gas condensates.
Little information exists on heavy metal contents related to the above pathways. One project in
Alberta sampled tail gas incinerator stacks and other natural gas processing streams (Gnyp et al.,
1987 and Gnyp et al., 1983 and St. Pierre et al., 1989). Hg was detected above the detection
limit of 7 µg/m3 only intermittently in any of the samples. A significant emission of mercury
from tail gas incineration in Alberta seems unlikely.
Attempts have been made to measure the distribution of mercury to various process streams
during natural gas processing. Due to the challenges with measuring mercury these studies were
mostly on plants with a high mercury content and often did not achieve a good mercury mass
balance. Table 6 summarizes the mercury to various streams for one 50 mmscfd natural gas
plant in the Far East (Carnell and Foster, 2005).
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Heavy Metals - Final Report
Table 6: Distribution of Mercury in a Far East Gas Processing Plant
(from Carnell and Foster, 2005)
Process Stream
raw gas
acid gas removal vent
dryer vent
condensate
sales gas
Mercury
(kg/y)
220
22
3
45
150
Portion of Hg
in Stream
(%)
10
1
20
68
Simulation programs have also been developed to predict the distribution of mercury to various
streams during natural gas processing. Smit et al., 2004 report predicted mercury distribution
using modified HYSYS simulation software. The distribution will depend on the processing
steps used. The simulation of the selected process scheme predicted that 80% of the elemental
mercury in the raw gas and 49% of the mercury in the condensate reported to the sales gas.
Mercury distribution will depend on the process scheme used and the concentration of mercury
in the raw natural gas.
7. Conventional oil
Crude oils contain metals at concentrations from a few parts per billion in conventional light oils
to hundreds of parts per million in heavy crudes. The most abundant metals, usually present
between 10 and 1000 ppm, are Ni, V and Fe. Other elements, usually present in the 1 to 50 ppm
range include Pb, Ba, Sn, Ag, Co, Cu, Mo, Ti and Zn. Hg and As are present at ppb levels
(Caumette et al., 2009).
Metal species in crude are present in many complex chemical forms, making a detailed species
analysis challenging. Most of the metals in crude oil are associated with the asphaltene fraction.
Up to 95% of the metal content is removed from oil by precipitation of asphaltenes (Caumette et
al., 2009). With the exception of Hg and As, during refining the metals will concentrate to
residual fuel oil fraction and then to the coke on further processing.
A recent study in Venezuela examined the potential for emissions of radioactive compounds on
combustion of No. 6 fuel oil in large electricity generation plants. (Barros, et al., 2005).
Naturally occurring heavy metals and radionuclides concentrate to the heavy fuel oil fraction and
to the ash remaining after combustion. Samples of heavy fuel oil and ash were collected and
analysed. The study concluded that the ash was safe from a radiological perspective but there
was some potential for leaching of vanadium compounds from the ash.
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Heavy Metals - Final Report
Hitchon and Filby, 1975, and Hitchon et al., 1983 examined 22 trace elements in 88 samples of
Alberta crude oils representing the major geological formations. Crude oil samples were
collected near the well head and centrifuged and filtered to remove solids prior to analysis.
Samples collected included crude oils, condensates and two samples of Athabasca heavy oil.
Table 7 summarizes the average concentrations of the samples analysed. Mercury concentration
of the well head samples was an average of 50.9 ppb.
Table 7: Average concentrations of trace elements in Alberta crudes
(Hitchon and Filby, 1975)
Element
Average
Concentration
Units
S
Number of Samples
above Detection
Limit
88
0.83
%
V
Cl
Na
Fe
Ni
84
87
85
41
69
13.6
39.3
3.62
10.8
9.38
ppm
ppm
ppm
ppm
ppm
Zn
Co
I
Mn
Se
Hg
Cs
Br
As
Au
Sb
Cr
Rb
Sc
Eu
79
84
51
78
62
39
43
82
71
4
24
42
9
51
50
459
53.7
719
100
51.7
50.9
4.27
491
111
0.438
6.22
93.3
148
7.76
0.935
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
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Heavy Metals - Final Report
7.1
Conventional Oil Pathway of Release to Environment
There is potential for heavy metal emissions to the environment from various steps in the
processes to produce final products such as gasoline. Major steps at the wellhead include:
- primary gas, water, solids and liquid hydrocarbons separation,
- flaring of solution gas if not recovered,
- disposal of produced water (if not re-injected),
- storage of liquids at site.
Major steps in producing final products at the refinery may include:
- distillation,
- coking of heavy ends or residues,
- catalytic cracking,
- hydrotreating.
Potential pathways of heavy metal release to the environment include:
- disposal of drilling mud wastes,
- disposal of sludge and water from primary separation,
- flaring of solution gas,
- combustion of refinery gas at the refinery,
- disposal of refinery waste waters and sludge,
- disposal of coke and/or combustion of coke,
- equipment decommissioning,
- end use of the refined products.
There was little or no data reported in the literature on potential heavy metal releases from oil
production and primary separation at the well head. Most produced water in Alberta is reinjected and thus would not be a source of emissions to the environment.
7.2
Mercury in Conventional Oil
Mercury has received the most emphasis in studies of heavy metals in conventional oil due to its
toxicity. Mercury is identified as a priority toxic substance in the Canadian Environmental
Protection Act. Mercury can be present in crude oil in many forms, including (Wilhelm and
Kirchgessner, 2003):
- elemental mercury (soluble in hydrocarbon liquids up to about 2 ppm),
- organic mercury compounds, such as dialkylmercury, usually in trace amounts (highly
soluble in crude oil and gas condensate),
- ionic salts, such as mercuric chloride,
- suspended solid forms, such as HgS or mercury adsorbed on particulates.
The form of mercury can have a significant impact on bio-availability. For example, mercuric
sulphide (HgS) is a relatively stable solid that is insoluble in water while alkyl mercury
compounds are readily bio-available. Elemental mercury is typically the major component in
conventional crudes. Mercuric sulphide and asphaltene mercury are significant in some crudes
and bitumens.
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Heavy Metals - Final Report
The distribution of mercury to various streams during crude production and processing will vary
with crude composition and processing steps. Due to its relatively high vapour pressure,
pathways of release of elemental mercury to the environment can include heated storage tank
vents and solution gas vents or flares. Limited analysis has been completed for produced water
(Wilhelm, 2001) with results generally 0.01 to 3 ppb of mercury. No Canadian samples were
included in this study.
Pathways of release to the air at the refinery include combustion of refinery gas in flares or
boilers and combustion of petroleum coke. Suspended Hg compounds in the crude, such as HgS,
will tend to concentrate in the heavy ends and residuals and ultimately go to the coke. Ionic Hg
compounds will tend to be separated with water. Elemental Hg and organic Hg compounds tend
to concentrate in the light distillation products. Composition and amount of refinery waste water
varies widely depending on feed crude and process configuration. Limited analysis of refinery
waste waters show contents of total Hg up to 1 ppb and 10 to 100 ppb each of trace metals such
as Cu, An, Pb, V, Se, Ni, Cr, Fe, As, etc. Refineries may dispose of waste water in deep wells or
treat and surface dispose. (Wilhelm, 2001).
There is insufficient information to conclusively estimate the partitioning of mercury in the crude
feed to air, water and solid emissions during separation at the wellhead and processing at the
refinery. There are major uncertainties in the paths for mercury emissions during refining as
there is very limited data on Hg content in waste sludge, waste water and refinery gas. Mercury
concentrations in refined products have been studied (Bloom, 2000, and Liang et al., 1996) with
reported mercury in U.S. light distillates and fuel oil of 1 ppb to 5 ppb. A mean mercury
concentration of 50 ppb was found in a sampling of petroleum cokes used as fuel in the U.S.
(Wilhelm, 2001). The mercury contained in the refinery feed crude will put an upper limit on the
potential mercury emissions from the refinery.
7.3
Mercury Content of Crudes Sampled at the Refinery
A recent major study in United States (Wilhelm, et al., 2007) and a companion study in Canada
(Hollebone and Yang, 2007) examined Hg in a large number of crude feeds to refineries in North
America. The objective was to measure the mean and range of concentrations in crude oil
processed in North America. The focus of the study was total mercury content and mercury
species (in the U.S. study) present in the oil delivered to the refinery rather than at the wellhead.
Some mercury may segregate to sediments in storage tanks, be lost as vapours from heated tanks
or adsorb on equipment during processing and transportation to the refinery.
An initial phase of this work examined sampling and analysis methods, selection of methods
with a suitably low detection limit and estimation of errors due to sampling and sample handling
methods (Wilhelm, et. al., 2005). The use of accurate sampling and analysis methods resulted in
measurable levels of mercury in all of the samples collected in the Canadian study. The relative
processed amounts of crude oil from different sources were reported in order to more accurately
represent total mercury levels in crude oil processed in North America and to develop an overall
mean mercury concentration weighted to amounts of crude used.
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Heavy Metals - Final Report
The remainder of this section will report results from Wilhelm, et al., 2007 and Hollebone and
Yang, 2007 due to the thoroughness of sampling and analysis methods used. Reported mercury
from previous studies of conventional oil may be less reliable due to:
- bias caused by unwarranted emphasis on a few oil sources with unusually high mercury
content,
- lack of reporting of sampling methods or quality control methods,
- poorly documented sample origin,
- potential loss of volatile elemental and organic mercury through vapour loss during
sample handling if appropriate sampling methods were not used,
- relatively high detection limits of sampling and analysis method in some previous
studies,
- reporting of mercury levels at the detection limit if no mercury was detected in the
sample.
Wilhelm, et al., 2007, reported the results of a multi-year study to sample and analyse 170 crude
oil streams fed to refineries in the United States. Samples were collected immediately upstream
of refinery feed tanks. The total mercury concentration expressed as a volume weighted mean
was 3.5 ± 0.6 ng/g. The measured range of concentration varied from below the detection limit
(0.5 ng/g) up to 600 ng/g. The highest mercury concentrations were found in crudes sourced
from east Asia. The estimated maximum amount of mercury from oil processed in the U.S. was
less than 5% of that derived from burning coal in the U.S.
Hollebone and Yang, 2007, reported the results of a three year study to examine the mercury in
feed oils to refineries in Canada. A total of 109 grab samples from 32 oils were collected at the
entry points to refineries and analysed by two different laboratories using two analytical methods
to determine total mercury content. In addition to conventional crudes (both Canadian and
imported), the sampled refinery feeds included two natural gas condensates, one diluted bitumen
and two synthetic crudes derived from bitumen.
Table 8 summarizes the results from the Canadian study with the crudes grouped based on
geographical origin. The average total mercury concentration in the Canadian refinery feed
samples was 2.6 ± 0.5 ng/g, weighted by the volume of each crude refined in Canada in 2002.
From this average concentration, the total estimated mercury emissions from crude refining and
end use of the refined products for 2002 was 227 kg, or about 4% of total mercury emissions
reported in Canada in 2007 NPRI. The average mercury concentration of samples from Western
and Northern Canadian oil production was 1.6 ± 0.3 ng/g.
Other observations from the Canadian study included:
- range of mercury concentrations in refinery feeds were from 0.1 to 50 ng/g. However,
only one sample contained mercury >20 ng/g.
- average concentration and range was significantly lower than previous studies.
- Canadian oils had lower total mercury (1.1 to 1.6 ng/g) than oils from foreign sources.
- no strong correlation between total mercury concentration and either sulphur content or
oil density.
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Table 8: Mercury Content in Refinery Feeds in Canada
(from Hollebone and Yang, 2007)
Geographical
Source of Crude Oil
Western and Northern Canada
Eastern Canada
Maritimes and Ontario
Imported Oil
Overall weighted average
average
(ng/g)
1.6 ± 0.3
1.1 ± 0.2
4.5 ± 0.8
2.6 ± 0.5
Hitchon and Filby, 1983, and Hitchon, et al., 1975, reported Hg concentrations in samples of
several Alberta crudes. Samples were collected near the well head but the sampling location
varied. Samples were centrifuged and filtered prior to analysis. Table 9 summarizes the results
from this study. Measured values of Hg ranged from undetected up to 399 ppb in one sample.
The average reported Hg concentration of 27.6 to 85.6 ppb is significantly higher than the values
of 1.6 ppb for western crudes sampled at the refinery (Table 8). This indicates that either a
significant reduction in Hg occurred during primary separation and transportation or that the
wellhead samples were contaminated during handling. The highest values reported by Hitchon
and Filby, 1983, of 399 ppm are similar to levels seen in some high mercury Asian crudes
imported to the U.S. (Wilhelm, et al., 2007).
Table 9: Mercury in Alberta Crude Oils
(from Hitchon and Filby, 1983)
Upper
Cretaceous
No. of Samples
Hg (ppb)
minimum
median
maximum
average
Upper and Middle
Devonian
11
Lower Cretaceous,
Jurassic and
Carboniferous
9
1.6
8.05
202.2
32.6
1.73
6.69
138.3
27.6
1.34
6.57
398.6
85.6
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Heavy Metals - Final Report
15
8. Bitumen
Around 30 minerals are present in the bitumen as trace elements. Some of these elements are in
the form of inorganic particulate phase and can be separated from bitumen by centrifugation.
Only about two thirds of the original elements remain measurable in the solids free bitumen.
Zhao et al., 2001, reported a significant decrease in Fe, Mn, Mg, Ti, Ca and Al in a bitumen
asphaltene after removal of ultra fine solids. V and Ni concentrations did not change on removal
of the solids. Some of the vanadium and nickel compounds may appear in the distillates during
processing (Strausz and Lown, 2003). Nickel, vanadium and other metals occur in such high
concentrations that companies are considering metals recovery from waste products.
Table 10 shows a comparison of the trace elements in two Athabasca bitumen samples with the
average trace element compositions of Alberta crudes. The bitumen samples were filtered prior
to analysis but the samples may have still contained some fine clay material. (Hitchon and Filby,
1983). The two bitumen samples had significantly higher content of heavy metals than Alberta
conventional crudes. The majority of the metals separate with and are present in the asphaltenes
and will concentrate in the residual oil and coke during bitumen processing.
Table 10: Comparison of Trace Elements in Athabasca bitumen and Western Canadian
crudes (Hitchon and Filby, 1983)
Element
S
Athabasca Athabasca
bitumen 1 bitumen 2
3.881
-
Crude Oil
Average
0.83
Units
%
V
Cl
Na
Fe
Ni
176.5
7.96
20.78
141.7
71.88
40.33
254.2
74.11
13.6
39.3
3.62
10.8
9.38
ppm
ppm
ppm
ppm
ppm
Zn
Co
I
Mn
Se
Hg
Cs
Br
As
Au
Sb
Cr
Rb
Sc
Eu
1349
3853
286.4
81.7
25.9
103.6
320.9
27.7
1014
377.5
190.7
9
1998
517.1
68.53
155.3
400.3
30.61
1682
720.2
199
23.2
459
53.7
719
100
51.7
50.9
4.27
491
111
0.438
6.22
93.3
148
7.76
0.935
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
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Heavy Metals - Final Report
8.1
Mercury in Bitumen
There was only limited data on mercury content in Alberta bitumen. Several samples of three
different bitumen refinery feeds were included in the study of crude sampled at the refinery inlet
discussed in Section 7.3 (Hollebone and Yang, 2007). One sample was diluted bitumen and two
were synthetic crude oil derived from bitumen. Table 11 summarizes the sulphur and mercury
content of these samples. For both the diluted bitumen and one synthetic crude, one sample was
an obvious outlier and was not included in Table 11. This limited data suggests that the process
of upgrading bitumen to synthetic crude removes in the order of 90% of the Hg from the raw
bitumen, with the mercury likely partitioned to the coke and refinery gases. The Hg content of
the synthetic crude was similar to Western Canadian crude oil feeds to refineries.
One sample of raw bitumen from the study reported by Hitchon and Filby, 1983, contained
mercury at a level of 81.7 ppb. This is significantly higher than the 5 to 10.7 ppb reported in
Table 11.
Table 11: Mercury content of bitumen refinery feeds
(Hollebone and Yang, 2007)
Sample
diluted bitumen
synthetic crude 1
synthetic crude 2
8.2
no. of
samples
5
3
6
sulphur
(weight %)
3.1 to 3.7
0.2
0.1 to 0.2
Hg
(ng/g)
5.0 to 10.7
0.4 to 0.8
0.6 to 1.6
Pathway of release to the environment
There is potential for heavy metal emissions to the environment from various steps in the
processes to produce final products from bitumen. These include:
- emissions of dissolved gas during mining,
- disposal of tailings from primary separation,
- heated oil tank storage vents,
- flaring or combustion of solution gas if present at SAGD sites,
- refinery gas combustion during upgrading and refining,
- combustion of coke or residual oil.
There is insufficient data reported in the literature to comment on emissions of heavy metals,
mercury and mercury compounds in the various potential pathways during processing of oil
sands to produce synthetic crude.
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Heavy Metals - Final Report
9. Relative Potential for Heavy Metal Emissions in Alberta
The potential for heavy metal emissions is related to the concentration as well as the amount of
annual production. Mercury is the metal of most concern for emissions to the environment and
the metal with the most information in the literature. The relative production of energy in
Alberta for natural gas, conventional crude and bitumen was discussed in Section 4.3. Table 12
uses the production figures for 2008 and the best estimate of average mercury concentration
based on information found in the literature. Coal is included in the table as coal production and
combustion to generate electricity is the largest source of man-made mercury emissions to the
environment in Alberta. By the year 2011, Alberta coal fired power plants will be required to
include systems for over 70% reduction of mercury emissions to the air.
The mercury contained in annual bitumen production is about five times that of natural gas and
conventional crude combined. Based on reported NPRI emissions to air, water and soil, bitumen
production and processing is responsible for over 85% of the mercury emissions to air, water and
soil from the Alberta oil and gas industry. Considering the planned expansion of bitumen
production and the planned capture of mercury emissions from coal, in the future bitumen
production will be a major source of mercury emissions in Alberta. Further investigation of
mercury concentration in Alberta bitumen and mercury emissions to the environment during
mining, separation and upgrading is recommended.
Table 12: Relative Production of Mercury in Alberta Oil and Gas
energy content in
2008 production
(GJ/y)
estimated Hg
concentration
Hg contained
in annual
production
(kg/y)
Hg emissions
reported to NPRI
in Alberta
(kg/y)
natural gas
4.8 x 109
0.05 µg/m3
65
0
crude
1.1 x 109
2 ppb
47
11
bitumen
3.2 x 109
8 ppb
605
82
coal
0.64 x 109
48 ppb
1560
825
coal with 70%
Hg capture
250
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Heavy Metals - Final Report
10. Conclusions and Recommendations
Natural gas, conventional crude oil and bitumen contain heavy metals in trace amounts and their
production, processing and use can contribute to emissions of heavy metals to the environment.
Due to its toxicity, mercury has been studied and characterized the most. Based on a review of
the open literature, the following observations are made on the potential for heavy metals
emissions from natural gas, oil and bitumen production and processing in Alberta:
1. Information on mercury content of Alberta natural gas was from 1972 study of mercury
in 18 natural gas wells and condensates samples. The mercury concentration in most
samples was below the detection limit of 0.08 µg/m3 for gas and 10 ppb for liquids.
Studies of U.S. gas deposits suggest that mercury in North American natural gas is
typically low, from 0.005 to 0.04 µg/m3.
2. Reported data on heavy metals content of Alberta crude oil sampled near the well head
was from a 1975 study of 88 samples. The average mercury content was 50.9 ppb, with a
range from 1.6 to 399 ppb.
3. Mercury content in conventional oil as delivered to the refinery was well characterized in
recent studies using well-tested sampling and analysis methods. The average mercury
content of Western Canadian crude feeds to refineries was 1.6 ppb.
4. Bitumen contains higher levels of trace elements than conventional crude, with most
elements associated with the asphaltenes. Most heavy metals will concentrate to the
residual oils and coke during processing. Only limited data was available for mercury
content. Based on analysis of diluted bitumen and synthetic crude feeds to a refinery,
bitumen contains 5 to 11 ppb of mercury while synthetic crude contains 0.4 to 1.6 ppb.
5. There is little information on mercury or other heavy metal concentrations in the various
pathways for emissions to the environment, such as solution gas flaring, refinery gas
combustion and tank vents.
Further work is recommended to better characterize potential heavy metal emissions to the
environment from the natural gas, conventional crude and bitumen production and processing
industry. Considering annual production rates and the estimate of mercury concentrations from
the available information, the highest priority for further work should be to better characterize
the potential emissions during bitumen production and processing. Both the natural gas and
conventional crude well head data is over 20 years old and could benefit from analysis with
newer sampling and analysis techniques with lower detection limits. In particular, the existing
data shows a significant difference between mercury concentration in Alberta crude sampled
near the wellhead and crude sampled near the inlet to refineries.
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Heavy Metals - Final Report
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