United States EPA/600/R-01/066
Environmental Protection
Agency September 2001
vvEPA Research and
Development
MERCURY IN PETROLEUM AND
NATURAL GAS: ESTIMATION OF
EMISSIONS FROM PRODUCTION,
PROCESSING, AND COMBUSTION
Prepared for
Office of Air Quality Planning and Standards
Prepared by
National Risk Management
Research Laboratory
Research Triangle Park, NC 27711
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Foreword
The U.S. Environmental Protection Agency is charged by Congress with
protecting the Nation's land, air, and water resources. Under a mandate of national
environmental laws, the Agency strives to formulate and implement actions leading to
a compatible balance between human activities and the ability of natural systems to
support and nurture life. To meet this mandate, EPA's research program is providing
data and technical support for solving environmental problems today and building a
science knowledge base necessary to manage our ecological resources wisely,
understand how pollutants affect our health, and prevent or reduce environmental risks
in the future.
The National Risk Management Research Laboratory (NRMRL) is the Agency's
center for investigation of technological and management approaches for preventing
and reducing risks from pollution that threaten human health and the environment. The
focus of the Laboratory's research program is on methods and their cost-effectiveness
for prevention and control of pollution to air, land, water, and subsurface resources,
protection of water quality in public water systems; remediation of contaminated sites,
sediments and ground water; prevention and control of indoor air pollution; and
restoration of ecosystems. NRMRL collaborates with both public and private sector
partners to foster technologies that reduce the cost of compliance and to anticipate
emerging problems. NRMRL's research provides solutions to environmental problems
by: developing and promoting technologies that protect and improve the environment;
advancing scientific and engineering information to support regulatory and policy
decisions; and providing the technical support and information transfer to ensure
implementation of environmental regulations and strategies at the national, state, and
community levels.
This publication has been produced as part of the Laboratory's strategic
long-term research plan. It is published and made available by EPA's Office of
Research and Development to assist the user community and to link researchers with
their clients.
E. Timothy Oppelt, Director
National Risk Management Research Laboratory
EPA REVIEW NOTICE
This report has been peer and administratively reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Mention of trade names or
commercial products does not constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Information
Service, Springfield, Virginia 22161.
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EPA-600/R-01-066
September 2001
Mercury in Petroleum and Natural Gas:
Estimation of Emissions from
Production, Processing, and Combustion
by
S. Mark Wilhelm
Mercury Technology Services
23014 Lutheran Church Rd.
Tomball, TX 77375
EPA Purchase Order No. 1C-R013-NASA
EPA Project Officer
David A. Kirchgessner
National Risk Management Research Laboratory
Research Triangle Park, NC 27711
Prepared for:
U.S. Environmental Protection Agency
Office of Research and Development
Washington, DC 20460
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Abstract
Mercury is a trace component of all fossil fuels including natural gas, gas condensates, crude
oil, coal, tar sands and other bitumens. The use of fossil hydrocarbons as fuels provides the main
opportunity for emissions of the mercury they contain to the atmospheric environment but other
avenues also exist in production, transportation and in processing systems. These other avenues
may provide mercury directly to air, water or solid waste streams. This document examines
mercury in liquid and gaseous hydrocarbons that are produced and/or processed in the United
States for the purpose of estimating, to the extent possible, emissions of mercury to the U.S.
environment from petroleum and natural gas.
Although the masses of petroleum and natural gas processed and consumed in the U.S. are
very large, only limited amounts of information are available concerning mercury in gas and oil
processed domestically. This report compiles existing information and data on mercury in
petroleum and natural gas and examines the current state of knowledge of the amounts of mercury
in petroleum and gas produced and imported to the U.S. In addition, the distribution and
transformation of mercury in production, transportation and processing are considered relative to
the determination of mercury in air emissions, wastewater, and products from oil and gas
processing facilities. Finally, the fates of mercury in combusted gas and liquid fuel products are
examined.
The mercury associated with petroleum and natural gas production and processing enters the
environment primarily via solid waste streams (drilling and refinery waste) and via combustion of
fuels. In total the amount may exceed 10,000 kg yearly but the present estimates are uncertain due
to lack of statistical data. The amounts in solid wastes and atmospheric emissions from combustion
are estimated to be roughly equal. Solid waste streams likely contain a much higher fraction of
mercuric sulfides or other insoluble compounds than water soluble species and thus the
bioavailability of mercury from this category is much more limited than that which derives from
combustion.
This report is intended to assist in the identification of those areas that require additional
research, especially the needs associated with measuring the concentrations of the various
chemical species of mercury in the various feedstocks and waste streams associated with the oil
and gas industry. Acquisition of additional information will be necessary if accurate estimates of the
magnitudes of mercury emissions associated with U.S. petroleum and natural gas are to be
accomplished.
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Contents
Abstract ii
Tables v
Figures vi
Abbreviations vii
Acknowledgements viii
Chapter 1 Introduction 1
References 2
Chapter 2 Background 3
References 4
Chapter 3 Oil and Gas Processed in The United States 6
Chemistry of Oil and Natural Gas 6
World Oil Production 8
U.S. Oil and Gas Production and Imports 9
Geologic Origin of Mercury in Oil and Natural Gas 14
References 14
Chapter 4 Petroleum and Natural Gas Processing 16
Petroleum Refining 16
Gas Processing 22
References 23
Chapter 5 Mercury in Petroleum and Natural Gas 24
Properties of Mercury and Mercury Compounds 24
Mercury in Hydrocarbons 25
Analytical Methods 31
Gas 31
Liquids 32
References 33
Chapter 6 Mercury in Refining and Gas Processing 35
Extraction 35
Transportation 37
Refining 37
Gas Processing 40
Mercury Removal Systems 40
References 41
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Chapter 7 Mercury Emissions from Oil and Natural Gas Production and Processing 43
Mercury Emissions to Water 43
Produced Water 43
Refinery Wastewater 44
Mercury Emissions to Air 47
Mercury Emissions Via Solid Waste Streams 49
Mercury in Crude Oil 50
Mercury in Refined Products 58
Estimate of Mercury Emissions from Refineries 59
Mercury in Combusted Gas and Estimated Emissions 61
U.S. EPA Estimates 62
References 64
Chapter 8 Data Requirements to Estimate Mercury Emissions 67
References 69
IV
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Tables
Table 2-1 Estimate of Mercury Cycling in the Biosphere 4
Table 2-2 Estimate of Point Source Mercury Discharge 5
Table 3-1 Typical Characteristics of Crude Oil 7
Table 3-2 World Production of Crude Oil, NGL and Other Liquids 8
Table 3-3 World Natural Gas Production 8
Table 3-4 U.S. Production and Reserves of Crude Oil, NGL and Natural Gas 9
Table 3-5 U.S. Crude Oil Reserves and Production 10
Table 3-6 Top Thirty U.S. Oil Fields 11
Table 3-7 Top Thirty U.S. Natural Gas Fields 12
Table 3-8 Oil Imports to U.S. Refineries 13
Table 3-9 Nomenclature and Age of Geological Strata 15
Table 4.1 Distillation Processes 17
Table 4-2 Decomposition Processes 18
Table 4-3 Unification and Rearrangement Processes 18
Table 4-4 Treatment Processes 19
Table 4-5 Refined Products 19
Table 5-1 Physical Properties of Elemental Mercury 24
Table 5-2 Solubilities and Volatilities of Mercury Compounds 25
Table 5-3 Natural Abundance of Mercury Compounds in Hydrocarbons 28
Table 5-4 Solubility of Mercury Compounds in Liquids 29
Table 5-5 Mercury Compounds in Natural Gas Condensates 29
Table 5-6 Operational Hg Speciation in Petroleum Samples 29
Table 6-1 Oil-Water Distribution Coefficients 36
Table 6-2 Total Mercury in Desalter Sludge 38
Table 6-3 Mercury Removal Systems for Hydrocarbons 42
Table 7-1 Mercury in Produced Waters 45
Table 7-2 Mercury Concentrations in Produced Water 46
Table 7-3 Pollutant Concentrations for a Typical Refinery Wastewater 46
Table 7-4 Mercury Emission Factors for Refinery Processes 49
Table 7-5 Total Mercury Concentrations in Crude Oil by NAA (1970) 52
Table 7-6 Total Mercury Concentrations in Crude Oil by NAA (1975) 52
Table 7-7 Total Mercury Concentrations in Alberta Crude Oils 53
Table 7-8 Total Mercury Concentrations in Libyan Crude Oils 53
Table 7-9 Mercury Concentrations in U.S. West Coast Crude Oils 54
Table 7-10 Total Mercury Concentrations in Crude Oils (Bloom 2000) 54
Table 7-11 Mercury Concentrations in Crude Oils Processed in NJ Refineries 55
Table 7-12 Total Mercury Concentrations in Crude Oils (EC 2000) 56
Table 7-13 Mercury Content of Crude Oils Processed in Canada 57
Table 7-14 Summary of THg in Crude Oils and Gas Condensates 57
Table 7-15 Summary of THg in Refined Products 58
Table 7-16 Summary of Mercury Concentrations in Fuel Oils 58
Table 7-17 Estimates of Mercury in Crude Oil and Refined Products 60
Table 7-18 Fuels from Crude Oil Used by Refineries 61
Table 7-19 Mercury in Major Crude Oil Imports 61
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Table 7-20 Total Hg Concentration in U.S. Pipeline Gas 62
Table 7-21 U.S. EPA Estimates of Mercury in Fuel Oil 64
Table 7-22 Mercury Concentration in Oils Used as Fuels 64
Table 8-1 Summary of Estimates for Mercury Emissions 69
Figures
Figure 4-1
Figure 4-2
Figure 4-3
Figure 4-4
Figure 4-5
Figure 5-1
Figure 5-2
Figure 6-1
Figure 6-2
Figure 6-3
Figure 6-4
Typical Refining Process
Primary Distillation
Vacuum DistiNation
Segregated Water Treatment System for a Typical Refinery
Gas Process Schematic
20
21
21
22
23
Solubility of Elemental Mercury in Normal Alkanes 30
Distribution of Mercury Compounds in Liquids 30
Primary Separation 37
Crude Oil Desalting 38
Mercury (Total) in Distilled Products 39
Distribution of THg Concentrations in Petroleum Coke 39
VI
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Abbreviations
API
BP
bpd
bpy
CVAA
CVAF
DFO
DOE
EOR
EPA
GF
HPLC
ICP
LNG
Mg
MS
NAA
NGL
NPDES
OAR
OPEC
ORD
OSWER
OW
PBT
RFO
SCF
IDS
TEG
TMDL
TRI
USGS
UV
VP
American Petroleum Institute
Boiling Point
barrels per day
barrels per year
Cold Vapor Atomic Absorbance
Cold Vapor Atomic Fluorescence
Distillate Fuel Oil
(U.S.) Department of Energy
Enhanced Oil Recovery
(U.S.) Environmental Protection Agency
Gulf (of Mexico)
High Performance Liquid Chromatography
Inductively Coupled Plasma
Liquefied Natural Gas
Megagram (106 grams)
Mass Spectroscopy
Neutron Activation Analysis
Natural Gas Liquids
National Pollutant Discharge Elimination System
Office of Air and Radiation (U.S. EPA)
Organization of Petroleum Exporting Countries
Office of Research and Development (U.S. EPA)
Office of Solid Waste and Emergency Response (U.S. EPA)
Office of Water (U.S. EPA)
Persistent, Bioaccumulative, Toxic
Residual Fuel Oil
Standard Cubic Foot
Total Dissolved Solids
Triethyleneglycol
Total Maximum Daily Load
Toxic Release Inventory
United States Geological Survey
Ultraviolet
Vapor Pressure
VII
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Acknowledgements
1. Michael Aucott (New Jersey Department of Environmental Protection) and the New Jersey
Mercury Study Committee for data on mercury in crude oils processed by New Jersey
refineries.
2. David Kirchgessner (U.S. EPA/ORD/NRMRL-RTP) for information on methane emissions
in natural gas processing.
3. Wenli Duo for the report and data: "Mercury Emissions From The Petroleum Refining
Sector In Canada," for Environment Canada, Trans-boundary Air Issues Branch,
Hazardous Air Pollutants Program.
4. Nicolas Bloom (Frontier Geosciences) for numerous helpful suggestions and discussions.
5. Robert Kelly (Analytical Chemistry Division, Chemical Science and Technology Laboratory,
National Institute of Standards and Technology) for helpful discussions.
6. Bob Morris (Coastal Corporation) for a copy of his paper "New TRI Reporting Rules on
Mercury," presented at the National Petroleum Refiners Association Meeting, San Antonio,
Texas (September, 2000).
7. George N. Breit (U.S. Geological Survey, Denver Federal Center) for data and discussions
concerning mercury in produced water.
8. David E. Panzer (Minerals Management Service, Camarillo, CA) for data on mercury in
produced water.
9. Bob Finkelman (U.S. Geological Survey) for information on mercury in coal and information
on geologic origins of mercury in fossil fuels.
10. Herb Tiedemann (National Petroleum Technology Office, Tulsa, OK) for data on mercury in
the Strategic Petroleum Reserve.
11. Karin Ritter (American Petroleum Institute) for providing several API reports.
VIM
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Chapter 1
Introduction
Discharges of mercury to the environment from
industrial sources are recognized as significant
contributors to the accumulations of mercury in aquatic
ecosystems. The reasons are many but they mainly
stem from the current understanding of the global
mercury cycle and the chemical and biological
mechanisms that account for the transformation of
atmospheric mercury and mercury in industrial
wastewaters to the methylmercury in fish (U.S.
EPA/ATSDR 1996). Further, the toxicity of
methylmercury to humans and piscivorous mammals
and the effects of inorganic mercury species on aquatic
organisms are now firmly established (NRC 2000, U.S.
EPA 1996). The comprehensive reviews of the
geochemical aspects of mercury (EPA 1997a, Porcella
1994, Morel et al. 1998) strongly suggest that mercury
originating from human activities is a major contributor
to the global cycle and hence to the resultant
methylmercury in the aquatic food chain. A general
overview of the geochemical mercury cycle and its
anthropogenic contributions are provided in Chapter 2.
Mercury and its common chemical forms are officially
designated by the U.S. EPA as persistent,
bioaccumulative and toxic (PBT) pollutants, which are
defined as those substances that are persistent
(months to years) in the environment, accumulate and
concentrate in biota and that are toxic to organisms
(EPA 1997b, EPA 1999). Mercury and its compounds
are thus the subjects of numerous regulations that
originate from both federal and regional agency
jurisdictions. The statutes that regulate mercury
discharges to the environment include provisions based
on both human and aquatic life concerns.
Under the general program to develop action plans for
PBT pollutants, the U.S. EPA has constructed an
action plan for mercury that focuses on regulatory
actions, enforcement and research to characterize and
reduce the risks associated with mercury. As part of the
mercury action plan, U.S. EPA Office of Research and
Development (EPA/ORD) has developed a mercury
research and monitoring strategy to facilitate
coordination and direction of research efforts involving
mercury. Some of the research topics currently under
investigation include source evaluation, emission
characterization, atmospheric transport and fate,
deposition, fate in terrestrial and aquatic media,
bioaccumulation, ecological toxicity, health effects,
exposure, monitoring, risk management, control and
remediation.
The EPA/ORD research plan includes the development
and evaluation of emission control technology for coal-
fired utilities and other mercury emitters in support of
the Office of Air and Radiation (OAR) and the Office of
Solid Waste and Emergency Response (OSWER)
programs. This effort includes attention to speciation
issues, control option costs and the disposal of the
mercury-containing wastes resulting from the control
options. Also included are research efforts directed to
the development of fate, transport and transformation
data in support of the Office of Water (OW)
determinations of total maximum daily loads (TMDLs)
for mercury.
While the issues involving mercury emissions from coal
and waste combustion are currently under intensive
investigation, U.S. EPA acknowledges that little is
known about mercury emissions from the petroleum
and natural gas industries (EPA 1997b). Given the
magnitude of petroleum and natural gas consumption
in the U.S., it would seem prudent to have accurate
data on the ranges and mean amounts of mercury in
petroleum and gas produced in, and imported to, the
U.S. In addition, the distribution and transformation of
mercury in production, transportation and processing
are likewise important to the determination of mercury
in air emissions, wastewater, and products from oil and
gas processing facilities. Finally, the fate of mercury in
combusted fuel products needs definition.
EPA/ORD has initiated a program to better define the
issues related to mercury in the natural gas and oil
industries. This document was commissioned by U.S.
EPA/ORD to document the current level of
understanding of the factors that influence the role of
petroleum and natural gas as contributing sources of
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mercury. Several major questions are addressed in the
discussion to follow:
• What are the estimated ranges and mean
amounts of mercury (total) in oil and natural
gas?
• What are the major sources of mercury in
hydrocarbons as categorized by geology,
location of origin and hydrocarbon type?
• What chemical species of mercury are present
in petroleum and natural gas and how do they
distribute in production, processing and refining
systems?
• What is the current knowledge concerning the
amounts of mercury that exist in the major
egression pathways from petroleum processing
including wastewater, air emissions, solid
waste and fuel products?
• What are the estimated magnitudes of water
and atmospheric mercury emissions from
petroleum processing?
• What are the major deficiencies in the current
knowledge and what data are required to
improve understanding?
Strategies to reduce anthropogenic mercury emissions
should be based on the known amounts of mercury in
industrial emissions. The compilation of information that
follows is intended to assist government and industry to
define the research and data gathering that may be
necessary to improve the current level of understanding
concerning mercury in fossil fuels.
In the discussion to follow, an effort has been
made, when referring to the concentration of
mercury in liquids and solids, to apply the units
"ppb" meaning parts per billion by weight with
correction for density of liquids and solids. Such
concentrations are referred to as THg meaning total
mercury per unit weight of the matrix. This
designation derives from the fact that mercury
analysis methods typically do not distinguish
forms and all forms of mercury in a sample are
summed in the procedures employed. Thus the
term THg (ppb) means the summed (by the
analytical method) concentration of mercury in a
sample of measured or calculated weight.
For gases, the units are typically jig/m3 meaning \ig
per standard cubic meter of the gas. It is
acknowledged that many gas concentrations
reported in the literature are not corrected to
standard conditions (which have different
interpretations for chemists and engineers). No
attempt has been made to attempt such
corrections, which are negligible in comparison to
the analytical uncertainties for such values. The
term THg for gases is not applied as gas analysis
methods (as historically practiced) are incapable to
distinguish volatile forms. Gas concentrations infer
total amounts in that particulate mercury is seldom
encountered in analysis of natural gas streams.
Exceptions do exist and are acknowledged but are
not typically identified in the text.
References
Morel, F., Kraepiel, A., and M. Amyot, 1998, The
Chemical Cycle and Bioaccumulation of Mercury,
Annu. Rev. Ecol. Syst., 29:543.
National Research Council, 2000, Toxicological Effects
of Methylmercury, National Academy Press,
Washington, DC.
Porcella, D., 1994, Mercury in the Environment,
Biogeochemistry in Mercury Pollution, Integration and
Synthesis, Watras, C. and J. Huckabee, eds., Lewis
Publishers, Boca Raton, FL.
U.S. EPA, 1996, 1995 Updates: Water quality criteria
documents for the protection of aquatic life in ambient
water, EPA/820/B-96/001 (NTIS PB98-153067),
Office of Water, Washington, DC.
U.S. EPA, 1997a, Mercury Study Report to Congress,
EPA/452/R-97/003 (NTIS PB98-124738), Office of Air
Quality Planning and Standards, Research Triangle
Park, NC and Office of Research and Development,
Washington, DC.
U.S. EPA, 1997b, EPA Strategic Plan, EPA/190/R-
97/002 (NTIS PB98-130487), Office of the Chief
Financial Officer, Washington, DC.
U.S. EPA, 1999, PBT Final Rule Effective for Reporting
Year 2000, 64 FR 58666, October 29, 1999,
Washington, DC.
U.S. EPA and Agency for Toxic Substances and
Disease Registry (ATSDR), 1996, National Alert on
Metallic Mercury Exposure, Washington, DC.
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Chapter 2
Background
The geochemical mechanisms by which mercury cycles
in the environment are generally known in concept but
some aspects of the cycle are incompletely understood
in detail. The level of understanding, however, has
improved markedly over the last 10 years and many of
the aspects of the cycle can be described with a fair
degree of confidence. The term cycle is used because
of the movement of mercury between major pools
(major pools are air and water; geologic mercury is not
considered a pool but contributes to the cycle) at
significant rates of flux (see Table 2-1). The movement
is coincident with chemical transformations of mercury
that are produced by physical, chemical and biologic
forces. While the total amount of mercury in the world
as a whole is constant, the amount in the biosphere is
not. The amount of mercury mobilized and released
into the biosphere has increased markedly over time,
especially from human activities since the beginning of
the industrial age.
Contributions of mercury to the biosphere originate
from both natural and anthropogenic sources. The
natural sources are volcanic activity; erosion of terrain;
dissolution of mercury minerals in oceans, lakes and
rivers; and a variety of other avenues that are not
related to human activities. Mercury also enters the
biosphere from industrial activities through its use as a
raw material and from combustion of fossil fuels and
waste. The use of mercury as an ingredient in
manufactured products has been reduced in recent
years and likely will be completely discontinued within
the next decade or two.
The atmosphere is considered important because it is
the mobilizing pathway for mercury deposition to
remote regions not contiguous with industrial activities
and thus provides the avenue for introduction of
mercury to otherwise pristine environments. The
estimate of the total annual global input to the
atmospheric pool from all sources including natural,
anthropogenic, and oceanic emissions is approximately
5,000 Mg (see Table 2.1, evasion 2,000 Mg, terestrial
3,000 Mg).
Most of the mercury in the atmosphere exists as
elemental mercury vapor, which can circulate in the
atmosphere for more than a year and thus can be
transported to regions far from the source of emission.
Mercury in rainfall is the primary avenue of egress from
the atmosphere to the surface. Mercury in surface
waters can be re-emitted back to the atmosphere as a
vapor (evasion). From land, mercury re-enters the
atmosphere from the transpiration of plants or as
mercury adsorbed to mobilized particles. As it cycles
between the atmosphere, land, and water, mercury
undergoes numerous chemical and physical
transformations, some of which are not completely
understood in a quantitative fashion.
While most of the mercury in the atmosphere is
elemental, most of the mercury in water, soil,
sediments, or plants and animals is in the form of
inorganic mercury salts and organometallics (mostly
methylmercury). Bacteria in sediments produce most of
the methylated form of mercury but the exact
mechanisms have yet to be completely defined.
Although its concentration is a very small percentage of
the amount in water, methylmercury concentrates in the
aquatic food chain. Predatory organisms at the top of
the aquatic food web acquire and accumulate the
methylmercury in their diets and present elevated
concentrations. While the concentration at the bottom
of the aquatic food chain may be at the low parts per
trillion level, at the top, fish tissue can present mercury
concentrations in excess of 1 ppm. Bioconcentration
factors are thus on the order of 104 to 105.
Inorganic mercury (oxidized and elemental) is less
efficiently absorbed and more readily eliminated from
the body than methylmercury and, therefore, does not
tend to bioaccumulate in fish or other organisms.
Inorganic mercury (mercuric ion, mercury complexed to
inorganic ligands) is toxic to organisms, however, and is
the dominant toxic species in water. Although
environmentally important, the toxicity of inorganic
mercury is secondary in consideration to its role as the
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species that is acted on by bacteria to produce
methylmercury that concentrates in the aquatic food
chain. It is the rising amount of methylmercury in fish
and the known effects of inorganic mercury on aquatic
organisms that are the principal reasons to reduce the
human contribution to the mercury cycle. Since natural
emissions are largely outside the domain of human
influence, attention is focused on man's contribution
and on ways to minimize it.
The vast majority of the mercury that enters the global
mercury cycle from human activities comes from
combustion of waste and fuels. According to the U.S.
EPA (1997) estimates (see Table 2-2), of the
approximately 140 Mg of mercury emitted to the
environment in the U.S. from point sources in the year
analyzed (1994-95), fully 125 Mg originated from
combustion. According to the EPA estimates, the
breakdown for combustion is roughly 50/40/10 percent
for coal burning, waste incineration and fuel oil
combustion (U.S. EPA 1997).
The U.S. total mercury emissions from point sources of
125 Mg/y compares to approximately 2,000 Mg/y
globally. The U.S. percentage of the world mercury
emission total is less than the U.S. percentage of its
energy usage. The discrepancy derives from the fact
that waste disposal and coal combustion are more
prevalent in countries outside the U.S.
Major R&D efforts are now being directed to developing
systems and process modifications to reduce mercury
emissions from U.S. combustion sources. For waste
incinerators and coal-fired boilers, some of the new
technology is now being applied. The use of mercury
removal equipment for coal-fired boilers was recently
mandated and full implementation should occur by
2005. Extension of regulations to oil-fired boilers is
currently under review.
U.S. EPA (1997) acknowledges that the estimates for
mercury in petroleum (fuel oil) are highly suspect due to
the fact that data are lacking both for mercury in crude
oil and in many of the fuel products derived from it.
Given that the amount of oil consumed in the U.S. is
roughly the same as the amount of coal burned, it
would seem prudent to obtain a more precise estimate
of mercury in crude oil so as to be able to estimate
atmospheric mercury emissions that originate from
refineries and liquid fuels.
References
U.S. EPA, 1997, Mercury Study Report to Congress,
EPA/452/R-97/003 (NTIS PB98-124738), Office of Air
Quality Planning and Standards, Research Triangle
Park, NC and Office of Research and Development,
Washington, DC.
Table 2-1 - Estimate of Mercury Cycling in the Biosphere
(U.S. EPA 1997)
Rates, Amounts, Concentrations
Pools
Ocean
Air
Flux (yearly)
Ocean to Air
Air to Ocean
Air to Ground
Ground to Air
Human Production
Sink (yearly)
Marine precipitation
11x10 kg (0.5 - 3 ppt ocean; 1-10 ppt fresh water)
5 x 106 kg (1 -10 ng/m3; mean lifetime > 1 year)
2 x 106 kg/y (evasion)
2 x 106 kg/y (marine deposition)
3 x 106 kg/y (terrestrial deposition)
3 x 106 kg/y (natural 1 + man 2)
4x 106 kg/y (local 2 + air 2)
0.2x 10bkg/y
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Table 2-2 - Estimate of Point Source Mercury Discharge
(U.S. EPA 1997)
U.S. year 1994-95 Mg/y % of Total (1)
Point Sources
Combustion sources
Utility boilers
Coal
Oil
Natural gas
Municipal waste incinerators
Commercial/industrial boilers
Coal
Oil
Medical waste incinerator
Hazardous waste incinerator
Residential boilers
Oil
Coal
Sewage Sludge Incinerators
Wood-fired boilers
Crematories
Manufacturing Sources
Miscellaneous Sources
141.0
125.3
47.2
(47.0)
(0.2)
(<0.1)
26.9
25.8
(18.8)
(7.0)
14.6
6.4
3.3
(2.9)
(0.4)
0.9
0.2
<0.1
14.4
1.3
96.9
86.9
32.8
(32.6)
(0.1)
(0.0)
18.7
17.9
(13.1)
(4.9)
10.1
4.4
2.3
(2.0)
(0.3)
0.6
0.1
0.0
10.0
0.9
(1) Total for percentage amounts includes non-point sources
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Chapters
Oil And Gas Processed in the United States
Fossil fuels include coal, petroleum, natural gas, shale
oil and several other forms of bituminous fuel materials
that were produced by the decay of plant remains over
geological time (Speight 1999). Most of the world's
energy is derived from the fossil fuels with smaller
amounts of energy coming from nuclear, wind, solar
and hydroelectric sources. Fossil fuels are projected to
be the major sources of energy for the next 50 to 100
years.
Mercury is a trace component of all geologic
hydrocarbons. Its origin relative to the origin of the oil
and gas in which it is found, and the geological reasons
for its occurrence in the various types of fossil fuels are
largely unexplored topics. In the effort to account for
mercury in petroleum and natural gas, it is useful to
examine mercury in the context of petroleum chemistry
in general and in the context of the extraction and
product manufacturing processes for petroleum and
natural gas (Chapter 4). Although of interest from a
geological standpoint, the quantities of fuels produced
from shale oil, tar sands, and other forms of bitumen are
small relative to coal, crude oil and natural gas. The
occurrence of mercury in shale oil and tar sands is
largely undocumented and will not be discussed.
Chemistry of Oil and Natural Gas
The distinction between petroleum (taken to mean
liquid hydrocarbons when extracted from the earth) and
natural gas (taken to mean material in a purely gaseous
state when extracted) is somewhat arbitrary and
inconvenient. The industrial processes that convert
liquids to products are different from those that
separate gases, however, and the distinction is
preserved for discussion of processing. It should be
stated that liquids and gas are co-produced from almost
all gas and petroleum reservoirs and the distinction
between a gas field and an oil field rests on the relative
proportions of produced phases and the molecular
weight distribution of the compounds produced.
Crude oils are complex mixtures containing many
different hydrocarbon compounds. The chemical
composition and physical properties of crude oil vary
dramatically from one field to another. Crude oils range
in consistency from water-like liquids to semi-solids,
and in color from clear to black. An average crude oil
contains about 84% carbon, 14% hydrogen, 1-3%
sulfur, and less than 1% each of nitrogen, oxygen,
metals, and salts. The types of organic molecules
contained in crude oils are numerous (more than
10,000 have been detected) but the major types are
saturated and unsaturated straight chain and cyclic
hydrocarbons with lesser amounts of substituted (for
carbon or hydrogen) molecules. Substitutional moieties
include (in order of occurrence) sulfur, oxygen, nitrogen
and metals.
Crude oils are generally classified as paraffinic,
naphthenic, or aromatic based on the proportional
dominance of hydrocarbon molecules in these
categories. Crude oil assays are used to classify crude
oils and are based on either the distillation profile or on
specific gravity and boiling points. More comprehensive
crude assays determine the value of the crude (i.e., its
yield and quality of useful products) and processing
parameters. Crude oils are usually grouped according
to the products they yield. Table 3-1 provides examples
of typical characteristics of common crude oils
according to the compositional categories.
Paraffinic hydrocarbon compounds found in crude oil
are saturated (maximum hydrogen bonding) and can be
either straight chains (normal) or branched chains
(isomers) of carbon atoms. The lighter, straight-chain
paraffin molecules (alkanes) are found in gases and
paraffin waxes. Isomer paraffins are usually found in
heavier fractions of crude oil.
Aromatics are unsaturated compounds having at least
one benzene ring as part of their molecular structure.
Naphthalenes are fused double-ring aromatic
compounds. Complex aromatics containing three or
more fused aromatic rings are found in heavier crude
-------
are found in all fractions of crude oil and include
monocycloparaffins (mostly C4-C6) and
dicycloparaffins (mostly C6-C10)
Crude oils are also defined in terms of American
Petroleum Institute (API) gravity, which is a measure of
density. Crude oils with lower percentages of carbon
(lighter density, less viscous, higher API gravity) are
richer in paraffins and yield greater proportions of
gasoline and light petroleum products. Crude oils with
higher percentages of carbon (heavier, more viscous,
lower API gravity) usually have greater amounts of
aromatics. Crude oils that contain hydrogen sulfide or
other reactive sulfur compounds are referred to as
"sour." Those with less reactive sulfur are called
"sweet."
Sulfur in crude oil can take the form of hydrogen
sulfide, as mercaptans, sulfides, disulfides and
thiophenes or as elemental sulfur. All crude oils contain
sulfur but in differing amounts and types. Heavier crude
oil fractions typically contain more total sulfur. Oxygen
compounds such as phenols, ketones, and carboxylic
acids also occur in crude oils in varying amounts but
usually in much lesser proportions than sulfur
compounds. Nitrogen is found in lighter fractions of
crude oil as basic compounds, and more often in
heavier fractions of crude oil as non-basic compounds.
Several trace metals (in addition to mercury) are
sometimes present in crude oil and these include
nickel, iron, arsenic and vanadium. Crude oils often
contain inorganic salts such as sodium chloride,
magnesium chloride, and calcium chloride in
suspension or dissolved in entrained water (brine).
Crude oils when extracted from the earth contain
suspended inorganic material including silicates (sand)
and carbonates. The distribution of particle sizes varies
considerably from colloids to fine sand. The more
viscous the oil the more suspended material it typically
holds.
Natural gas generally is predominantly methane
(usually > 90%) with lesser amounts of propane and
butanes (C1 - C5, 1-5 carbon atoms per molecule).
Liquids co-produced from natural gas are mostly C5 to
C10 and have little aromatic character. Carbon dioxide
and hydrogen sulfide are common components of
natural gas. Mercury (elemental) is a unique metallic
component of natural gas because of its volatility.
Natural gas is geologically different from most oil in the
sense that it is a less mature material. Less mature
means that gas hydrocarbon reservoirs have been
subjected to subterranean temperature and pressure
over shorter periods of geologic time. As a result the
liquids co-produced with natural gas are less diverse as
compared to light crude oils and contain much higher
percentages of paraffinic compounds.
Table 3-1 - Typical Characteristics of Crude Oil
(Speight 1999)
Crude source
USA -Mid-continent
North Sea -Brent
Nigeria -Light
Saudi Arabia -Light
USA -W. Texas Sour
Venezuela -Light
Saudi Arabia -Heavy
Venezuela -Heavy
Paraffins
(% vol)
-
50
37
63
46
52
60
35
Aromatics
(% vol)
-
16
9
19
22
14
15
12
Naphthenes
(% vol)
-
34
54
18
32
34
25
53
Sulfur
(% wt)
0.4
0.4
0.2
2.0
1.9
1.5
2.1
2.3
API
gravity
40
37
36
34
32
30
28
24
-------
World Oil Production
Tables 3-2 and 3-3 compile the world production of
petroleum liquids (crude oil and natural gas liquids, NGL)
and natural gas for 1998 (U.S. DOE 2000). Within
regions of the world, oil and gas vary considerably in
composition reflecting the geological characteristics of
the strata of origin. The world produces about 27 billion
barrels (1 barrel = 159 liters) of oil and about 80 trillion
standard cubic feet (SCF = 0.0283 standard m3) of gas
yearly. Major exporting countries (producing and selling
more oil and gas than they consume) are those in the
Middle East, Venezuela and in Africa. Major importing
countries are Japan, China, India and the United States.
Gas is imported primarily in liquid form (LNG, liquefied
natural gas) and mainly by Japan and Singapore as
feeds to petrochemical manufacture.
While global reserves of both oil and gas continue to
increase, the recent rate of natural gas discovery and
production has increased more rapidly due to its
preference as a clean fuel and the improving
infrastructure for its transportation to markets (USGS
2000). In the U.S. this is especially true with gas fields
accounting for the majority of new hydrocarbon
reserves.
Table 3-2 -World Production of Crude Oil, NGL and Other Liquids (1998)
(U.S. DOE 2000)
Region/Country
Rate (1000 b/d)
North America
Canada
Mexico
United States
Central & South America
Western Europe
Eastern Europe & Former U.S.S.R.
Middle East
Africa
Far East & Oceania
World Total
15,495
2,694
3,523
9,278
6,974
6,999
7,454
22,454
7,851
7,926
75,152
Table 3-3 -World Natural Gas (dry) Production (1998)
(U.S. DOE 2000)
Region/Country
,12
Rate(10'^SCF/y)
North America
Canada
Mexico
United States
Central & South America
Western Europe
Eastern Europe & Former U.S.S.R.
Middle East
Africa
Far East & Oceania
World Total
26.17
6.04
1.27
18.86
3.09
9.66
25.16
6.61
3.70
8.58
82.97
-------
United States Oil and Gas Production and
Imports
The United States currently produces about 40 percent
of the liquids processed by U.S. refineries (U.S. DOE
2000). About 60 percent of crude oil processed by U.S.
refineries is imported. A smaller amount of natural gas
is imported as a percentage of gas processed. Total
amounts of oil and gas produced in U.S. are compiled
in Table 3-4 and by State in Table 3-5. The top 30 U.S.
oil and gas fields by production in 1998 are listed in
Tables 3-6 and 3-7.
About 30 major fields account for about half of U.S.
crude oil production (see Table 3-6). Most of these
fields were discovered prior to 1990. Newer production
is found mostly offshore in either State or Federal
waters, mostly in the deeper waters of the Gulf of
Mexico. The range of geology of U.S. production spans
numerous formation types. Field size is characterized
by recoverable reserves defined as the amount of oil
calculated to be obtainable by conventional extraction
techniques. The largest producing oil fields in the U.S.
at present are located on the North Slope of Alaska.
Large gas reserves are found in New Mexico, Texas
and offshore Gulf of Mexico, with the newer production
originating offshore. The relationship between gas
production rates and gas reservoir size (field size) is
more uniform than that for oil because of the variability
of oil viscosity and weight as opposed to gas. Gas
production from the top 30 gas fields (Table 3-7)
accounts for about one third of total U.S. production
(1998).
The trend toward increasing U.S. imports of oil is due to
the fact that the terrestrial regions of the continental
U.S. have been thoroughly explored and the majority of
major fields have been discovered. Those that may
remain are more likely to be found in deep offshore
waters and in arctic regions. The cost of U.S. frontier oil
exploration and production translates to a price per
barrel that is higher than the price of oil that can be
presently purchased in world markets. Since refineries
naturally purchase oil having the lowest cost, the trend
to imports is likely to continue as long as the supply and
quality of oil in the global market is high and as long as
imported oil is lower in cost than new domestic
supplies.
Imported crude oils are compiled in Table 3-8. The
major sources of crude oil imported to the United States
are those that originate in the Middle East, Venezuela,
the west coast of Africa, Canada and Mexico. Imported
crude oil accounts for about 60 percent of crude oil
processed by U.S. refineries and is roughly equally
divided between OPEC (oil producing and exporting
countries) and non-OPEC sources.
Table 3-4 - U.S. Production and Reserves of Crude Oil,
NGL and Natural Gas (1998)
(U.S. DOE 2000)
Production
Reserves
Oil (million barrels)
Natural Gas (billion SCF)
Gas Liquids (million barrels)
Imported (OPEC "') Oil (million barrels)
Imported (Non- OPEC) Oil (million barrels)
1,991
18,720
833
1,500
1,600
21,034
164,041
7,524
(1) OPEC - Organization of Petroleum Exporting Countries
-------
Table 3-5 - U.S. Crude Oil Reserves and Production
(1998, 106 Barrels)
(U.S. DOE 2000)
State or Region
Alaska
Lower 48 States
Alabama
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
New Mexico
North Dakota
Ohio
Oklahoma
Pennsylvania
Texas
Utah
West Virginia
Wyoming
Federal Offshore
Pacific (California)
Gulf of Mexico (Louisiana)
Gulf of Mexico (Texas)
Miscellaneous
U.S. Total (1998)
Reserves
12/31/97
5,161
17,385
47
45
3,750
198
91
92
10
238
20
714
68
183
159
21
735
279
43
605
17
5,687
234
26
627
3,477
528
2,587
362
19
22,546
Production
1998
437
1,554
7
7
270
20
6
10
1b
34
2
83
8
19
14
3
59
33
6
62
1
417
14
1
58
417
45
336
36
2
1,991
10
-------
Table 3-6 - Top Thirty U.S. Oil Fields
(U.S. DOE 2000)
Rank by
Reserves
1
3
2
15
6
4
9
40
10
18
13
5
8
23
50
44
61
21
14
60
54
7
11
12
28
24
35
25
58
14
Field Name
Prudhoe Bay
Kuparuk River
Midway-Sunset
Point Mclntyre
Kern River
Belridge South
Mississippi Canyon Block 807
Garden Banks Block 426
Milne Point
Green Canyon Block 244
Spraberry Trend Area
Yates
Elk Hills
Wilmington
Viosca Knoll Block 990
Niakuk
Ewing Bank Block 873
Cymric
Endicott
Giddings
Viosca Knoll Block 956
Wasson
Slaughter
Hondo
East Texas
Lost Hills
Seminole
Pescado
Eugene Island SA Block 330
Levelland
Total Production of Top 30
Location
AK
AK
CA
AK
CA
CA
GF(1)
GF
AK
GF
TX
TX
CA
CA
GF
AK
GF
CA
AK
TX
GF
TX
TX
CA
TX
CA
TX
CA
GF
TX
Discovery
Year
1967
1969
1901
1988
1899
1911
1989
1987
1982
1994
1950
1926
1919
1932
1981
1984
1991
1916
1978
1960
1985
1937
1937
1969
1930
1910
1936
1970
1971
1945
1998 Production
(106 barrels)
222.0
91.8
49.6
47.6
46.8
44.9
43.2
26.5
20.4
20.2
20.1
19.3
19.3
19.0
18.6
18.5
18.1
17.7
17.0
16.7
16.5
16.3
14.9
13.9
13.8
11.5
11.5
11.1
10.2
10.0
927
(1)GF = Gulf of Mexico
11
-------
Table 3-7 - Top Thirty U.S. Natural Gas Fields
(U.S. DOE 2000)
Rank by
Reserves
1
2
3
4
15
6
7
11
12
10
79
21
46
19
52
51
25
37
45
53
43
36
27
22
23
29
17
41
26
66
(1)
Field Name
Blanco / Ignacio-Blanco
Basin
Hugoton Gas Area
Prudhoe Bay
Giddings
Carthage
Mobile Bay
Antrim
Panhandle West
Watte n burg
Matagorda Island Block 623
Elk Hills
Garden Banks Block 426
Panoma Gas Area
McAllen Ranch
Anschutz Ranch East
Whitney Canyon
Viosca Knoll Block 956
Bob West
Indian Basin
McArthur River
Vaquillas Ranch
Strong City District
Spraberry Trend Area
Oak Hill
Mocane-Laverne Gas Area
Red-Oak Morris
Watonga-Chickasha Trend
Gomez
Waltman
Total of Top 30
GF = Gulf of Mexico
Location
NM&CO
NM
KS & OK & TX
AK
TX
TX
AL
Ml
TX
CO
GF(1)
CA
GF
KS
TX
UT&WY
WY
GF
TX
NM
AK
TX
OK
TX
TX
OK & KS & TX
OK
OK
TX
WY
Discovery
Year
1927
1947
1922
1967
1960
1936
1979
1965
1918
1970
1980
1919
1987
1956
1960
1980
1978
1985
1990
1963
1968
1978
1972
1953
1967
1947
1910
1948
1963
1959
1998 Production
(109SCF)
718.1
662.6
468.6
252.7
225.6
222.7
149.4
136.0
123.2
100.9
100.3
98.0
92.8
92.7
84.7
80.1
76.2
74.6
74.3
73.4
72.5
71.6
70.5
69.2
66.5
66.3
64.6
64.6
63.5
56.6
4573
12
-------
Table 3-8 - Oil Imports to U.S. Refineries
(U.S. DOE 2000)
Arab OPEC
Algeria
Iraq
Kuwait
Qatar
Saudi Arabia
United Arab Emirates
Other OPEC
Indonesia
Nigeria
Venezuela
Non OPEC
Angola
Argentina
Australia
Brunei
Cameroon
Canada
China, PRC
China, Taiwan
Colombia
Congo
Ecuador
Egypt
Gabon
Guatemala
Japan
Korea
Malaysia
Mexico
Norway
Peru
Russia
Trinidad and Tobago
Turkey
United Kingdom
Yemen
Other
TOTAL
Crude Oil
1000 b/d
2,053
10
336
300
1
1,404
3
2,116
50
609
1,377
4,427
465
80
31
23
1
1,209
25
-7
349
70
98
11
207
23
-5
-24
26
1,321
221
41
9
53
0
161
4
34
8,596
(3.1 x109b/v)
LPG
1000 b/d
53
50
3
11
11
87
108
-1
-1
-23
6
6
-8
151
(0.06x109b/v
13
-------
Geologic Origin of Mercury in Oil and
Natural Gas
It would be useful to understand the geologic origin of
mercury in hydrocarbons so as to obtain some
predictive capability for estimation of the amounts in
regional sources. At present this task is difficult
because of the lack of data on total mercury and
species concentrations in many of the major oil and gas
fields in the world. In addition, much of the data that
does exist are uncertain in accuracy (discussed in
Chapter 5) and insufficiently documented as to exact
geologic origin.
Petroleum and natural gas occur throughout the upper
portion of earth's crust. Most oil and gas has been
discovered at depths that do not exceed 10,000 meters.
The earth's crust is divided into strata that are
categorized in order of age (Table 3-9). These divisions
are distinguished by compositions that are specific to
the conditions of formation and include the nature and
type of organic debris, fossils, minerals, and other
characteristics they contain. Carbonaceous materials,
including oil and natural gas, occur in all geological
strata from the Precambrian onward (Tiratsoo 1984).
Crude oil and natural gas originate from geological
formations associated with ancient basins (locations of
accumulation of ancient organic material). The basin
geology is referred to as the source rock. Basins are
characterized as marine (salt water), lacustrine (fresh
water) or terrestrial. It is generally believed that the
accumulation of petroleum in reservoirs occurred by
transformation (maturation) of the source organic
material to molecular hydrocarbons with the process
being assisted by heat and pressure from burial of the
original deposits. Subsequent hydrocarbon fluid
migration to locations of accumulation (traps) accounts
for the discovery of petroleum in porous reservoirs. The
chemical and geologic factors that account for the
origin of petroleum and its location of discovery are the
focus of a wide body of science and technology, so
large in fact that a concise summary is not possible
here.
There are few if any attempts in published literature to
account for the origin of mercury in petroleum. Mercury
in coal is associated with pyrites that are both syngenic
and epigenic with coal (Toole-O'Neil et al. 1999). One
possible syngenic origin of mercury in petroleum and
coal is atmospheric deposition to the region of organic
genesis. Rates of ancient atmospheric mercury
deposition are unknown, however. Present day rates of
atmospheric mercury deposition are on the order of 10
ug/m2-year, but ancient rates are likely lower. Volcanic
activity is a possible source of atmospheric deposition
also.
As will be discussed in later sections, the range of total
mercury concentrations in oil is thought to be wider
than that for coal and this variation suggests that
atmospheric deposition to genetic organic material,
being globally uniform, cannot account for the mercury
in petroleum. The more likely hypothesis is that
mercury in oil and gas originated from mercury in the
earth's crust that was liberated by geological forces
(heat and pressure) and migrated as a vapor to the
traps in which oil and gas accumulated.
Although of mostly academic interest, the geological
mechanisms that account for mercury in oil and natural
gas await definition. At present, there is insufficient data
on mercury at specific locations and geologies to draw
any definite conclusions.
References
Speight, J. G., 1999, The Chemistry and Technology of
Petroleum, Marcel Dekker, New York, NY.
U.S. Geological Survey, 2000, USGS World Petroleum
Assessment 2000, Description and Results, U.S.
Dept. of Interior Digital Data Series, U.S. DOI,
Washington, DC.
U.S. DOE 2000, Energy Statistics for 1998, Energy
Information Administration, National Energy
Information Center, Washington, DC.
Tiratsoo, E. N., 1984, Oilfields of the World, Scientific
Press Ltd. Beaconsfield, UK.
Toole-O'Neil, B., Tewalt, S., Finkleman, R., and D.
Akers, 1999, Mercury concentration in coal -
unraveling the puzzle, Fuel, 78: 47.
14
-------
Table 3-9 - Nomenclature and Age of Geological Strata
(Speight 1999)
Era
Period
Epoch
Age
(years X 10s)
Cenozoic Quaternary
Recent
Pleistocene
0.01
3
Cenozoic Tertiary
Pliocene
Miocene
Oligocene
Eocene
Paleocene
12
25
38
55
65
Cretaceous
Mesozoic Jurassic
Triassic
135
180
225
Paleozoic
Permian
Carboniferous
Pennsylvanian
Mississippian
Devonian
Silurian
Ordovician
Cambrian
275
350
413
430
500
600
Precambrian
800
15
-------
Chapter 4
Petroleum and Natural Gas Processing
In the effort to construct the routes of mercury in
geologic hydrocarbons to the biosphere, it is useful to
examine oil and gas processing steps and to account
for the possible pathways of mercury in the various
process streams. A tremendous variety of processing
schemes exists for refining crude oil and for natural gas
separation but the majority of gas and oil processing
facilities are similar in their basic designs and
configurations.
Produced fluids from both oil and gas wells enter
separators where the primary phase separations occur.
In almost all cases, primary phase separations produce
a water stream that is disposed of (most commonly by
re-injection to the reservoir), a gas stream and a liquid
hydrocarbon stream that are processed separately. Oil
is transported to refineries in pipelines, tankers (or
barges) and sometimes by truck. Raw natural gas is
usually treated close to the wellhead to partially remove
water and 4S before transport by pipeline to a gas
treatment/processing facility. The initial treatments are
necessary to prevent corrosion of the pipeline.
The feed to a refinery is a blend of oil from numerous
fields and usually from several overseas sources.
Refineries are usually configured to process either sour
or sweet crude but usually not both, so the feeds to a
refinery are selected to match the process
configuration. A significant aspect of refinery
configuration is the process needed to separate large
quantities of sulfur contained in sour crude. The same
is true for gas in that sour gas requires special
treatment steps and a contiguous facility to process
separated h^S into sulfur for sale.
In general, the processing of oil is directed to maximize
gasoline manufacture while gas processing is directed
to separate methane (sales gas) from other gas
components. The major differences in processing steps
that are utilized depend on the composition of produced
hydrocarbon and the local market. Gas plants that
process both gas and condensate usually separate
liquids (C5+) that are used either as feeds to
petrochemical plants or sent to a refinery where they
are processed along with crude oil. The gas that is
generated in a crude oil refinery is most often used to
fuel the refinery and less often processed to separate
methane for sale.
Petroleum Refining
Petroleum refining involves the distillation, or
fractionation, of crude oils into separate hydrocarbon
groups or cuts. Chemical modification and blending of
cuts results in products that are sold. The types of
products and the relative amounts of products that are
obtained in refining are directly related to the chemical
characteristics of the crude processed and to the
processing steps employed to modify chemical
structure (Speight 1999). A schematic of the typical
integrated refining processes is shown in Figure 4-1.
The principal steps in oil refining are the primary
(Figure 4-2) and vacuum (Figure 4-3) distillations that
produce the major streams that are subsequently
treated and modified. Table 4.1 provides an overview of
the feeds and separated fractions.
Intermediates from distillations are subjected to
numerous treatment and separation processes such as
extraction, hydretreating, and sweetening to remove
undesirable constituents and improve product quality.
Integrated refineries incorporate distillation, conversion,
treatment, and blending operations (see Figure 1).
Distillation cuts are converted into products by
changing the structure of the hydrocarbon molecules
through cracking, reforming, and other conversion
processes and by blending streams to optimize desired
characteristics.
Conversion processes (Tables 4-2 and 4-3) change the
size and structure of hydrocarbon molecules to
optimize the amount and quality of products. These
processes include molecular decomposition by thermal
and catalytic cracking, molecular combination by
alkylation and polymerization and molecular
rearrangement by isomerization and catalytic reforming.
16
-------
Many variations on these basic unit processes have
been developed and many are proprietary to individual
companies. For the catalytic processes, refinery
efficiency is achieved by optimizing catalyst
performance relative to feed characteristics.
Treatment processes (Table 4-4) are applied to process
intermediates and to products and are used to remove
impurities and contaminants (sulfur, metals) and to
separate undesirable constituents (wax, aromatics,
naphthenes). Treatments involve both chemical and
physical separation and include desalting, drying,
hydrodesulfurizing, solvent refining, sweetening,
solvent extraction, and dewaxing.
Formulating and blending combine hydrocarbon
fractions, additives, and other components to produce
finished products with specific properties. Other refinery
unit operations include light-ends recovery (still gas);
sour-water stripping; sludge treatment; wastewater
treatment; acid and tail-gas treatment; and sulfur
recovery.
Major product types and yearly amounts of products
from U.S. refineries are shown in Table 4-5.
Transportation fuels (combusted in engines as opposed
to furnaces) include gasoline, jet fuel and diesel.
Naphthas are primarily used as feeds to petrochemical
processes. Fuel oil is primarily used for residential
heating and to fire industrial boilers. Asphalts and
heavy oils are used for a variety of non-combusted
products (construction materials, road materials,
lubricants) and combusted products (wax).
A typical refinery generates approximately 10-15
gallons of process wastewater for every barrel of oil
processed (API 1977). Water contacts oil in washing
operations such as desalting, in steam stripping and in
aqueous treatments (alkylation). A typical refinery uses
a segregated water treatment system as described
schematically in Figure 4-4. The water treatment
system consists of initial oil and solids removal
(clarifiers, separators), additional oil and solids removal
(air flotation, filters), and waste removal (activated
sludge, aerated lagoons, oxidation ponds, trickling
filters). Following biological treatment, granular filtration
and polishing are employed to eliminate dissolved
solids (Sittig, 1978). The main function of wastewater
treatment systems is to remove hydrocarbons so that
water can be discharged to meet regulatory criteria.
A wide variety of solid waste streams are generated in
conjunction with crude oil refining. These streams
include tank bottoms, slop oil, spent catalysts, filter
cake from water treatments and numerous others. The
nature and type of refinery residuals is documented in
periodic compilations (API 1998) and regulatory
reviews (U.S. EPA 1996).
Table 4.1 - Distillation Processes
(OSHA 2000)
Process
Action
Method
Purpose
Feedstocks
Products
Atmospheric
distillation
Vacuum
distillation
Separation
Separation
Thermal
Thermal
Separate
fractions
Separate w/o
cracking
Desalted crude
oil
Atmospheric
tower residual
Gas, gas oil,
distillate,
residual
Gas oil, lube
stock, residual
17
-------
Table 4-2 - Decomposition Processes
(OSHA 2000)
Process name
Catalytic
cracking
Coking
Hydrocracking
Hydrogen
steam
reforming
Steam cracking
Visbreaking
Process
Alkylation
Grease
compounding
Polymerizing
Catalytic
reforming
Isomerization
Action
Alteration
Polymerize
Hydrogenate
Decompose
Decompose
Decompose
Table 4-3 -
Action
Combining
Combining
Polymerize
Alteration/
dehydration
Rearrange
Method
Catalytic
Thermal
Catalytic
Thermal/
catalytic
Thermal
Thermal
Unification and
(OSHA
Method
Catalytic
Thermal
Catalytic
Catalytic
Catalytic
Purpose
Upgrade
gasoline
Convert
vacuum
residuals
Convert to
lighter HC's
Produce
hydrogen
Crack large
molecules
Reduce
viscosity
Rearrangement
2000)
Purpose
Unite olefins &
isoparaffins
Combine
soaps & oils
Unite two or
more olefins
Upgrade low-
octane naphtha
Convert
straight chain
to branch
Feedstocks
Gas oil, coke
distillate
Gas oil, coke
distillate
Gas oil,
cracked oil,
residual
Desulfurized
gas, O2, steam
Atm. tower hvy
fuel/ distillate
Atmospheric
tower
residual
Processes
Feedstock
Tower
isobutane/
cracker olefin
Lube oil, fatty
acid, alky metal
Cracker olefins
Coker/ hydro-
cracker
naphtha
Butane,
pentane,
hexane
Products
Gasoline,
petrochemical
feedstock
Gasoline,
petrochemical
feedstock
Lighter, higher-
quality
products
Hydrogen, CO,
C02
Cracked
naphtha, coke,
residual
Distillate, tar
Products
Iso-octane
(alkylate)
Lubricating
grease
High-octane
naphtha,
petrochemical
stocks
High-octane
Reformate/
aromatic
Isobutane/
pentane/
hexane
18
-------
Table 4-4 - Treatment Processes
(OSHA 2000)
Process
Amine treating
Desalting
Drying &
sweetening
Furfural extraction
Hydrodesulfurization
Hyd retreating
Phenol extraction
Solvent
deasphalting
Solvent dewaxing
Solvent extraction
Sweetening
Action
Treatment
Dehydration
Treatment
Solvent
extraction
Treatment
Hydrogenation
Solvent
extraction
Treatment
Treatment
Solvent
extraction
Treatment
Method
Extraction
Extraction
Adsorption
Thermal
Absorption
Catalytic
Catalytic
Adsorption
Thermal
Absorption
Cool/ filter
Absorption
precipitation
Catalytic
Purpose
acidic
contaminants
Remove
contaminants
Remove H2O
& sulfur
compounds
Upgrade mid
distillate &
lubes
sulfur,
contaminants
Remove
impurities,
saturate
HC's
Improve
viscosity &
color
Remove
asphalt
Rpmnvp WPY
IxCI 1 i\J V C VVCIA
from lube
stocks
Separate
unsat. oils
H2S, convert
mercaptan
Feedstocks
Sour gas, HCs
w/C02 & H2S
Crude oil
Liquids, LPG,
alkylation
feedstock
Cycle oils & lube
feedstocks
High-sulfur
residual/gas oil
Residuals,
cracked HCs
Lube oil base
stocks
Vacuum tower
residual,
propane
Vacuum tower
lube oils
Gas oil,
reformate,
j; j.; 1 1 j.
distillate
Untreated
distillate/gasoline
Products
Acid free gases
& liquid HCs
Desalted crude
oil
Sweet & dry
hydrocarbons
High quality
diesel & lube oil
Desulfurized
olefins, HCs
Cracker feed,
distillate, lube
High quality lube
oils
Heavy lube oil,
asphalt
Dewaxed lube
basestock
High-octane
gasoline
High-quality
distillate/gasoline
Specific Gravity
g/mL
Table 4-5 - Refined Products
(U.S. DOE 2000)
Refined Products
Barrel/y
(109)
kg/y
do11)
0.75
0.80
0.85
0.85
1.10
0.90
0.55
Transportation fuels (60%)
Naphthas (5%)
Residual fuel oil (5%)
Distilled fuel oil (21%)
Petroleum coke (3%)
Asphalt, Heavy oils (3%)
Still Gas (3%)
TOTAL
3.7
0.3
0.3
1.3
0.2
0.2
0.2
6.2
4.4
0.4
0.4
1.8
0.3
0.3
0.2
7.8
19
-------
Still Gas
Gasoline
Kerosene
Naphtha
Diesel
Kerosene
Heating Oil
Diesel
Fuel Oil
Naphtha
Gasoline
Kerosene
Coke
Asphalt
Aromatic Oil
Wax
Lube Oil
Figure 4-1 - Typical Refining Process
20
-------
CONBENSER
DISIILLATON
LffitT NAPHTHA
IMC
HEAVY NAPHTHA
160 C
KEROSENE
SMC
"GAS 6k
RESOJUM
Figure 4-2 - Primary Distillation
VACUUM
DB1ILLATION
TOWER
To VACUUM
FUMACE
Figure 4-3 - Vacuum Distillation
VACUUM GAS
OIL
LUBRICATIHG OILS
VACUUM
RESIOUJM
21
-------
Poml
Process
Water
Treatment
Ballast
Storage I
Tanlf
/ Holding
"*• Pond
Discharge 1
Figure 4-4 - Segregated Water Treatment System for a Typical Refinery
Gas Processing
Figure 4-5 shows a typical gas processing plant that
provides pipeline sales gas (methane) and
petrochemical feedstocks. Several other types of gas
processing are common including plants that optimize
liquefied petroleum gas (LPG, C3 and C4) separation,
liquefied natural gas (LNG, C1), natural gas liquids
(NGL, C3+). Certain aspects of gas treatment are
common to all gas processing schemes.
Unlike refining, gas processing attempts no molecular
transformations to produce salable products. Gas
processing is more accurately termed a treatment and
separation process. The treatments are designed to
remove unwanted constituents (CO2, H2S, H2O) and
trace contaminants (metals). The separations are
typically cryogenic utilizing selective condensation of
fractions (C2, C3, C4) by removal of heat.
Water removal (dehydration) treatments are applied to
all natural gas and several processes are common.
Glycol dehydration contacts gas with triethyleneglycol
(TEG) that absorbs water. The TEG is regenerated in a
continuous process that boils off the water. Molecular
sieve (mol-siv) water adsorbents are also employed.
Mol-siv water sorbents are regenerated with hot gas in a
dual contactor arrangement (lag-lead regeneration). Acid
gas removal (AGR) involves contacting gas with amine
solutions that selectively adsorb H2S and some CO2.
CO2 is removed by contacting gas with carbonate
solutions.
The gas separation process involves cooling gas
(Joule-Thompson) to liquefy C2 - C5. The cryogenic
heat exchanger is referred to as a cold box and is
typically manufactured from aluminum. Mercury
removal units containing sorbents specific to mercury
are applied upstream of the cold box to prevent
condensation of mercury and subsequent damage to
the aluminum welds (Wilhelm 1994).
Mercury removal (see Figure 4-5) may or may not be
employed at gas processing plants. The decision is
based on the amount of mercury in feeds, whether
aluminum heat exchangers are utilized and on whether
downstream customers of gas products have
specifications for mercury. Mercury removal units are
required for virtually all LNG plants because of the
sensitivity of cryogenic heat exchanges to mercury
deposition (Wilhelm 1994) and because the low
temperatures required to liquefy gas usually condense
mercury as well.
22
-------
The individual products (propane, butane, C5+) are
separated in towers by warming and pressure
reductions. The resulting liquid product streams
(butane, propane) are typically feeds to petrochemical
manufacture with methane sold as a pipelined product
(sales gas). Ethane is typically the feed to ethylene
manufacture; propane to propylene; butane to MTBE
(methyl-tertbutylether, a gasoline additive). The C5+
product may be sold to a refinery or to other types of
petrochemical manufacture (aromatics, olefins).
References
American Petroleum Institute, 1977, Water Reuse
Studies, API Publication No. 949. Washington, DC.
American Petroleum Institute, 1998, Management Of
Residual Materials: 1997, Petroleum Refining
Performance, API Publication No. 352,
Washington, DC.
Sittig, M., 1978, Petroleum Refining Industry - Energy
Saving and Environmental Control, Noyes Data,
Park Ridge, NJ.
Speight, J. G., 1999, The Chemistry and Technology of
Petroleum, Marcel Dekker, New York, NY.
U.S. EPA, 1996, Waste Minimization for Selected
Residuals in the Petroleum Refining Industry, Office
of Solid Waste and Emergency Response,
EPA/530/R-96/009 (NTIS PB97-121180),
Washington, DC.
U.S. DOE, 2000, Energy Statistics for 1998, Energy
Information Administration, National Energy
Information Center, Washington, D.C.
U.S. Occupational Safety and Health Administration,
2000, OSHA Technical Manual, Section 4:
Petroleum Refining, U.S. Dept. of Labor,
Washington, DC.
Wilhelm, S., 1994, Methods to Combat Liquid Metal
Embrittlement in Cryogenic Aluminum Heat
Exchangers, Proceedings 73rd GPA Convention,
New Orleans, LA.
FEED GAS MEROIIW
OBVEtt REMOVAL
C6*
OtPOPflHKtfl
Figure 4-5 - Gas Process Schematic
23
-------
Chapters
Mercury in Petroleum and Natural Gas
Properties of Mercury and Mercury
Compounds
The common physical properties of elemental mercury
are listed in Table 5.1. Elemental mercury is a liquid at
ambient conditions. Its melting point is -38.87 C and it
has a boiling point of 357 C. Elemental mercury is quite
dense (13.5 times more than liquid water under ambient
conditions). The high density, the low saturation vapor
pressure and high surface tension control the behavior of
elemental mercury in solid, liquid and gaseous matrices.
Mercury occurs in nature in the zero (elemental), +1
(mercury[l] or mercurous), or the +2 (mercury[ll] or
mercuric) valence states. Mercurous compounds
usually involve Hg-Hg bonds
unstable and rare in nature.
and are generally
Mercury occurs most prevalently in the elemental form
or in the inorganic mercuric form. Common mercuric
compounds include mercuric oxide, mercuric chloride,
mercuric sulfide and mercuric hydroxide. Organic
mercury forms also exist and consist of two main
groups: R-Hg-X compounds and R-Hg-R compounds,
where R = organic species, of which methyl (-CH3) is
prominent, and X = inorganic anions, such as chloride,
nitrate or hydroxide. The R-Hg-X group includes
monomethylmercury compounds. The most prominent
R-Hg-R compound is dimethylmercury.
Table 5-1 - Physical Properties of Elemental Mercury
Atomic number
Atomic weight
Boiling point
Boiling point/rise in pressure
Density
Diffusivity (in air)
Heat capacity
Henry's law constant
Interfacial tension (Hg/H2O)
Melting point
Saturation vapor pressure
Surface tension (in air)
Vaporization rate (still air)
80
200.59 atomic mass units
357 C (675 F)
0.0746 °C/torr
13.546 g/cm3 at 20 C (0.489 Ib/in3 at 68 F)
0.112 cm2/sec
0.0332 cal/g at 20 C (0.060 Btu/lb at 68 F)
0.0114 atm m2/mol
375 dyne/cm at 20 C (68 F)
-38.87 C (-37.97 F)
0.16 N/m3 (pascal) at 20 C (68 F)
436 dyne/cm at 20 C (68 F)
0.007 mg/cm2hr for 10.5 cm2 droplet at 20 C
24
-------
Mercury is difficult to oxidize in the natural environment
and spilled mercury (in soil for instance) retains the
elemental form indefinitely absent moisture and
bacteria until evaporation. Mercury can be oxidized by
the stronger oxidants including halogens, hydrogen
peroxide, nitric acid and concentrated sulfuric acid.
Mercury is oxidized and methylated in sediments by
sulfate-reducing bacteria.
Selected solubility and volatility data for elemental
mercury and some mercury compounds in water are
compiled in Table 5-2. It is important to note that sulfides
of mercury are largely insoluble in water (and oil) and, as
pollutants are less available to receptors.
Under ambient conditions, silver, gold, copper, zinc, and
aluminum readily form amalgams with elemental
mercury. The solubility of these metals in elemental
mercury is relatively low. The solubility of zinc in mercury
is approximately 2 g Zn/100 g Hg, while gold solubility in
mercury is only 0.13 g Au/100 g Hg. Silver, copper, and
aluminum have even lower solubilities than gold. The
affinity of mercury for gold is important in analytical
procedures that trap vapor phase mercury on gold
collectors.
Formula
State
Table 5-2 - Solubilities and Volatilities of Mercury Compounds
Volatility
Hg Solubility in
H20; 25 C
Name
Hg° Liquid
HgCI2 Solid
HgSO4 Solid
HgO Solid
HgS Solid
HgSe Solid
(CH3)2Hg Liquid
(C2H5)2Hg Liquid
Boiling Point 357 C
Vapor Pressure 25 mg/m
Boiling Point 302 C
decomposes 300 C
decomposes 500 C
Sublimes under vacuum;
Sublimes under vacuum,
Boiling Point 96 C
Boiling Point 170 C
3 (25 C)
decomposes 560 C
decomposes 800 C
50 ppb
70g/L
0.03 g/L
0.05 g/L
- log Ksp(1) = 52
- log Ksp ~ 1 00
< 1 ppm
< 1 ppm
Elemental
Mercuric chloride
Mercuric sulfate
Mercuric oxide
Mercuric sulfide
Mercuric selenide
Dimethylmercury
Diethylmercury
(1) Ksp = solubility product
Mercury In Hydrocarbons
Elemental mercury and mercury compounds occur
naturally in geologic hydrocarbons including coal,
natural gas, gas condensates and crude oil. Table 5-3
provides a listing of the mercury species that have been
detected and their relative abundance in hydrocarbon
matrices (Wilhelm and Bloom 2000). Since analytical
speciation techniques do not exist for all of the matrices
(especially coal), considerable uncertainty exists for the
relative abundance of some species.
In natural gas, mercury exists almost exclusively in its
elemental form and at concentrations far below
saturation suggesting that no liquid mercury phase
exists in most reservoirs. One gas reservoir is known
(Texas) that produces gas at saturation (with respect to
elemental mercury) and produces condensed liquid
elemental mercury as well suggesting that, in this single
example, the gas is in equilibrium with a liquid mercury
phase in the reservoir.
The prevalence of dialkylmercury in natural gas is
largely unknown but thought to be low (less than 1
percent of total) based on the limited speciation data
reported in the literature for gas condensates (Tao et al.
1998). Organic mercury compounds in produced gas
would be expected to partition to separated hydrocarbon
liquids as the gas is cooled. Therefore, if dialkylmercury
is present in the reservoir, it would be found mostly in
condensate, less so in gas, in those situations where
hydrocarbon liquids separate due to natural cooling.
Likewise in gas processing, little organic mercury would
be expected in sales gas due its partition to liquid
streams.
Crude oil and gas condensate can contain several
chemical forms of mercury, which differ in their
chemical and physical properties.
1. Dissolved elemental mercury (Hg°) - Elemental
mercury is soluble in crude oil and hydrocarbon
25
-------
liquids in atomic form to a few ppm. Elemental
mercury is absorptive and adsorbs on metallic
components (pipes and vessels), suspended
wax, sand and other suspended solid materials
in liquids. The measured concentration of
dissolved elemental mercury typically
decreases with distance from the wellhead due
to adsorption, reaction with iron, conversion to
other forms and loss of the suspended fraction.
2. Dissolved organic mercury (RHgR and RHgX,
where R = CH3, C^Hs, etc. and X = CI" or other
inorganic anion) - Dissolved organic mercury
compounds are highly soluble in crude oil and
gas condensate. Organic mercury compounds
are similar to elemental mercury in adsorptive
tendencies but differ in their boiling points and
solubilities and thus they partition to distillation
fractions in a different fashion from Hg°. This
category includes dialkylmercury (i.e.,
dimethylmercury, diethylmercury) and
monomethylmercury halides (or other inorganic
ions).
3. Inorganic (ionic) mercury salts (Hg2+X or
Hg2+X2, where X is an inorganic ion) -Mercury
salts (mostly halides) are soluble in oil and gas
condensate but preferentially partition to the
water phase in primary separations. Mercuric
chlorides have a reasonably high solubility in
organic liquids (about 10 times more than
elemental mercury). Ionic salts also may be
physically suspended in oil or may be attached
(adsorbed) to suspended particles.
4. Complexed mercury (HgK or HgK2) - Mercury
can exist in hydrocarbons as a complex, where
K is a ligand such as an organic acid, porphyrin
or thiol. The existence of such compounds in
produced hydrocarbons is a matter of
speculation at present depending in large part
on the particular chemistry of the hydrocarbon
fluid.
5. Suspended mercury compounds - The most
common examples are mercuric sulfide (HgS)
and selenide (HgSe), which are insoluble in
water and oil but may be present as suspended
solid particles of very small particle size.
6. Suspended adsorbed mercury - This category
includes elemental and organic mercury that is
not dissolved but rather adsorbed on inert
particles such as sand or wax. Suspended
mercury and suspended mercury compounds
can be separated from liquid feeds to the plant
by physical separation techniques such as
filtration or centrifugation.
There is considerable debate in the scientific
community as to the prevalence of dialkylmercury
compounds in produced hydrocarbons. Their existence
is inferred when analysis for total mercury in a liquid
matrix does not mass balance with speciated forms.
Dialkylmercury compounds have been directly detected
in a few instances but at very low concentrations
possibly inferring an analytical artifact.
Gas and liquid processing can cause transformation of
one chemical form of mercury to another. A common
example is the reaction of elemental mercury with sulfur
compounds. The mixing of gas and/or condensate from
sour and sweet wells allows reaction of elemental
mercury with S8 or ionic mercury with H2S to form
particulate HgS that can settle out in tanks and deposit
in equipment. In theory, high temperature processes
such as hydrotreating in refineries should convert
dialkylmercury and complexed mercury to the
elemental form.
The partitioning of mercury into product and effluent
streams in petroleum processing is largely determined
by solubility. Table 5-4 provides the approximate
solubility of the common species in several liquid
matrices. The solubility of elemental mercury in normal
alkanes (IUPAC 1987) as a function of temperature is
shown in Figure 5-1.
Crude oil and gas condensate, when sampled soon
after primary separation of water and gas, can contain
significant amounts of suspended mercury compounds
and or mercury adsorbed on suspended solids. The
suspended compounds usually are mostly HgS but
include other mercury species adsorbed on silicates
and other suspended colloidal material. The amount of
suspended mercury can be a substantial percentage of
the total concentration of mercury in liquid samples of
produced hydrocarbons and they must be separated
(filtered) prior to any analytical speciation of dissolved
forms.
The term gas condensate refers to liquids that can
originate at several locations in a gas processing
scheme. A generic unprocessed condensate is the
hydrocarbon liquid that separates in the primary
separator, either at the wellhead or at the gas plant.
Processed condensate is the C5+ fraction that is a
product from a gas separation plant. Naphthas typically
originate from the primary distillation of oil in the range
of 50 to 150 C. The distribution of hydrocarbon
compounds in both condensates and naphthas are
similar and mostly in the range C5 to C10. Processed
condensate and naphthas typically do not contain
26
-------
suspended mercury compounds while unprocessed
condensate can contain some amount.
Published total Hg concentrations in condensate,
naphthas and crude oil often do not fully disclose
sampling procedures or analytical processing steps
(filtration, centrifugation, exposure to air). For these
reasons, some data are suspect in that the total
mercury concentrations reported may or may not
include a contribution from suspended forms. In
addition, the distribution of compounds could reflect
species conversion due to aerobic processing of
samples that is suspected to promote oxidation of Hg°
to ionic forms and thus to alter the distribution of
species.
Reported total Hg concentrations in liquid hydrocarbons
(compiled in Chapter 7) vary considerably. Some
condensates and crude oils are close to saturation with
respect to Hg° at concentrations of 1 - 4 ppm as
determined by sparging of fresh, filtered samples.
Adding suspended, ionic and organic forms, total
mercury concentrations in crude oil over 5 ppm are
known. Gas condensates in Southeast Asia have
dissolved total Hg concentrations in the 10 - 800 ppb
range. Most crude oils processed in the U.S. have
relatively low (<10 ppb) mercury concentrations. The
range of total mercury concentration in oil processed in
the U.S. is estimated to be 1 to 1000 ppb (wt.) with the
mean close to 5 ppb (see Section 7 and Wilhelm 2001).
Data for total Hg in naphthas (Tao et al. 1998) are
similar to condensates and range between
approximately 5 and 200 ppb. High concentrations
have not been reported in the limited published data.
Naphthas originating from distillations would be
expected to have lower concentrations than the raw
produced liquids from which they originate.
Only limited data are available that allow examination of
the distribution of concentrations of mercury
compounds in hydrocarbon liquids. Of interest are the
natural abundance of mercury compounds, the relative
distribution of compounds in liquid samples, the
partitioning of compounds in separations and
distillations and transformation of species during
processing.
The data of Tao et al. (1998) on gas condensates,
naphthas and a crude oil, are shown graphically in
Figure 5-2. The origin (process location) of samples
analyzed by Tao were not disclosed. Tao's data
indicate that ionic mercury was the dominant species in
the condensates examined. Hg° did not exceed 25
percent of the total in any of the condensate samples.
The dialkyl species was detected (>10%) in some
condensates. The monoalkyl species was detected but
at very low concentrations. Hg was not seen in
naphthas as would be expected assuming a normal
distillation profile. The more volatile Hg° would be
expected to partition to the lighter gas fraction. RHgR
appeared to be the dominant species in one naphtha
sample. Ionic forms of mercury were seen in all of the
samples.
Zettlitzer et al. (1997) used two methods to measure
concentrations of mercury species. The method for
monoalkylmercury provided suitable detection limits.
The concentrations of monoalkylmercury in the
condensate analyzed by Zettlitzer were low and
generally agree with the data of Tao. A gas
chromatographic (separation) and mass spectrometer
(detection) method was used to examine RHgR but the
detection limit was high and the methodology suspect.
In Zettlitzer's procedure, extracting condensate with
HCI was postulated to remove ionic and organic forms.
The concentration of acid-extractable mercury was
operationally defined as the difference between the
total amount extracted using HCI and the sum of ionic
and monoalkylmercury determined independently.
Zettlitzer's distributions of compounds, using
operationally defined values for extracted mercury, are
compiled in Table 5-4. The unprocessed condensate
sample exhibited a 2 ppm concentration of Hg° which is
close to the saturation value for elemental mercury in
hydrocarbon liquids. These data do not show the
dominance of ionic species seen in the data of Tao.
Freeh et al. (1996) analyzed two condensates and
found most of the total mercury in ionic form. The
dialkyl form accounted for approximately 10 percent
and the monoalkyl form less than 1 percent. Similarly
Schlickling and Broekaert (1995) analyzed 2
condensates and found mostly ionic compounds.
Bloom's (2000) operationally defined speciation (Table
5-6) data account for the majority of total dissolved
mercury as either Hg° or KCI extractable (mostly ionic).
In spite of the fact that dialkylmercury has been
detected in some samples, the concentrations found for
this class of compounds are very low (< 10 ppb)
excepting one naphtha (Tao et al. 1998) in which it was
found at a concentration of approximately 50 ppb.
Based on the limited data, it is by no means apparent at
this point in time that dialkylmercury is prevalent in
petroleum.
Snell et al. (1998) examined the stabilities of mercury
species in synthetic gas condensate and demonstrated
conclusively that Hg and HgCI2 react to form Hg2CI2
that is insoluble in hydrocarbons and precipitates.
Hg° + HgCI2
Hg2CI2
27
-------
The reaction exhibited a half-life on the order of about
10 days at ambient temperature. Most condensate
samples contain both species thus implying, given the
clearly defined observations of Snell, that species
conversion is likely in gas condensate samples. Bloom
(2000) likewise examined sample stability and found
standard solutions of Hg°, HgCH3+ and Hg(CH3)2 stable
in paraffin oil stored in glass. HgCI2 was not stable in
paraffin oil and Hg° and HgCI2 were unstable in natural
crude oil. Bloom's data generally support those of Snell.
Oxidative mechanisms may operate in hydrocarbon
samples that are exposed to oxygen, that contact metal
surfaces or that are treated with impure reagents as
part of the analytical method. If this is the case, then
the high concentrations of ionic forms in some samples
may be an artifact of collection procedures, sample age
and analytical processing methodologies. The author's
experience with crude oils and gas condensate
samples is that very fresh samples typically exhibit the
dominance of the Hg° species. No reductive
mechanisms are known that would account for
generation of Hg° in samples of geologic hydrocarbons;
hence, the transformation of ionic or organic species to
elemental mercury is not likely.
The primary separation of water in gas or oil production
would be expected to segregate the majority of ionic
species naturally present to the water phase. Produced
water that has low dissolved mercury content is
associated with co-produced hydrocarbon liquids
containing high concentrations of ionic species
(analyzed days after collection). Such high percentage
concentrations of ionic species in the hydrocarbon
liquid are not expected based upon the rationalization
that the ionic species should partition to the separated
water phase during primary separations.
If one compares the concentrations of Hg° in co-
produced hydrocarbon liquid and gas, Hg° typically is
dominant in both. This suggests that Hg is the
dominant species in the reservoir and the ionic forms
derive from it. Reaction mechanisms associated with
sample stability certainly require further investigation. If
the ionic content of liquid samples is merely an artifact
of sample aging, then the distribution of mercury
compounds previously cited is suspect.
There is also considerable doubt that dialkylmercury
exists abundantly in crude oil and condensate.
Monoalkylmercury is not found in petroleum. If
dialkylmercury were abundant, then the monoalkyl
species would be expected to be similarly abundant.
Given the very low concentrations of HgCH3+ in
condensate, it is unlikely that discharges of produced
water to the ocean would contain significant amounts
and thus would not have any direct contribution to
monomethylmercury levels in sediments or in fish in
proximity to platforms.
Table 5-3 -Approximate Natural Abundance of
Mercury Compounds in Hydrocarbons
Coal
Natural Gas
Gas Condensate
Crude Oil
Hg°
(CH3)2Hg
HgCI2
HgS
HgO
CH3HgCI
T
?
S?
D
T?
9
D
T
N
N
N
N
D
T, (S?)
S
Suspended
N
T?
D
T, (S?)
S
Suspended
N
T?
Abundance: D (dominant) - greater than 50 percent of total;
S (some) - 10 to 50 percent
T (trace) - less than 1 percent
N (none) - rarely detected
? indicates that data not conclusive
28
-------
Table 5-4 - Approximate Solubility of Mercury Compounds in Liquids; 25 C
Species
Hg°
XHgX
HgCI2
HgS
HgO
CH3HgCI
Water
(ppm)
0.05
9
70,000
0.01
50
>10,000
Oil
(ppm)
2
miscible
>10
< 0.01
low
1,000
Glycol
(ppm)
<1
>1
>50
<0.01
>1,000
Table 5-5 - Concentrations of Mercury Compounds
in Natural Gas Condensates (tig/liter Hg) (Zettlitzer et al. 1997)
Sample
Hg°
HgCI2
Other RHgCI Sum (a) Total
(1) Sum =Hgu + HgCI2 + RHgCI + other; other = acid extracted - HgCI2; HgS = Total- sum
HgS
Low-Temp. Separator
(percent)
Ambient temp.
Separator
Storage tank
250
19.2
2000
39.2
200
11.8
400
30.8
400
7.8
200
11.8
644
49.5
2600
51.0
1250
73.5
6
0.5
100
2.0
50
2.9
1300
100.0
5100
100.0
1700
100.0
3500 2200
5500 400
4300 2600
Table 5-6 - Operational Hg Speciation in Petroleum Samples (Bloom 2000)
Sample ID
unfiltered Hg, ng/g
Total
Hg°
0.8 \i filtered Hg, ng/g
dissolved total Hg(ll)
(1) This sample was contained participate Hg°that was re-dissolved in hexane.
CH3Hg
condensate #1
condensate #2
crude oil #1
crude oil #2
crude oil #3
crude oil #4
crude oil #5
crude oil #6
crude oil #7
20,700
49,400
1,990
4,750
4,610
4,100
15,200
1.51
0.42
3,060
34,5001
408
1,120
536
1,250
2,930
0.09
0.17
5,210
36,800
821
1,470
1,680
1,770
3,110
1.01
0.41
2,150
2,370
291
433
377
506
489
0.39
0.02
3.74
6.24
0.25
0.26
0.27
0.62
0.45
0.15
0.11
29
-------
•no
5-
OS
-ion
-Wl
-IP St.
us
-110
-••
SS 13
1000 /
Figure 5-1 - Solubility of Elemental Mercury in
Normal Alkanes as a Function of Temperature
40
iHflCt,
I
Ct « C3 C4 C5 N1 Ni NS CO « C7
Condeniat* |C), Kipfttha3(N| «nd Crude Oil (CO)
Figure 5-2 - Distribution of Mercury Compounds in Liquids
(Taoetal. 1998)
30
-------
Analytical Methods for Mercury in
Hydrocarbon Matrices
Advances in analytical techniques over the last decade
have allowed extremely accurate determinations of
mercury and mercury species in virtually all matrices.
The advances have been made in both technique and
instrumentation. The most important contributions were
the development and application of ultraclean sample
handling techniques (Bloom 1995; Fitzgerald and
Watras 1989) and the development of more sensitive
analytical methods, such as amalgamation pre-
concentration (Bloom and Crecelius 1983; Fitzgerald
and Gill 1979) and cold vapor atomic fluorescence
spectrometry, or cold vapor atomic fluorescence
(CVAF) (Bloom and Crecelius 1983; Goddon and
Stockwell 1989). The CVAF method for total Hg
determination in water was adopted by U.S. EPA as
Method 1631 (U.S. EPA 1995).
Speciation techniques for mercury compounds in water
have evolved along with the development of the very
sensitive detectors. Mercury and its compounds can
now be measured in aqueous media at below parts per
trillion (ng/L) levels. Essentially all environmentally
important mercury species, including methylmercury,
dimethylmercury [(Chb)2Hg], inorganic mercury,
particulate mercury, and elemental mercury (Hg°), can
be accurately measured in aqueous environmental
media. Clevenger et al. (1997) provides an excellent
review of the variety of methods used to detect and
speciate mercury in environmental media (water,
sediments, atmosphere) and the limits of detection
presently achieved.
Determination of mercury in hydrocarbon matrices has
likewise evolved over the last decade primarily as a
result of the major improvements accomplished for
water. In hydrocarbon samples, lower detection has
been achieved by better sampling techniques and new
methods for separating mercury from the hydrocarbon
matrix. Improvements have also been obtained by a
better understanding of the chemistry of mercury in
petroleum and gas and from understanding how the
various species distribute in phases during sampling
and analysis.
Sampling of low molecular weight hydrocarbon liquids
(C2-C5) for mercury analysis is difficult to accomplish
when the process stream is at elevated temperature
and/or pressure. In samples taken from elevated
temperature liquids, Hg° can segregate to the vapor
phase in a sample container thus causing a lower than
actual analytical result of the liquid phase. Losses of
volatile mercury also occur when sampling pressurized
fluids. When samples of pressurized fluids are taken
into a vessel at ambient pressure, volatile mercury
(Hg°) escapes to the gas phase when the fluid is
partially depressurized. This problem is especially
important for sampling of condensed gases such as
propane and butane. The sampling techniques for
volatile liquids often do not account for volatile mercury
components thus placing some of the reported data in
doubt.
Mercury concentrations in metal containers used for
pressurized liquid samples can exhibit lower than actual
results due to adsorption or reaction with corrosion
products on container walls. The material of
construction for pressurized sample containers must be
selected carefully to obtain quantitative samples.
Stainless steel containers minimize reactive loss of
mercury but can introduce errors due to adsorption,
especially if the mercury concentrations are low.
For multiple-phase samples (water, hydrocarbon liquid
and gas), mercury will partition to the various phases
disproportionately with elemental mercury equilibrating
between gas and liquid and other forms remaining
mostly in the liquids. The amount of elemental mercury
that partitions to water is usually a small percentage of
the total mercury concentration in coexisting phases
because of the low solubility of elemental mercury in
water. Ionic mercury compounds, if a large percentage
of the total mercury concentration in crude oil, will
partition to the water phase. Acidic water can
encourage formation of a particle rich layer at the
water/oil interface that can be very high in mercury
concentration. Sampling and analysis protocols often
are not designed to take these factors into account,
thus supplying additional uncertainty to reported data.
Gas
Mercury in a hydrocarbon gas matrix at low
concentrations is difficult to detect directly by
spectroscopic methods (UV, visible, IR, X-ray) because
of interference by the hydrocarbon. Pre-concentration
of the mercury in gas to a collector facilitates analysis.
Collection methods for mercury in natural gas are used
primarily because of the low concentrations that are
often present. By using a collector, the total amount of
mercury present in a large volume of gas can be
concentrated into a liquid or solid matrix.
A prevalent wet collection method is to bubble gas
(containing mercury) through a permanganate solution
where all mercury species are converted to mercuric
ion. Mercuric ion is then reduced to elemental mercury
and separated by volatilization into an inert gas stream
31
-------
for quantitative detection. Detection methods are
typically UV atomic absorbance or UV atomic
fluorescence. This method is accurate and reasonably
sensitive if sufficient volumes of gas are used, but the
apparatus required to collect the samples is somewhat
cumbersome and the required sample volumes are
large.
A common dry collection method is to flow gas across a
gold collector (sputtered gold on quartz). The gold
amalgamates with mercury to scavenge elemental
mercury. Organic mercury amalgamates as well but
slower than elemental necessitating low flow rates and
long sampling times if the total mercury concentration is
required. The mercury/gold amalgam is heated in an
inert (Ar) gas stream to volatilize mercury for detection.
The collection method is very effective for light, dry gas.
If the stream to be sampled contains heavier
components, hydrocarbon condensation is minimized
by heating the traps slightly (100° to 200° C) without
compromise of quantitative mercury collection.
lodated carbon carbon impregnated with potassium
iodide is also used to scavenge mercury from gas
matrices resulting in concentration of a sufficient
quantity of mercury on the solid adsorbent for routine
digestive analysis, lodated carbon traps are less
sensitive to contaminants in hydrocarbons than gold
traps, lodated carbon traps also have complete capture
capability for elemental and dialkyl mercury and a high
capacity. In view of these attributes, the iodated carbon
trap is used for unprocessed gas where reasonably
high concentrations are expected.
Liquids
Analytical methods for total mercury in hydrocarbon
liquids vary considerably and include combustion/trap
(Liang et al. 2000), vaporization/trap (Shafawi et al.
1999), acid digestion (reviewed by Liang et al. 2000)
and oxidative extraction (Bloom 2000). Combustion
techniques (Liang et al. 2000) oxidize and vaporize the
entire liquid matrix and mercury in the combustion
vapors is trapped by amalgamation on gold. Mercury on
gold is then thermally desorbed and detected using
CVAF. The thermal vaporization/trap method §hafawi
et al. 1999) is similar to the combustion method
excepting that the hydrocarbon liquid is not combusted
and the matrix is retained but in vapor form. The
vaporized liquid is passed over a gold trap in the same
fashion as the combustion method.
Acid digestion methods chemically oxidize mercury to
mercuric ion that separates to the aqueous solution.
The important considerations in wet digestive methods
are to avoid losses to vaporization if the digestion is hot
and to avoid introduction of mercury from impure
reagents or the air. Mercuric ion in acid solution is
quantified by acid neutralization, reduction (SnCI2) to
Hg°, evolution by sparging, trapping on gold and
detection by CVAA or CVAF. Acid digestions are
reported using mixtures of nitric, hydrochloric, sulfuric
acids and perchloric acids.
Extractive methods (Bloom 2000) also employ oxidants,
most typically BrCI, but as opposed to digestions do not
chemically decompose the matrix. Thus typically less
heat is required and losses due to thermal evolution of
volatile mercury forms do not occur. The mercuric ion in
the aqueous extract is treated in the same manner as
acid digestates (reduction, sparging, trap on Au, detect
CVAF). For extractive methods, an important
consideration is that the period of time that the
extracting solution contacts the sample must be long
enough to accomplish complete oxidation and
separation of the entirety of the mercury present in the
sample. Formation of emulsions with some
hydrocarbon liquids can complicate extractive
techniques and procedures such as centrifugation are
used to break oil/water emulsions.
Digestates and extracted liquids are treated chemically
to transform mercuric ion into a species that can be
detected. This is accomplished in a variety of ways, but
the most common is to reduce mercuric ion to
elemental mercury (in water) using stannous chloride or
sodium borohydride. The elemental mercury is evolved
from the solution using inert gas and either sent directly
to a detector or collected on a trap (amalgamation) and
then thermally evolved into an inert gas stream for
detection.
The most common forms of detection are UV
absorbance and UV atomic fluorescence. In cold vapor
atomic absorbance (CVAA), a mercury lamp and optical
flux detector are employed to measure absorbance of
UV light by mercury atoms in argon or nitrogen. The
fluorescence (CVAF) technique is similar but measures
emission (in argon) following absorbance at 90° to the
excitation light path thus avoiding several spectral
interferences and other optical limitations. CVAF is the
most sensitive detection method (10"13g).
For CVAF the overriding attribute is the low detection
limit meaning that quantitative analysis can be achieved
with very small gas sample volumes. By using double
amalgamation, extremely low concentrations of
mercury in gas or liquids can be measured (1 ppt or
less). The low detection limits also dramatically reduce
matrix effects common to other methods and allow
extreme dilution prior to analysis to reduce
interferences.
32
-------
Other methods of total mercury analysis in hydrocarbon
liquids include inductively coupled plasma (ICP)
followed by mass spectrometry (ICP-MS) (Olsen et
al.1997) or atomic emission spectrometry (ICP-AES)
detection (Snell et al. 1996). The ICP technique avoids
digestion of the sample, hence minimizing some of the
potential errors that can occur in multi-step wet
chemical processing of liquid samples. The ICP
procedure involves dilution of the sample with a solvent
and injection of a known quantity directly into a torch
that produces a gaseous plasma. A portion of the
plasma is then fed directly to the MS or AES detector.
Neutron activation analysis (NAA) methods, in which
samples are irradiated in a nuclear reactor and the
decay radiation (gamma) is quantitatively counted,
have been used successfully to measure total mercury
concentration in crude oil (Musa et al. 1995). The cost
and availability of this method have limited its
application to only very specialized circumstances but
the NAA method eliminates essentially all sample
preparation and blank requirements and is essentially
free of interferences.
Gas chromatography (GC) and high performance liquid
chromatography (HPLC) (Schickling and Broekaert
1995) in conjunction with an element specific detector
such as ICP/MS (Tao et al. 1998) or ICP/AES (Snell et
al. 1996) have been used to directly measure volatile
mercury compounds in hydrocarbon liquids. These
compounds include elemental mercury, dialkylmercury
compounds and monoalkylmercury compounds
(determined either directly or after alkylation).
Dialkylmercury compounds are separated from other
forms chromatographically and can be quantitatively
measured in simple matrices. The application of these
techniques to actual petroleum is limited to refined
products.
Analysis for total mercury in a liquid hydrocarbon matrix
provides the sum of both dissolved and suspended
species. If samples are not filtered prior to analysis, the
result obtained from total mercury analysis includes the
contribution from suspended mercury compounds and
thus can be artificially high and variable because the
distribution of suspended mercury in liquid samples is
seldom homogeneous.
Operational speciation of liquid samples (Bloom 2000)
involves multiple and sequential analyses for the
various forms and a mass balance exercise.
THg = Hg° + (RHgR + HgK) + Hg2+ + suspended Hg
Suspended mercury is quantitatively determined by
measuring total mercury of an agitated sample followed
by measuring total mercury of a filtered portion of the
agitated sample. Ionic forms are determined by non-
oxidative extraction. The volatile elemental form (Hg°) is
determined by sparging and collecting the volatile
component on a trap. Total mercury concentration
typically is determined by combustion, extraction or
acid digestion. The sum of the concentrations of
dialkylmercury and complexed mercury (RHgR + HgK)
often is estimated from the discrepancy in the mass
balance. To determine the exact concentration of the
organic forms, more sophisticated techniques (GC-
CVAF, GC-ICP/MS) are required.
References
Bloom, N. S., 1995, Mercury as a case study of ultra-
clean sample handling and storage in aquatic trace
metal research, Environ. Lab., March/April:20.
Bloom, N. S., 2000, Analysis and Stability of Mercury
Speciation in Petroleum Hydrocarbons, Fresenius' J.
Anal. Chem., 366:5.
Bloom, N. S., and E. Crecelius, 1983, Determination of
mercury in seawater at sub-nanogram per liter
levels, Mar. Chem., 14:49.
Clevenger, W. L, Smith, B. W., and J. D. Winefordner,
1997, Trace Determination of Mercury: a Review,
Crit. Rev. Anal. Chem., 27(1 ):1.
Fitzgerald, W. F., and G.A. Gill, 1979, Subnanogram
determination of mercury by two-stage gold
amalgamation applied to atmospheric analysis,
Anal. Chem., 46:1882.
Fitzgerald, W. F., and C. J. Watras, 1989, Mercury in
surficial waters of rural Wisconsin lakes, Sci. Tot.
Environ. 87/88:223.
Freeh, W., Baxter, D., Bakke, B., Snell, J., and Y.
Thomasson, 1996. Determination and Speciation of
Mercury in Natural Gases and Gas Condensates,
Anal. Comm., 33:7H (May).
Goddon, R. G., and P. Stockwell, 1989, Atomic
fluorescence spectrometric determination of mercury
using a filter fluorimeter, J. Anal. Atom. Spectrom.
4:301.
IUPAC, 1987. Mercury in Liquids, Compressed Gases,
Molten Salts and Other Elements, Volume 29;
Solubility Data Series, Pergamon Press, H. Clever,
editor, New York, NY.
Liang, L., Lazoff, S., Horvat, M., Swain, E., and J.
Gilkeson, 2000, Determination of mercury in crude
oil by in-situ thermal decomposition using a simple
lab built system, Fresenius' J. Anal. Chem., 367:8.
Musa, M., Markus, W., Elghondi, A., Etwir, R., and E. A.
Arafa, 1995, Neutron Activation Analysis of Major
33
-------
and Trace Elements in Crude Petroleum, J.
Radioanal. Nucl. Chem., 198(1), 17.
Olsen, S., Westerlund, S., and R. Visser, 1997,
Analysis of Metals in Condensates and Naphthas
by ICP-MS, Analyst, 122:1229.
Schickling, C., and J. Broekaert, 1995, Determination of
Mercury Species in Gas Condensates by On-line
Coupled HPLC and CVAA Spectrometry, App.
Organomet. Chem., 9:29.
Shafawi, A., Ebdon, L, Foulkes, M., Stockwell, P., and
W. Corns, 1999, Determination of total mercury in
hydrocarbons and natural gas condensate by
atomic fluorescence spectrometry, Analyst,
124:185.
Snell, J. P., Freeh, W., and Y. Thomasson, 1996,
Performance Improvements in the Determination of
Mercury Species in Natural Gas Condensate Using
an On-line Amalgamation Trap or Solid-phase
Micro-extraction with GC-MIP-AES, Analyst,
121:1055.
Snell, J., Johansson, M., Freeh, W., and K. Smit, 1998,
Stability and reactions of mercury species in
organic solution, Analyst, 123:905.
Tao, H., Murakami, T., Tominaga, M., and A. Miyazaki,
1998, Mercury speciation in natural gas
condensate by gas chromatography-inductively
coupled plasma mass spectrometry, J. Anal. At.
Spectrom., 13:1085.
U.S. EPA, 1995, Method 1631: Mercury in water by
oxidation, purge and trap, and cold vapor atomic
fluorescence spectrometry, EPA/821/R-95/027,
Office of Water, Washington, DC.
Wilhelm, S., and N. Bloom, 2000, Mercury in Petroleum,
Fuel Proc. Technol., 63:1.
Wilhelm, S., 2001, An Estimate of Mercury Emissions
from Petroleum, in press, Environ. Sci. Tech.
Zettlitzer, M., Scholer, R., and R. Falter, 1997,
Determination of Elemental, Inorganic and Organic
Mercury in North German Gas Condensates and
Formation Brines, Proceedings of Symposium: Oil
and Gas Chemistry, Houston, TX, SPE Paper No.
37260.
34
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Chapters
Fate Of Mercury in Refining and Gas Processing
It would be useful to understand how mercury partitions
in separations, distillations and catalytic processes so
as to be able to predict the amounts of mercury in
emissions or effluents as a function of the known
amount in feeds. Optimally one would have this type of
information for each of the various mercury species
present in hydrocarbon feeds to processing. Very little
data are presently available that provide evidence as to
the fate of mercury in refining and gas processing. Most
of the reported information concerning mercury in
processes is anecdotal and consists of observations of
mercury deposition in equipment and detection of
mercury in certain waste streams.
In some situations, computational methods have been
used to estimate the distribution of mercury and
mercury compounds in processes. Computer models
can predict locations where mercury can condense or
accumulate in cryogenic processes and the distribution
of volatile species in distillations. Calculations of the
distribution of mercury in a process require accurate
information on the concentrations of the various
dissolved and suspended forms that exist in liquid and
gas feeds as well as vapor pressures, solubilities and
gas/liquid partition ratios of Hg species as a function of
temperature and pressure.
Vapor pressure and solubility for elemental mercury are
reasonably well known or easily estimated. The
solubilities of dialkylmercury compounds in
hydrocarbons are assumed to be infinite over the range
of temperatures encountered in most petrochemical
processes. Partitioning of mercury species between
liquid and gas phases can be estimated using chemical
approximation principles and some limited empirical
data (Edmonds et al. 1996, Bloom 2000).
In low temperature processes, chemical reactions to
transform one mercury species to another typically do
not occur so a species mass balance is assumed.
Oxidation of Hg° to ionic compounds and/or HgS likely
occurs in some high temperature refinery processes,
thus making predictive calculations more difficult.
Distillations and separations produce major
redistribution of mercury compounds in refining as does
blending crude feeds having differing amounts of
reactive sulfur compounds.
Predictions of redistribution of mercury species based
on assumptions of thermodynamic equilibrium do not
account for some major kinetic factors. Rates of
condensation and dissolution of Hg° are slow in liquids
at low temperature. Likewise, the rates of redistribution
of mercury and organic mercury to separated phases
are slow compared to the rates of phase separation.
Purely thermodynamic models thus require major
corrections for non-equilibrium conditions and empirical
verification.
Extraction
Oil and gas production systems provide limited
opportunities for loss of mercury from produced fluids
that are typically mixtures of hydrocarbon liquids, gas
and produced water. Essentially all production systems
employ separators to accomplish the primary phase
separation so that produced water can be disposed of.
Multiple stages of separation are typical as oil or gas is
transported to a processing facility.
A typical separator schematic is shown in Figure 6-1
and, although the internals (not shown) are quite
complicated, the obvious result is that hydrocarbon
liquid, natural gas and water phases are separated.
The mercury in the fluid produced at the wellhead will
contain both the dissolved and suspended forms.
Strictly based on gravity, most of the suspended
mercury will be retained in the liquid phases that
separate.
The distribution of dissolved and suspended forms of
mercury in the produced fluid to separated phases is
35
-------
difficult to predict but some broad generalities are
possible. The amounts of mercury that enter the
separated phases depend on physical, chemical and
kinetic factors. The distribution of suspended mercury
depends on particle size and whether the suspended
(colloidal) material is hydrophilic or oleophilic. That
amount of suspended mercury that is attached to large
particles is either removed in the water phase or
retained in the separator as sludge and is then
removed when the separator is periodically cleaned. A
high percentage of truly colloidal mercury is retained by
the liquid hydrocarbon phase in separations.
The distribution of dissolved forms depends on
numerous factors including the differences in solubility
of each species in the various phases, the chemical
composition of the hydrocarbon phases, pressure,
temperature and kinetic considerations. Distribution
coefficients have been measured by Bloom (2000). In
Bloom's study, equal volumes of paraffin oil spiked with
the particular species and water were shaken
vigorously for 2, 6, or 12 minutes, and then allowed to
separate. The results of these experiments are shown
in Table 6-1 and agree reasonably well with
expectations. The expected coefficient for Hg° is
approximately 20, based upon the relative solubilities of
Hg° in water (60 ng/mL) and paraffin oil (1200 ng/mL)
at room temperature. The trend to lower K0w
(octanol/water partition ratio) for elemental mercury was
thought to be due, in part, to oxidation (possibly by
oxygen in air) of Hg° that produces ionic mercury that
partitions to water.
In general, purely ionic (un-complexed) mercury should
partition preferentially to the water phase while elemental
and organic forms should be retained by the liquid
hydrocarbon phase. Henry's law (applied to condensate)
determines the amount of mercury in the gas phase (to a
first approximation). In practice the accuracy of
computations to predict the distribution of mercury in
separations is complicated by kinetic factors because the
residence time in a separator is short and complete
equilibrium is seldom reached.
Table 6-1 - Oil-Water Distribution Coefficients (Bloom 2000)
Shaking Time
Analytical measure
Hg°
(1) KOW (oil/water partition ratio)
HgCI2
CH3HgCI
2 min
6 min
12 min
oil [Hg], ng/mL
water [Hg], ng/mL
Kow <1)
oil [Hg], ng/mL
water [Hg], ng/mL
Kow
oil [Hg], ng/mL
water [Hg], ng/mL
Kow
170.6
5.0
34.1
167.0
12.2
13.7
151.8
18.9
8.0
5.5
160.2
0.034
1.7
167.6
0.010
0.85
169.9
0.005
32.2
98.9
0.33
32.7
98.3
0.33
33.4
99.4
0.34
36
-------
Fluid from
Well
i
Gas
T
I Cot
Condensate
Water
Figure 6-1 - Primary Separation
Transportation
In most cases, mercury is not lost in the movement of
fluids to the processing facility, especially mercury in
oil. For gas, a notable exception to this statement is
transport of slightly wet gas in steel pipelines from
primary separations. Elemental mercury reacts with
steel corrosion products to form a mercury-rich layer on
pipe surfaces. For example, natural gas produced
offshore that contains low mercury concentration (1-20
ppb) when measured at the wellhead, may not present
any mercury at the processing facility initially. The time
to detect mercury at the end of the pipeline is
dependent on the length of the pipeline, the amount of
moisture in the gas and numerous other factors. The
lag in presentation is due to the reaction of the
elemental mercury with the non-stoichiometric iron
oxide/sulfide corrosion products on pipe surfaces, with
participation of H2S in gas, if present.
Refining
Desalting is the process by which oil is washed with
water to remove soluble salts (Figure 6-2) and is
applied upstream of the atmospheric distillation. The
partition of mercury in desalting is similar to that which
occurs in primary phase separations. The greater
amount of water and the longer residence time of crude
oil in the desalter make it more efficient to remove
suspended mercury and those ionic species that have
affinity for water. As a result, the mercury in crude oil
after application of desalting should be depleted of
some fraction of ionic species and contain higher
percentages of the elemental and complexed species.
Mercury in desalter sludge was examined by U.S. EPA
(1996) at four U.S. refineries. The examined refineries
are a small subset of the total number (approximately
100) of U.S. refineries and hence the sampling is not
statistically predictive. Total mercury concentrations are
reported in Table 6-2.
The distribution of total mercury in (filtered) crude oil to
primary distillation products (Sarrazin et al. 1993;
Wilhelm and Bloom 2000) is shown in Figure 6-3 and
generally trends toward lower concentration in the
higher temperature fractions. Suspended HgS was not
present in the filtered crude examined by Wilhelm
(unknown for Sarrazin et al. 1993). For crude feeds that
contain large amounts of suspended mercury, the non-
volatile HgS would tend to remain with the bottom
fractions in the primary distillation and with the heavy oil
and coke in the vacuum distillation. The HgS in resid
and other bottom fractions used to fire boilers is
converted in combustion to volatile forms (Hg°, HgO)
that can be emitted to the atmosphere.
The amount of mercury in petroleum coke is known
with some certainty. As part of the U.S. EPA study of
fuel feeds to coal-fired utilities, a large database has
been developed that contains the total mercury
concentration of petroleum coke consumed as fuel in
coal-fired boilers at electric generating facilities (U.S.
EPA 2000). Analysis of these data (Wilhelm 2000)
allows a clear and accurate determination of the mean
amount of mercury in coke. The mean is is
approximately 50 ppb. The distribution of
concentrations is shown in Figure 6-4. The origin of
crude feeds in the refineries that produced the coke is
not reported.
37
-------
It is likely that the mercury in coke is HgS or HgSe
because the process to produce coke includes both
atmospheric distillation (350 C) and vacuum distillation
(500° - 550° C). Coke is the solid residual material from
the vacuum still and other coking processes. The
volatilization (sublimation) temperature for mercuric
sulfide is approximately 560° C, hence, in the vacuum
distillation and coking processes, the sulfides and
selenides of mercury would be expected to concentrate
in residuum.
Little is known concerning the fate of mercury in unit
processes at refineries. Such processes include
catalytic cracking, visbreaking, alkylation, hydretreating,
etc. Based on purely chemical considerations, any
organic or ionic mercury in feeds to hydrotreaters would
be expected to be converted to Hg°, which would then
incorporate to the separated gas streams (H2S, hfe, C1-
C4).
Mercury in refinery wastewater has been examined by
Ruddy (1982) but prior to the development of the more
accurate and sensitive analytical methods previously
discussed (Chapter 5). The early estimate was that, on
average, refinery wastewater contains approximately 1
ppb total mercury, but the precise range and mean
were not obtained from a statistical sampling. This
amount is consistent with the removal of the majority of
hydrophilic mercury species in the desalter.
Table 6-2 - Total Mercury in Desalter Sludge
(U.S. EPA 1996)
Refinery
1
2
3
4
THg (ppm)
41
4
39
0.01
WATER,
EI»ULS.'H£*i
OIL
..
A
CRUDE
ELECTROSTATIC
DESAL1ER
BRIHE
FURNACE
Figure 6-2 - Crude Oil Desalting
38
-------
BO
I Sirrazmrti 1803
Wih.lm »no fflwm 20CO
10 -
I I
-=IDO MHO- 17D »17D-3BD >JBO -33D > 330
Distillation Ternpsroture Range 1C;
Figure 6-3 - Mercury (Total) in Distilled Products
SO
40 •
J0
o
£
0.
10
0 90 IH> 130 ZW 250 300 390 "tOD 4M 300
Hg(ppb)
Figure 6-4 - Distribution of Mercury (Total) Concentrations in Petroleum Coke
39
-------
Gas Processing
The fate of mercury in gas processing is easier to
predict because the process is simpler and less inclined
to cause transformation of the species initially present.
Gas is subjected to primary separation, treatments to
remove contaminants and cryogenic separation or
liquefaction. Distribution of mercury compounds in the
primary phase separation process has been discussed,
however, produced fluids from most gas wells typically
contain lesser amounts of suspended and ionic
mercury compounds than those found in crude oil of
similar total mercury content (on a mass percentage
basis). Some heavy condensate feeds to gas
separation processes can contain significant amounts
of suspended and oxidized forms, but still less than that
seen in crude oil on a percentage basis.
In treatments for contaminants, the elemental mercury
in gas will dissolve in the liquid glycol in glycol
dehydrators and increase in concentration until
equilibrium is reached. Some portion of elemental
mercury in a glycol dehydrator is removed in the regen
cycle. If the concentration of mercury in gas is
sufficiently high, elemental mercury vapor can
condense in the glycol reboiler vapor condenser. In
amine systems, it is postulated that mercury may react
with the H2S scavenged by the amine and thus be
removed from the process as HgS in the amine filters.
The separation process for gas products is typically
cryogenic and provides the opportunity for
condensation (precipitation) of elemental mercury, if the
concentration is sufficiently high to allow this to occur.
Such condensation is reported for gas separation
plants having mercury in feeds in excess of
approximately 10-20 ug/m3.
LNG plants and many gas separation plants employ
mercury removal systems to minimize problems
associated with mercury condensation and mercury
attack of heat exchangers. Mercury attack of aluminum
heat exchangers caused numerous failures in the
1970's and 1980's but newer process designs, the use
of mercury removal technology and new heat
exchanger designs have succeeded in mostly
eliminating the problem (Wilhelm 1994).
Mercury Removal Systems
One approach to minimize the amount of mercury that
appears in effluents from petroleum processing
operations is to remove the mercury from upstream
hydrocarbons. Mercury removal close to the production
well, in concept, would eliminate downstream problems.
Unfortunately, removal systems for mercury are ill suited
to treating unconditioned hydrocarbons due to the fact
that raw produced hydrocarbons contain numerous
contaminants that interfere with the successful operation
of mercury removal systems. Offshore production
facilities are not designed, nor intended, to have the
capability of mercury removal beds as part of the primary
treatment (dehydration) system. Mercury removal
systems are large and, more importantly, heavy which
precludes their use offshore in most cases (Wilhelm,
1999).
Mercury removal systems are most often located at gas
processing facilities that produce the feedstock
materials for downstream chemical manufacturing
plants. The removal systems, if properly designed and
operated, can eliminate mercury from plant products
and thus substantially reduce the impact of mercury on
downstream plants. Gas processing plants vary
considerably in design depending on the composition of
the feed and the market for products. Plants are
optimized to make particular products such as LNG,
LPG, NGL, ethane, propane, butane and/or C5+
depending on the feed to the plant and the consumer
market. There is less incentive to remove mercury at
plants configured to make fuels than for plants
designed to produce feedstocks for chemical
manufacture.
The principal method to prevent mercury contamination
at processing facilities is to remove mercury from the
various feeds to the plant. Several commercial
processes (see Table 6-3) are available for this
purpose. Mercury removal sorbent beds or treaters are
employed in which the removal material is specially
designed for the particular application. Sorbents consist
of an inert substrate (support) onto which is chemically
or physically bonded a reactive compound that reacts
to form a stable mercury compound that is retained by
the sorbent bed.
The substrates (supports) are designed to selectively
adsorb mercury compounds but do not react with them
directly; the reactant compound is designed for this
task. Most supports (activated carbon, aluminas,
zeolites) are porous with the pore size carefully
controlled to selectively adsorb mercury and to avoid
adsorption of high molecular weight hydrocarbons. For
efficient mercury removal bed function, the adsorptive
capacity of the support is equal in importance to the
reactive nature of the mercury-scavenging compound.
Some commercial mercury removal systems are
targeted at gas phase treatment and some are targeted
at liquids. Gas phase treatment systems primarily
consist of sulfur impregnated carbon, metal sulfide on
40
-------
carbon or alumina, and regenerative molecular sieve
(zeolite) onto which is bonded a metal that
amalgamates with mercury.
In a gas treatment system that utilizes sulfur-
impregnated activated carbon (Nishino et al. 1985,
Matviya et al. 1987), mercury (Hg°) physically adsorbs
and then reacts to form non-volatile mercuric sulfide.
The reaction between Hg° and sulfur is a redox reaction
in which mercury is oxidized and sulfur is reduced.
Because the percentage amount of organic mercury in
gas is usually very low, the efficiency to react with
organic mercury is less critical. Sulfur is soluble in liquid
hydrocarbon and is removed by contact with liquid
hydrocarbon rendering it ineffective. Sulfur/carbon
sorbents are relatively less effective to treat heavy gas
where some liquid condensation is possible.
Metal sulfide (MS) systems for gas (Sugier et al. 1978;
Barthel et al. 1993) have the advantage that the metal
sulfide is not soluble in liquid hydrocarbon and has less
sensitivity to water. The MS systems are therefore
more suited to moist feeds or those in which
hydrocarbon carry over or condensation may occur. In
a metal sulfide mercury removal system for gas having
an alumina (AI2O3) support, mercury reacts with the
metal sulfide directly, adsorption on the alumina
substrate is less kinetically favored than for carbon and
is not required for the reaction to occur.
Mol-siv sorbents Markovs 1988) that contain metals
(silver) selectively capture mercury by an amalgamation
process. Mol-sieve treaters serve a dual role to
dehydrate and to remove mercury. The mercury is
released as mercury vapor upon heating in the regen
cycle. The regen gas in these systems is treated with a
conventional mercury removal bed to prevent sales gas
contamination or a mercury condensation system is
employed in the regen cycle.
Liquid removal processes consist of iodide impregnated
carbon, metal sulfide on carbon or alumina, silver (on
zeolite), mol-sieve and a two step process consisting of
a hydrogenation catalyst followed by metal sulfide
captation. The carbon/iodide system (McNamara, 1994)
consists of an iodide-impregnated carbon having a
large pore diameter. In the iodide system, mercury
must oxidize to react with iodide. In theory the oxidation
step is assisted by carbon, which provides catalytic
assistance to the oxidation step. The metal sulfide and
mol-sieve Markovs, 1993) mercury removal systems
for condensate are conceptually equivalent to those
employed for gas.
Organic mercury (dialkylmercury) is more prevalent in
hydrocarbon liquids. The ability of sorbents to react with
the organic variety is less certain. One system
addresses this situation by using a two-step process in
which the first step is hydrogenation of the dialkyl
mercury using a catalyst and hydrogen (Roussell et al.
1990; Cameron et al. 1993). The dialkyl mercury is
converted to elemental mercury that is scavenged in
the second step using a metal sulfide sorbent.
References
Barthel, Y., Cameron, C., and P. Sarrazin, 1993,
Mercury removal from wet natural gas, Proc. of
European Gas Processors Association, 10th
Continental Meeting.
Bloom, N. S., 2000, Analysis and Stability of Mercury
Speciation in Petroleum Hydrocarbons, Fresenius' J.
Anal. Chem., 366: 5.
Cameron, C., Courty, P., Boitiaux, J-P., Varin, P., and G.
Leger, Method of Eliminating Mercury or Arsenic
From a Fluid in the Presence of a Mercury/Arsenic
Recovery Mass, U.S. Patent 5,245,106 (1993).
Edmonds, B., Moorwood, R., and R. Szczepanski,
1996, Mercury Partitioning in Natural Gases and
Condensates, Proceedings: GPA European
Chapter Meeting, London, UK (March).
Markovs, J., 1988, Purification of Fluid Streams
Containing Mercury, U.S. Patent 4,874,525.
Markovs, J., 1993, Removal of Mercury from Process
Streams, U.S. Patent 5,223,145.
Matviya, T., Gebhard, R., and M. Greenbank, 1987,
Mercury Adsorbent Carbon Molecular Sieves and
Process for Removing Mercury Vapor from Gas
Streams, U.S. Patent 4,708,853.
McNamara, J., 1994, Process for Removal of Mercury
From Liquid Hydrocarbon, U.S. Patent 5,336,835.
Nishino, H., Tanizawa, Y. and T. Yamamoto, 1985,
Process for Removal of Mercury Vapor and
Adsorbent Therefor, U.S. Patent 4,500,327.
Roussell, Courty, P. Boitiaux, J-P., and J. Cosyns, 1990,
Process for Removing Mercury and Possibly Arsenic
in Hydrocarbons, U.S. Patent 4,911,825.
Ruddy, D., 1982, Development Document for Effluent
Limitations Guidelines, New Source Performance
Standards, and Pretreatment Standards for the
Petroleum Refining Point Source Category,
EPA/440/1-82/014 (NTIS PB83-172569), Office of
Water Regulations and Standards, Washington, DC.
Sarrazin, P., Cameron, C., and Y. Barthel, 1993,
Processes prevent detrimental effects from As and
Hg in feedstocks, Oil and Gas J., (Jan. 25).
41
-------
Sugier, A., and F. la Villa, 1978, Process for Removing
Mercury from a Gas or Liquid by Absorption on a
Copper Sulfide-Containing Solid Mass, U.S. Patent
4,094,777.
U.S. EPA, 1996, Waste Minimization for Selected
Residuals in the Petroleum Refining Industry, Office
of Solid Waste and Emergency Response,
EPA/530/R-96/009 (NTIS PB97-121180),
Washington, DC.
U.S. EPA, 2000, Unified Air Toxics Website: Electric
Utility Steam Generating Units, Section 112 Rule
Making, Office of Air Quality Planning and
Standards, Research Triangle Park, NC.
www.epa.gov/ttn/uatw/combust/utiltox/utoxpg.html
Wilhelm, S. M., 1994, Methods to Combat Liquid Metal
Embrittlement in Cryogenic Aluminum Heat
Exchangers, Proceedings 73rd GPA Convention,
New Orleans, LA.
Wilhelm, S. M., 1999, Conceptual Design of Mercury
Removal Systems for Hydrocarbon Liquids,
Hydrocarbon Processing, 78(4):61.
Wilhelm, S. M., and N. S. Bloom, 2000, Mercury in
Petroleum, Fuel Proc. Technol., 63:1.
Table 6-3 - Mercury Removal Systems for Hydrocarbons
Reactant Substrate Complexed Form Application
Sulfur
Metal Sulfide
Iodide
Hydrogen, Metal Sulfide
Ag
Metal Oxide
Carbon
AI2O3; Carbon
Carbon
AI203
Zeolite
Sulfided metal oxide
HgS
HgS
Hgl2
HgS
Ag/Hg amalgam
HgS
Gas
Gas, Condensate
Condensate
Condensate
Gas, Condensate
Gas, Condensate
42
-------
Chapter?
Mercury Emissions from Oil and Natural Gas
Production and Processing
Mercury in produced hydrocarbons may escape to the
environment by several avenues of egress. These
avenues may be generally categorized as wastewater,
solid waste streams and air emissions. Wastewaters
originate in production operations in the form of
produced water and in refining and gas processing as
wastewater. Solid waste streams are generated in
production, transportation and in refining. Air emissions
originate from fugitive emissions from process
equipment and from combustion, with combustion
thought to be vastly dominant as a possible avenue by
which mercury in oil and gas may be transferred from
produced hydrocarbons to the environment.
It is useful, therefore, to examine the major pathways
(solids, liquids and gas) and to further categorize
mercury emissions by industry segment, meaning
production, transportation, and processing systems.
Mercury in combusted fuels is examined in detail as
this is considered to be the dominant avenue of transfer
of mercury in fossil fuels to the atmosphere based on
the existing data and based on the analogy to coal
combustion recently developed (U.S. EPA 1997a,
Brown et al. 1999).
The industry distinguishes between upstream and
downstream operations. The upstream category refers
to primary production and whatever processing is
necessary to place the produced fluids in the
transportation system. The term downstream
operations refers to refining and gas processing to
produce salable products. Natural gas is transported
exclusively via pipeline in the U.S. while crude oil is
transported by a variety of ways with pipelines and
tankers conveying the overwhelming majority.
Mercury Emissions to Water
The main wastewater streams that derive from
petroleum production and processing are produced
water from both oil and gas production and refinery
wastewaters. Very minor amounts of water (relative to
produced water and refinery wastewater) derive from
gas processing and these are mainly water from
separators at gas plants (essentially produced waters)
and condensed water from dehydration. No wastewater
streams originate from transportation systems other
than the very small amounts that come from pipeline
pigging operations and tanker ballast. The discussion
that follows will concentrate on the major streams as
mercury in water data are not reported for the minor
sources.
Produced Water
Normal production operations of both crude oil and
natural gas involve primary separation of water, gas
and oil. Separated water (referred to as produced water
when separated close to the well) is either discharged
(to an ocean, lake or stream or evaporation pond) or re-
injected (usually to the formation it came from). Re-
injection is utilized to enhance oil recovery (EOR) or to
comply with regulatory requirements stemming from
environmental concerns.
Produced water is the largest waste stream in the oil
and gas industry. Produced water varies greatly in
composition and salinity, depending on the geologic
source of the water, type of production, and the
treatment of the water once brought to the surface. The
salinity of produced water ranges from essentially fresh
water to brines that are several times more saline than
seawater. Produced waters typically have total
dissolved solids (TDS) concentrations between 2,000 to
300,000 mg/L (natural seawater is about 34,000 mg/L).
The predominant cation in produced waters is sodium
and chloride is usually the predominant anion.
Some states allow surface discharge of produced
water, but many do not. Produced water originating on
offshore platforms can be discharged to the ocean
unless the platforms are located in sensitive areas or
43
-------
the water is unusually hazardous due to a particular
characteristic (salinity, hydrocarbon content, toxicity). In
sensitive coastal areas of the U.S., produced water is
closely regulated with permit requirements that severely
limit options for discharge thus necessitating treatment
or re-injection.
The U.S. EPA establishes controls on produced water
discharges into U.S. waters through provisions of the
Clean Water Act (CWA; 33 U.S.C. 1251) that established
the National Pollutant Discharge Elimination System
(NPDES). EPA issues effluent limitation guidelines
(ELGs) and discharge permits for produced water
discharged to waters under Federal jurisdiction. A permit
is required for discharge of water both onshore (issued
by individual States) and to offshore waters under
Federal or State jurisdictions. Granting of a permit is
contingent on testing to criteria (including metals) set by
the various States but which are based on the human
and aquatic life criteria contained in the CWA and Safe
Drinking Water Act. Application of the Best Practicable
Control Technology for waters exceeding specifications
is required and applied on a case-by-case basis.
Only limited data are available concerning mercury in
produced waters and essentially none concerning
speciation. Produced waters may contain suspended
HgS, elemental Hg° and/or oxidized forms but the
relative amounts in any produced waters are not
reported relative to the forms that occur in co-produced
hydrocarbons. HgS and Hg° are the dominant forms
found in produced water associated with gas production
in the Gulf of Thailand (Frankiewicz and Tussaneyakul
1997). Gas condensates originating in the Gulf of
Thailand contain between 100 and 1000 ppb total
mercury (mostly elemental).
Total mercury concentrations in U.S. produced waters
were only recently reported as, prior to approximately
1990, analytical methods were insufficient to detect the
low ppb and ppt levels typically now found. Tables 7-1
and 7-2 summarize the available data. Petrusak et al.
(2000) has estimated the amounts and fate of waters
produced onshore for the year 1995. Approximately 18
billion barrels of water were produced by onshore U.S.
oil and gas wells in 1995. 71 percent of this water was
re-injected for EOR and 21 percent was disposed of in
Class II injection wells. Of the remaining 8 percent
(0.23 trillion liters), 3 percent was discharged, 2 percent
was put to beneficial use and 3 percent was disposed
of using miscellaneous methods (public water treatment
works, evaporation ponds, etc.).
Waters produced offshore are more likely to be
discharged to the ocean unless the platform is located
in a sensitive coastal area. Approximately 2 billion
barrels of water are produced annually in offshore
areas under Federal and State jurisdiction (about 1
billion bpy in the Gulf of Mexico and 1 billion bpy
elsewhere, Stephenson 1992). About 70 percent of the
offshore produced water is discharged to the ocean
(approximately 0.3 trillion liters annually).
At this point in time it is not possible to assign either a
mean or range to mercury concentrations in produced
and discharged water. It may be possible eventually to
obtain such a mean amount by accessing the NPDES
databases of the individual states that require reporting
of mercury concentrations. As discussed previously, the
analytical methods recently adopted by the U.S. EPA
(EPA Method 1631, U.S. EPA 1999) are slowly being
applied under statute and it may be some time before
sufficient data are available to obtain an accurate
estimate of the amount of mercury in produced water
that is discharged to the environment. The mercury
species present in produced waters are unknown but
likely include higher percentages of suspended forms
(HgS) and ionic forms than the produced crude oil.
Applying an estimated mean mercury concentration in
produced water of 1 ppb to 0.5 trillion liters (0.2
onshore and 0.3 offshore yearly), one obtains the result
that on the order of 250 kg mercury may enter the
aqueous environment annually from waters associated
with U.S. oil and gas production.
Refinery Wastewater
The chemical compositions of refinery wastewaters
vary widely, as do the volumes of water (per barrel of
oil processed) produced by refineries. Major water
compositional differences stem from process
configuration (products produced) and from the type of
crude oil that is processed (high sulfur crude, sweet
crude). The wastewater that enters water treatment
systems at refineries is a composite of water
discharges from individual processing units that differ in
type and function. Water streams from process units
are differentiated and categorized as waters that
contact hydrocarbons (including condensed steam from
stripping) and cooling waters that typically do not
contact hydrocarbons directly but may contain some
hydrocarbon contamination from leakage.
The following post-secondary treatment wastewater
characteristics are typical (API 1977, 1978, 1981).
Additional details are contained in Table 7-3.
• 1-10 MMgal/D secondary treatment process
wastewater
• Total mercury at up to 1 ppb, species unknown
(Ruddy 1982)
• Residual petroleum compounds present (10 -
40 ppm Total Organic Carbon typical)
44
-------
. 10-100 ppb each of any trace metal(s): Cu, Zn,
Pb, V, Se, Ni, Cr, Fe, As, etc.
• Ammonia (1 - 20 ppm), cyanide, chelating
agents possibly present
• Total Suspended Solids at 10-30 ppm
Speciation of mercury in refinery wastewater is largely
unknown. Post-biological treatment waters from
municipal sewage treatment (similar in process to
refinery biological water treatment) generates mercury
compound speciation such that less than 5 percent (of
the total mercury concentration) exists as
monomethylmercury, less than 0.01 percent as
dialkylmercury, less than 0.1 percent as Hg°, possibly
10-30 percent suspended particulate Hg, less than 10
percent labile Hg(2+), and between 60 and 90 as
organochelated Hg(2+). The concentration of total
mercury in effluents from (municipal) sewage treatment
facilities is in the range of 5-20 ng/L (Bloom and Falke
1996).
The mean and range of mercury concentration in
refinery wastewater cannot be stated with certainty.
Very little information is available in the published
literature that speaks directly to this issue. The EPA
study of refinery effluents from the early 80's (Ruddy
1982) provides a mean close to 1 ppb but the
methodology to arrive at this number is poorly
documented. The advances in mercury analysis
procedures that have occurred since that time (U.S.
EPA 1999) may allow a more accurate estimate in the
future, but now it can only be stated that the mean is
likely less than 1 ppb and that the level varies from
refinery to refinery and with the amount of mercury in
processed crude.
The amount of refinery wastewater discharged to the
environment (rivers, lakes and oceans) is
approximately 1.5 billion barrels yearly (for year 1998,
U.S. DOE 2000, U.S. EPA 1996). Applying the 1982
EPA mean value of 1 ppb (max.) to this amount yields
approximately 250 kg as an upper limit to the total
amount of mercury discharged in refinery wastewater.
Table 7-1 - Mercury in Produced Waters
Location
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
North Sea
North Sea
North Sea
North Sea
North Sea
Gulf of Mexico
Ocean
Ocean
Coastal LA
Brent
Northern
Central
UK
Dutch
Coastal
Discharge Rate
(109 L/y)
0.64
0.40
1.74
140
THg
(ppb)
<0.010
<0.010
0.007 - 27;
Mean 7.08; SD 11.26
<3
<3
<3
<1
4
<0.01 -0.2,
n = 37
Reference
Ray 1998
Ray 1998
Meinhold et al. 1996
Jacobs et al. 1992
Jacobs et al. 1992
Jacobs et al. 1992
Jacobs et al. 1992
Jacobs et al. 1992
Trefry et al. 1996
45
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Table 7-2 -Mercury Concentrations in Produced Water
(Southern CA, year 1990)
(Raco1993)
Platform
Elly
Edith
Hogan
Hillhouse
A
B
C
Habitat
Irene
Grace
Gail
Gilda
No.
Samples
2
1
2
1
2
2
2
1
4
2
5
2
Volume
(106 L/y)
1
176
225
361
1184
726
836
21
608
139
273
704
5,254
THg
(ppb)
<1
<1
<1
<1
0.5
2.5
<1
<1
0.5
1
1.6
<1
Dafa from National Pollutant Discharge Elimination System discharge
monitoring reports submitted to US EPA Region 9, San Francisco.
Table 7-3 - Pollutant Concentrations for a Typical Refinery Wastewater
Parameter
Trace Metals
Arsenic
Chromium
Copper
Mercury
Nickel
Selenium
Zinc
Trace Organics
Benzene
Toluene
Ethylbenzene
Acenaphthene
Benz[a]anthracene
Benzo[a]pyrene
Chrysene
Phenanthrene
Pyrene
2,4-Dimethylphenol
Value
(mg/L)
0.0050
0.0680
0.0180
0.0009
0.0100
0.0172
0.0610
0.0005
0.0005
0.0008
0.0011
0.0004
0.0007
0.0003
0.0002
0.0005
0.0022
Basis
API (1978; 1981)
API (1978; 1981)
API (1978; 1981)
Ruddy (1 982)
API (1978; 1981)
Ruddy (1 982)
API (1978; 1981)
API (1978; 1981)
API (1978; 1981)
API (1978; 1981)
Ruddy (1 982)
API (1978; 1981)
API (1978; 1981)
API (1978; 1981)
Ruddy (1 982)
API (1978; 1981)
API (1978; 1981)
46
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Mercury Emissions to Air
The primary opportunities for atmospheric emissions of
mercury in oil and gas production and processing
operations are fuel combustion (discussed in
subsequent Sections), mercury in fugitive emissions
and gas flares at primary production operations.
The amount of gas that is flared annually in the U.S. is
approximately 7 billion cubic meters (for year 1996,
U.S. DOE 1999) and the trend is downward. Flared gas
typically originates from gas co-produced with oil
production in situations where economics dictate that
flaring is less expensive than collection and transport.
The mercury concentration in flared gas is not reported.
If one assumes flare gas contains on the order of 1
ug/m3 then the annual amount emitted in flared gas is
on the order of 7 kg. This order of magnitude estimate
does not include mercury in flares at refineries. In most
refineries, gas used to regenerate catalysts (some
catalysts collect mercury and release it when
regenerated) is sent to flares and may contain higher
amounts of mercury than typical for other types of gas
flares.
Approximately 9 billion m3 of methane is emitted
annually by the gas industry (Kirchgessner et al. 1997).
Approximately 90 percent of emitted gas is non-
combusted methane and about 10 percent compressor
discharge. The concentration of mercury in wellhead
natural gas is likely higher than in pipeline gas by a
factor of 2-3 based on the distribution of mercury in gas
processing (Wilhelm 1999). Assuming an upper limit of
1 |jg/m3 mercury in wellhead gas, the amount of
mercury in fugitive natural gas emissions is on the
order of 10 kg.
Approximately 1 million metric tons of methane
(equivalent) are estimated to be emitted from petroleum
production, transportation and processing (year 1999,
U.S. DOE 1999). 90 percent of such emissions are
associated with production and about half of the
production related amount is from vents on oil tanks.
While the amount of mercury in such emissions is not
known, a rough estimate is possible. The distribution of
mercury in oil to vented gases can determined by
Henry's law. Henry's constant for mercury in oil is the
solubility divided by the vapor pressure (2 ppm/25
mg/m3). The upper limit amount of mercury in 1 million
metric tons (1.5 billion m3 methane) would be no
greater than approximately 185 kg if the mean mercury
in oil concentration is 10 ppb.
The Clean Air Act (CAA; 42 U.S.C. 85) requires the
U.S. EPA to develop national emission standards for
hazardous air pollutants (NESHAP) for source
categories. The CAA implements NESHAP via
requirements for maximum achievable control
technology (MACT). Mercury is a listed hazardous air
pollutant (HAP) under Section 112 of the CAA. The
source categories that are of interest to petroleum
producers and refiners are boilers, certain refining
process units and miscellaneous combustion sources.
NESHAP for petroleum refineries apply to catalytic
cracking units (CCU), catalytic reforming units (CRU),
and sulfur plant units (SPU). Of these, only process
vents associated with CRU catalyst regeneration are
scrutinized relative to mercury. While EPA has
identified particulate metals (PM = antimony, arsenic,
beryllium, cadmium, chromium, cobalt, lead,
manganese, and nickel) as HAPs from CRU process
vents, mercury is not included because it is volatile in
atomic form and not easily controlled by existing
particulate control technology. EPA, as of 1998,
concluded that because mercury is not well controlled
by PM air pollution control devices ESPs as well as
PM scrubbers), the MACT floor for Hg in CCU process
vents is determined to be no control for both new and
existing units. Data are not available to estimate
mercury emissions from either CCUs or CRUs.
Metal emission factors are used to estimate air
pollutant emissions to the atmosphere of volatile or
particulate metals or metal compounds (U.S. EPA
1997c). They relate the quantity of pollutants released
from a source to an activity associated with those
emissions. For metals in refinery unit processes,
emission factors are usually expressed as the weight of
pollutant emitted divided by a unit weight or volume of
the activity emitting the pollutant (e.g., pounds of
mercury emitted per gallon of fuel oil burned). Emission
modification factors are used to estimate a source's
emissions by the general equation:
EMF =AxEFx[1-(ER/100)]
where:
EMF = emissions modification factor,
A = activity rate,
EF = uncontrolled emission factor, and
ER = emission reduction efficiency in % for
pollution control.
California Assembly Bill 2588 (entitled the Air Toxics
Hot Spots Information and Assessment Act of 1987)
required petroleum processing facilities in California to
inventory their air emissions of designated toxic
materials (including mercury) for the purpose of
assessing the health risks to surrounding communities.
47
-------
Data for compliance with the California statute are
compiled and reported by the American Petroleum
Institute and Western States Petroleum Association
(API and WSPA 1998). Emission factors were
developed for externally fired boilers and heaters,
internal combustion engines, gas turbines and direct-
fired processes. The test method used for mercury
involved isokinetic collection of particulate and gaseous
mercury in potassium permanganate (KMnO4) solution.
In the method employed, the collected mercuric form
(produced by oxidation by the permanganate) was
reduced to elemental Hg and then sparged from the
solution into an optical cell and measured by atomic
absorption spectrometry.
Table 7-4 summarizes the emission factors reported in
the API/WSPA study (1998). The compiled list
represents data from ongoing activities and includes
only a small fraction of the unit operations and process
systems that are potential sources. The California
program that examined air toxic emissions from
refineries adopted priorities based on suspected
sources for a large number of pollutants. Thus,
although mercury was examined as a part of the
program, it was (and is) not necessarily the primary
focus or priority. The data do provide some clues and
insights into certain refinery operations and the
magnitude of their mercury emissions.
The asphalt blowing process polymerizes asphaltic
residual oils by oxidation with air. The objective is to
increase the melting temperature and hardness of the
asphalt and thus achieve improved properties
depending on the type of asphalt product (road
materials, construction materials, roofing material, etc)
desired. The process involves blowing heated air
through the oils in a batch or continuous process to
oxidize the polycyclic aromatic compounds that
comprise the majority of the asphaltic material. The
process operates at approximately 400-450° C and
thus may partially volatilize HgS. The distribution of
mercury compounds emitted in asphalt blowing is
unknown.
Process heaters or furnaces are used to heat feed
materials to the required reaction or distillation
temperature levels. The fuel burned may be still gas,
natural gas, residual or distillate fuel oils, or
combinations, depending on economics, operating
conditions, and emission requirements. Assuming
mercury in distillate and residual fuel oils is the
elemental form, then one would expect that the emitted
mercury species would be the elemental form and
mercury oxides, the relative percentage of each
depending upon furnace type and efficiency.
Coke calcining is a high temperature pyrolysis
treatment of raw petroleum coke with the primary
objective to produce coke properties suitable for a
particular end use. In the calcining process, moisture
and volatile material are removed and carbonization
and aromatization processes that started in the coker
are completed. The calciner can be heated by a variety
of fuels and to a variety of temperatures depending on
product properties but typically in the range of 400 to
500° C. These temperatures are sufficient to cause
partial volatilization of HgS in coke.
In Table 7-4, the mercury emissions factors are
calculated from crude fired steam generators in three
tests using 3 crude sources. One source has elevated
mercury (5 x 10~3 Ib/Mgal, 700 ppb) while the other two
were
ppb).
were much lower (5 x 10~5, 9 x 10~6 Ib/Mgal; 7 ppb, 1
Some additional evidence for fuel oils is available from
U.S. EPA studies (U.S. EPA 1998) of mercury emission
factors for utility boilers. EPA measured mercury
emission factors for several furnace types used by
utilities. In this study, U.S. EPA (1998) cited mercury in
residual fuel oil as 0.6 Ib per trillion Btu based on
analysis of 4 samples of fuel oil (mean standard
deviation = 0.3). The conversion factor applied was
150,000 Btu/gallon of density 8.2 Ib/gallon, thus yielding
a mean mercury concentration of approximately 10
ppb.
48
-------
Table 7-4 - Mercury Emission Factors for Refinery Processes
(API/WSPA 1998)
Process
Asphalt Blow
Boiler
Boiler
Boiler
Coke Calcining
Heater
Heater
Heater
Heater
Steam Generator
Steam Generator
Turbine
Turbine
Fuel
Gas
Fuel Oil
Still Gas
Still Gas
Gas
Fuel Oil
Still Gas
Still Gas
Still Gas
Crude
Crude
Still Gas
Still Gas
APC(1)
TO
None
None
SCR
SD/FF
None
DeNOx
None
SO2 Scrub
None
SO2 Scrub
SCR/COC
COC
Emission
Factor
9.00E-03
1 .03E-05
3.23E-04
3.23E-04
4.63E-05
1 72E-05
2.02E-04
2.02E-04
2.02E-04
2.19E-03
2.19E-03
4.63E-03
2.15E-02
Units
Ib/MMcf
Ib/Mgal
Ib/MMcf
Ib/MMcf
Ib/ton coke
Ib/Mgal
Ib/MMcf
Ib/MMcf
Ib/MMcf
Ib/Mgal
Ib/Mgal
Ib/MMcf
Ib/MMcf
No. of
Tests
1
1
1
1
1
1
1
1
1
3
3
2
1
Hg(2)
146 (3)
1.4
5.2
5.2
23
2.4
3.3
3.3
3.3
327
327
75
348
Units
l-ig/m3
ppb
|ig/m3
l-ig/m3
ppb
ppb
l-ig/m3
|ig/m3
l-ig/m3
ppb
ppb
l-ig/m3
|ig/m3
(1) APC - air pollution control; COC - CO Oxidation Catalyst; DeNox (SNCR) - Selective Non-Catalytic A/Ox
Reduction; FF - Fabric Filter; SCR - Selective Catalytic A/Ox Reduction; SD - Spray Dryer; TO - Thermal Oxidizer.
(2) Calculated concentration in the fuel assuming the emission ratio (THg out/ THg in) is 1.
(3) Calculated Hg concentration in air emitted to the atmosphere.
Mercury Emissions Via Solid Waste
Streams
Under the Resource Conservation and Recovery Act
(RCRA; 42 U.S.C. 321), materials containing mercury or
mercury compounds are regulated as hazardous solid
waste if they meet the regulatory definition of solid waste
and the definition of hazardous waste. The hazardous
category is achieved if the material exhibits either a
defined characteristic or is specifically listed by EPA as
hazardous. At present, U.S. EPA does not list waste
streams from exploration, production or refining as
hazardous according to any mercury content criteria.
Solid wastes directly associated with exploration and
crude oil or natural gas production are exempted from
regulation as hazardous wastes. The exempted
categories include drilling fluids and other wastes
directly related to production. For this reason, such
wastes are infrequently scrutinized for metals content
and data are scarce upon which one might estimate the
totals for this category.
Wastes are designated as characteristically hazardous
based on the concentration of mercury in waste
leachate as determined by the Toxicity Characteristic
Leaching Procedure (TCLP). Refinery solid waste
streams are routinely examined using TCLP for metals
leachability characteristics and treated according to
RCRA requirements. In general, solid waste streams
from refineries are not characteristically hazardous due
to mercury content. RCRA data on TCLP are not
typically reported unless the waste stream does not pass
and then they are reported under TRI (see discussion
below).
Drilling wastes primarily consist of the extracted
cuttings and drilling mud from the boreholes of
exploratory wells (also workovers and injection wells).
The drilling industry generated approximately 24 billion
liters of such waste in 1995 (API 1995). Petrusak et al.
(2000) reports statistics for drilling wastes produced
onshore in the U.S. About 13 percent of such wastes
are re-injected, 47 percent are evaporated on site and
most of the remainder is buried on site.
Data on mercury content of drilling wastes are not
generally reported but TCLP test results typically do not
identify this category of waste as characteristically toxic
due to mercury content. The reason for this fact is that
subterranean mercury (as would be in the cuttings from
drilling operations) is found almost exclusively as HgS
or as a substitutional element in minerals (mostly
pyrites). In addition most of the mercury in drilling muds
comes from the mineral ingredients (barite) used to
make the mud, not from the drill cuttings, except in rare
situations. In these mineral forms mercury is not water
soluble and thus not extractable by TCLP.
49
-------
Mulyono et al. (1996) reported analysis of four water-
base drilling muds (Indonesia) as having mercury
concentrations between 144 and 2141 ppb (mean 750
ppb). These concentrations were for fresh mud and the
concentrations did not change after use. Approximately
20 percent of the mercury was nitric acid extractable.
Under the Emergency Planning and Community Right-
to-Know Act (EPCRA; 42 U.S.C. 116), companies that
manufacture, process, or use toxic chemicals must
report annually a Toxic Release Inventory (TRI) to both
the U.S. EPA and the appropriate state agency.
Mercury and mercury compounds are included in the
list of more than 650 chemicals that must be reported.
Although petroleum production is generally excluded,
refineries are not if they process crude oil containing
more than the threshold reporting amount. Prior to this
year (2000) the threshold was sufficiently high to
exclude reporting of mercury in crude oil and refined
products.
In 1997, the U.S. EPA expanded the types of
companies that report TRI to include electric utilities
and petroleum bulk terminals and stations (amongst
others). In 1999, under EPA's PBT Chemicals Initiative,
EPA created a new PBT group within TRI, and then
significantly modified the TRI reporting requirements for
this group of chemicals by lowering the thresholds that
trigger reporting. The final rule (EPCRA, Section 313)
criterion for PBTs was promulgated this year (2000)
and defines the threshold reporting amount for mercury
as 10 pounds.
In the new rules promulgated for 2000 for PBT
pollutants, EPA also eliminated the de minimis
exemption of 0.1 percent that previously excluded
reporting of trace constituents of chemical feedstocks.
Thus refineries, bulk terminals and some other
petrochemical processors must now report mercury if it
exceeds the yearly threshold amount of 10 pounds.
Given the new requirements it is likely that it will soon
be possible to estimate the contribution of mercury in
solid waste from petroleum and gas production and
processing to the global burden based on a better
statistical database. At this point in time it is not
possible to accomplish this task with any confidence as
to accuracy.
Mercury in Crude Oil
Crude oil contains both dissolved and suspended
mercury compounds and, although analysis for total
mercury in crude oil yields the sum of both forms, the
concentration of suspended forms that is obtained from
sampling crude oil is highly dependent on the location
that samples are taken in the production and refining
process. Furthermore, given that the fates of
suspended forms (HgS) and dissolved forms are
different, the concentration of each is important to
predicting the fate of mercury in a refinery.
Filby and various colleagues (Shah, Filby and Haller
1970, Filby and Shah 1975, Hitchon, Filby and Shah
1975, Hitchon and Filby 1983) measured mercury in
crude oils using neutron activation analysis. This early
work was directed to associating chemical
characteristics of crude oil with geologic origin for
exploration purposes.
Shah et al. (1970) report concentrations for 10 crude
oils as shown in Table 7-5. The procedure involved pre-
filtration (1 |im pore size) of the oil; hence mercury
existing as particulates above 1 |im was not measured.
One of the crude oils examined by Shah (California
Cymric) was unusual in having had a total mercury
concentration above 10 ppm. This crude was popularly
analyzed during the 1970's because the high mercury
concentration was advantageous to analytical method
development and thus it became popular amongst
analysts in the early studies.
Shah's data are the basis for U.S. EPA early estimates
(Brooks 1989) of ppm levels for the mean amount of
mercury in crude oil. The exercise (by EPA) to arrive at
a mean amount involved averaging the mean or
median of the range of concentrations from the early
studies of Shah and Filby. The inclusion of Cymric in all
of the early compilations provided a disproportionate
emphasis of this anomalous source.
Filby and Shah (1975) report crude oil data for four
samples identified by country of origin (see Table 7-6).
It is not known if the California oil analyzed by Filby and
Shaw is Cymric, but likely so. Hitchon and Filby (1983)
measured total mercury in 86 crude oils (and two tar
sands) from Alberta, Canada. Thirty-seven samples
had mercury concentrations below the detection limit
(DL) of 2 ppb. Forty-nine samples were above DL with
a mean of 50.0 ppb (maximum concentration of 399
ppb). The data are summarized in Table 7-7. The
average of 86 crude oils (22 ppb) was calculated by
assigning a value of half the DL to those exhibiting total
mercury (THg) below the detection limit.
Musa et al. (1995) reported total mercury in Libyan
crude oils to be in the range of 0.1 to 12 ppb (Table 7-
8). Liang et al. (2000) reported the mean concentration
of mercury in 11 crude oils (source not identified) as 4
ppb (range = 1 to 7 ppb). Magaw et al. (1999) reported
data on 26 crude oil types purchased by U.S. west
coast refineries as less than 10 ppb (the detection limit
of the CVAA instrument). Magaw et al.'s data (Table 7-
50
-------
9) span the major U.S. crude streams and include both
domestic and imported crudes. Magaw et al. report one
California crude oil (Cymric) as having 1.5 ppm THg.
Bloom (2000) found total Hg in unfiltered crude oils
ranging between sub-ppb levels to over saturation
(several ppm, see Table 7-10). The mean
concentrations for total mercury in crude oil (1.5 ppm)
that Bloom reported is much higher than other reported
data. This is due to the fact that the data set contains a
large number of samples from one field that presented
processing difficulties and hence was extensively
analyzed. Bloom's reported mean is derived from the
number of samples analyzed in his laboratory and not
based on crude oil sources. The crude oil samples in
the upper half of Bloom's data come mostly from one
field in South America producing less than 30,000 bpd.
The mean of the lower half of Bloom's data for crude
oils is 1 ppb.
Much of Bloom's condensate data reflects samples
from the Gulf of Thailand. These Asian condensates
are not processed in the U.S. but are prevalent in
reported data (Tao et al. 1998, Shafawi et al. 1999,
Bloom 2000) because they are problematic to
petrochemical manufacture. The mean concentration of
the lower half of condensate samples that were
analyzed in Bloom's laboratory was reported as
approximately 20 ppb.
The New Jersey Department of Environmental
Protection Mercury Task Force, in a recently completed
study of oil processed in New Jersey refineries,
reported mercury concentrations in crude oil compiled
in Table 7-11 (Morris 2000). The reported data
identified crude oil origin. The number of samples
analyzed and standard deviations were not reported.
According to Morris' data, the mean amount of mercury
in crude oil imported to the U.S. East Coast refineries is
less than 5 ppb.
Environment Canada (2000) has compiled a database
on oil properties that includes metals analysis using
ASTM method D 5185 (Inductively Coupled Plasma
Atomic Emission Spectrometry; ICP-AES). Table 7-12
compiles the reported mercury concentrations in the EC
database. The ICP-AES method has a detection limit
for mercury of 15 ppb.
Duo et al. (2000) reports analytical data for 8 crude oils
that are representative of 50 percent of all crude oil
processed in Canada. The exact origins of the crude
oils were not divulged but many of these same oils are
also processed in the U.S. The method used was a
variation of digestion/CVAA. The method had a
minimum detection limit for mercury of 2 ppb. Most of
the data are below this amount as shown in Table 7-13.
Total mercury concentrations in crude oil (summarized
in Table 7-14) cannot be statistically treated at present,
in part because of the uncertainties in the analytical
data, and also due to the fact that much of the data
reported in the literature are not well documented as to
origin. While the majority of recently reported data are
less than 20 ppb total mercury there are exceptions in
the ppm range, notably Bloom 2000, Shah et al. 1970
and Magaw et al. 1999 (one sample from California).
The data for condensates are generally higher than for
crude due to a preponderance of data on Asian
condensates that are more frequently analyzed due to
their difficulty in processing.
51
-------
Table 7- 5 - Total Mercury Concentrations in Crude Oil by NAA
(Shahetal. 1970)
Source
California
California
California
California
California
Libya
Libya
Libya
Louisiana
Wyoming
Mean
Amount
(ppb)
114
81
88
29,688
78
2,079
62
75
23
77
3,200
SD
(ppb)
2.8
1.9
3.0
103.9
2.4
11.9
5.1
1.7
1.8
3.4
Notes
Detection Limit 4 ppb
Cymric
Range 23 - 30,000 ppb
Table 7-6 - Total Mercury Concentrations in Crude Oils by NAA
(Filby and Shah 1975)
Source
THg
(ppb)
Notes
California (Tertiary)
Venezuelan poscan)
Alberta (Cretaceous)
Libya
Mean
23,100
27
84
<4
5,803
5 Replicates; Mean = 21,200; S.D. 0.36
Detection Limit 4 ppb
52
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Table 7-7 - Total Mercury Concentrations in Alberta Crude Oils
(Hitchonand Filby 1983)
Stratigraphic Number
Era _ ,
Samples
Upper Cretaceous 21
Lower Cretaceous 18
Jurassic 3
Triassic 4
Carboniferous 8
Devonian 32
Total 86
(1) Detection limit = 2 ppb
(2) Calculated by assuming
-------
Table 7-9 - Mercury Concentrations in U.S. West Coast Crude Oils
(Magawetal. 1999)
Region
Middle East
Africa
North America
Asia
South America
North Sea
Number
of
Samples
2
4
11
4
4
1
26
Range
(ppb)
<10(1)
<10
<1 0-1, 560
<10
<10
<10
ND- 1,560
Mean
(ppb)
<10
<10
146
<10
<10
<10
65
(1) DL = 10 ppb
Table 7-10 - Total Mercury Concentrations in Crude Oils
(Bloom 2000)
Number of
Samples
76
37
39
Range
(ppb)
NR(1)
NR
NR
Mean
(ppb)
1,505
1
3,000
SD
3,278
1.49
4,140
Notes
All
Lowest 37 samples
Top 39 samples
(1) NR - not reported
54
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Table 7-11 - Mercury Concentrations in Crude Oils
Processed in New Jersey Refineries
(Morris 2000)
Type
Africa (Angola)
Africa (Angola)
Africa (Congo)
Africa (Gabon)
Africa (Nigeria)
Africa (West)
Africa (West)
Arabia (Dubai)
Canada (Newfoundland)
Mexico
Mexico
Mixed
North Sea
North Sea
North Sea
North Sea
Saudi Arabia
South America (Columbia)
South America (Columbia)
South America (Venezuela)
South America (Venezuela)
South America (Venezuela)
South America (Venezuela)
MEAN
Mean THg
(ppb)
2.7
1.5
1.8
1.8
1.0
3.2
1.5
2.9
1.9
2.7
0.1
3.1
3.4
9.3
2.5
4.7
5.7
12.3
2
4.8
5.1
0.8
6
3.5
Field
Palanca
Soyo
Kitina
Rabi
Escravos
Nemba
Ecofisk
Gullfaks
Nome
Range = 0.1 - 12.3
55
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Table 7-12 - Total Mercury Concentrations in Crude Oils
(Environment Canada 2000, Cao 1992)
Field Name
Location
THg
(ppb)
Notes
Alberta Sweet
Cold Lake Bitumen
Transmountain Blend
Terra Nova
Bent Horn A-02
Taching
Iranian Heavy
Maya
Ninian Blend
Oseberg
Arabian Light
California (API 11)
Carpinteria
Dos Quadras
Hondo
Platform Irene
Port Hueneme
Santa Clara
Sockeye
W. Texas Intermediate
W. Texas Sour
Alaska North Slope
BCF24
Boscan
Lagomedio
Canada (Alberta)
Canada (Alberta)
Canada (Alberta)
Canada (Newfoundland)
Canada (NWT)
China
Iran
Mexico
North Sea
North Sea
Saudi Arabia
U.S. (CA)
U.S. (CA)
U.S. (CA)
U.S. (CA)
U.S. (CA)
U.S. (CA)
U.S. (CA)
U.S. (CA)
U.S. (TX)
U.S. (TX)
U.S. (AS)
Venezuela
Venezuela
Venezuela
Crude
Bitumen
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
Crude
(1) DL = 15 ppb
56
-------
Table 7-13 - Mercury Content of Crude Oils Processed in Canada
(Duo et al. 2000)
Crude Oil Concentration (ppb)
Minimum Maximum Mean
A
B
C
D
E
F
G
H
Mean
<2
<2
<2
<2
<2
<2
<2
<2
Table 7-14 - Summary of THg
Reference
Shahetal. 1970
Hitchon and Filby
1983
Filby and Shah.
1975
Musa et al. 1995
Taoetal. 1998
Magaw et al. 1999
Bloom 2000
Liang et al. 2000
Morris 2000
Cao 1992
Duo et al. 2000
Olsen et al. 1997
Bloom 2000
Shafawi et al. 1999
Tao et al. 1998
Type
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Condensate
Condensate
Condensate
Condensate
Number
of
Samples
10
86
4
6
1
26
76
11
23
<2
<2
<2
9
<2
<2
<2
7
in Crude Oils
Range
(ppb)
23 - 29,700
<2 - 399
<4- 23,100
0.1 -12.2
<1 0-1, 560
NR(1)
1.6-7.2
0.1 -12.2
24 AIKDL=15
8
4
18
5
7
<2-9
NR
NR
9-63
15-173
and Gas
Mean
(ppb)
3,200
22
5,803
3.1
<1
65
1,505
4.4
3.5
8
1.6
15
3,964
30
40
<2
<2
<2
2
<2
<2
<2
4
1.5
Condensates
SD Notes
U.S. and imports
63.6 Canada
U.S. and imports
4.2 Libyan
Asia
West Coast
Refineries
3,278 Origins not reported
1.0 Origins not reported
New Jersey
Refineries
Canada and Imports
Canadian
Refineries
Origins not reported
1 1 ,665 Mostly Asian
18.6 S.E.Asia
Asian
(1) NR - not reported
57
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Mercury in Refined Products
Recently reported data for mercury in refined products
are compiled in Table 7-15. Bloom (2000) reported
mercury in U.S. light distillates and fuel oil close to 1 ppb
(46 samples). Liang et al. (1996) reported mercury in
U.S. gasoline and diesel less than 5 ppb.
A statistical ensemble for mercury in refinery products
exists in only one case. Total mercury in petroleum coke
was reported as part of the U.S. EPA reporting
requirements on fuel feeds to utility boilers (U.S. EPA
2000) and the mean is approximately 50 ppb (1000 data
points, 2 million tons). The distribution of mercury
concentrations in petroleum coke is shown in Figure 6.4.
Table 7-16 summarizes the data for mercury
concentrations in fuel oil. The U.S. EPA emissions
estimates used in the Report to Congress (U.S. EPA
1997a) are not well documented as to the origin of fuel
oil concentration data. Details are discussed in the
Section titled U.S. EPA Estimates.
Table 7-15 - Summary of THg in Refined Products
Reference
Liang et al. 1996
Liang et al. 1996
Liang et al. 1996
Liang et al. 1996
Liang et al. 1996
Liang et al. 1996
Bloom 2000
Bloom 2000
Bloom 2000
Olsen et al. 1997
Tao et al. 1998
U.S. EPA 2000
Type
Gasoline
Gasoline
Diesel
Diesel
Kerosene
Heating Oil
Light distillates
Utility fuel oil
Asphalt
Naphtha
Naphtha
Petroleum
Coke
Number of
Samples
5 0
Range
(ppb)
.22 - 1 .43
4 0.72-3.2
1
1
1
1
14
32
10
4
3
1000
0.4
2.97
0.04
0.59
NR
NR
NR
3-40
8-60
0-250
Mean
(ppb)
0.7
1.5
0.4
2.97
0.04
0.59
1.32
0.67
0.27
15
40
50
SD
NR(1)
NR
NR
NR
NR
NR
2.81
0.96
0.32
NR
NR
NR
Notes
U.S.
Foreign
U.S.
Foreign
U.S.
U.S.
U.S.
U.S.
U.S.
Asian
U.S.
(1) NR - not reported, ND - not detected
Table 7-16 - Summary of Mercury
Reference
Liang et al. 1996
Bloom 2000
EPA1997b
EPA1997b
EPA1997a
EPA1997a
EPA1997a
EPA 1998
Type
Heating Oil
Utility fuel oil
RFO 6
DF02
Utility RFO
Commercial
RFO/DFO
Residential
RFO/DFO
RFO
Number of
Samples
1
32
6
3
4
Concentrations in Fuel
Range
(ppb)
0.59
NR
2-6
Mean
(ppb)
0.59
1
4 (1)
<120(2)
10
100
100
10
Oils
SD
NR(3)
0.96
0.3
Notes
U.S.
U.S.
Measured
Calculated
Calculated
(1)Median (2) Average (3) ND - not detected
58
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Estimate of Mercury Emissions
from Refineries
Wilhelm (2001 in press) constructed an estimate of
mercury emissions from petroleum in the U.S. for the
year 1999. The macro-analysis Wilhelm constructed
(Table 7-17) considered the amount of mercury in
crude oil, the distribution of mercury in the refining
process as well as the combustion processes for the
fuel products derived from crude oil. Wilhelm drew
attention to the fact that analytical uncertainties and
lack of information on sample origin obfuscate
calculation of the mean concentration of mercury in
crude oil and many refined products. The estimation
model was constructed to provide a framework to
identify major streams that require statistical definition
as to mercury concentration.
In Table 7-17, estimates of the total yearly amount in
major crude oil streams were calculated by multiplying
the source crude feedstock amounts (year 1999; U.S.
DOE 2000) by estimated mean concentrations of
mercury reported for regional crude oil sources, both
domestic and imported. Wilhelm based his estimates of
the mean concentration of mercury in major crude
streams on the recently reported data of Morris (2000),
Environment Canada (2000) and Magaw et al. (1999)
but acknowledged that the actual mean concentrations
for crude oil from some sources could be an order of
magnitude higher or lower than those used in Table 7-
17.
The model predicted that, if the amount of mercury in
crude oil (including condensates) processed in the U.S.
is close to 10 ppb on average, then the total amount of
mercury in crude oil is approximately 8,500 kg. Of this
amount, approximately 7,000 kg resides in refinery
products. Approximately 15 percent of refinery products
(asphalt, lube oils, solvents) are not burned, leaving
approximately 6,000 kg emitted to the atmosphere
mainly by combustion (Wilhelm included refinery fuel
combustion and assumed an emission factor of 1). The
mean amount of mercury in U.S. transportation fuels
(gasoline + diesel + jet fuel) had a major impact on the
estimate (due to the fact that half of refined products fall
into this category). The mean was considered to be no
greater than 3 ppb based on the data of Liang et al.
(1996) and data for other distillates.
Wilhelm estimated atmospheric emissions of mercury
from refineries from a mass balance with other avenues
of egress from refineries and assumed that combustion
of fuels accounts for the primary path of emission. From
energy usage at U.S. refineries (U.S. DOE 2000)
compiled in Table 7-18 and the estimated total mercury
concentrations in refined products, Wilhelm estimated
the amount of mercury in air emissions from fuel
burning at all U.S. refineries to be no more than
approximately 1,500 kg/year or about 25 percent of the
total amount of mercury in refinery combusted fuel
products (6,000 kg/year). The higher percentage
amount assigned to refineries appears to be due to the
fact that the major fuels utilized at refineries (coke, still
gas) have higher, on average, mercury concentrations
than other fuel products. While the concentration of
mercury in coke is known, the amount in still gas is
much less certain.
Wilhelm argued that mercuric sulfide, originating as
either suspended in crude oil or as the reaction product
of other forms of mercury with sulfur in the refining
process, is suspected to concentrate in the heavier
fractions so the known amount in coke (50 ppb, U.S.
EPA 2000) seemed reasonable (to Wilhelm) relative to
the amount in lighter fractions. Even if mercury does
not concentrate in coke, its concentration is known with
some confidence and should serve as an upper limit to
the amount in crude oil, given that light distillates exhibit
relatively lower mercury concentrations (<5 ppb). It was
argued that if elemental mercury in crude oil partitions
to still gas, then the mercury concentration in light
distillates would be expected to be elevated as well.
Based on these arguments, it was concluded that
mercury in distillates likely reflected the amount of
volatile elemental mercury in crude oil and the amount
in coke reflected the amount of HgS and other
suspended forms.
Perturbation of the proposed model to a lower mean
concentration for mercury in crude oil actually produces
a somewhat better fit to the existing data. As an
example, if one applies the origin specific
concentrations in Table 7-11 (Morris 2000) to the
volumes of oil that derive from known major import
sources, then one may calculate with better confidence
that 35 percent of all crude processed by U.S. refineries
contains no more than approximately 1,500 kg total
mercury as opposed to approximately 3,000 estimated
by Wilhelm based on an upper limit of 10 ppb in crude
oil. These calculations are shown in Table 7-19. The
mean concentration applied to imported oil streams is
rounded to 5 ppb due to the lack of statistical details.
Numerous major uncertainties exist in the cited analysis
including the estimates for refinery wastewater and
solid waste (previously discussed), data for mercury in
refined products, and discrepancies between crude oil
data obtained by differing analytical methods. Wilhelm
rightly cautioned that any estimation model for mercury
in petroleum should be viewed with skepticism until
additional data are obtained and in light of the fact that
a complete statistical understanding of the amounts of
59
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mercury in crude oil or in refined products is not
presently available. In addition, Wilhelm cautions that
mercury emission factors for many combustion sources
that burn liquid fuels are not now (2000) known.
Duo et al. (2000) examined emissions from Canadian
refineries. The method Duo applied was similar to
Wilhelm's but did not consider mercury in wastewater or
solid waste streams in his mass balance. Duo concluded
that the amount of mercury emitted from Canadian
refineries (to the atmosphere) was the difference
between mercury in crude oil and mercury in refined
products. Based on Liang et al.'s (1996) data for refined
products, Duo concluded that greater than 90 percent of
mercury in Canadian crudes is emitted during the
refining process.
Table 7-17 - Estimates of Mercury in Crude Oil and Refined Products
(for year 1999, Wilhelm 2001)
Type bpy
(U.S. DOE 2000) (U.S. DOE 2000)
(109)
Crude Oil
Domestic (40%)
Imported (60%)
Total (IN)
Refined Products
d = 0.75
d = 0.80
d = 0.85
d = 0.85
d=1.10
d = 0.90
d = 0.55
Wastewater
(Ruddy 1982)
Solid waste
(U.S. EPA 1996)
Air (Table 7-12)
Air (fugitive)
Total (OUT)
Alaska (18%)
COM (20%)
Other (62%)
Canada (15%)
Mexico (15%)
Middle East (20%)
Other (50%)
Motor fuels (60%)
Naphthas (5%)
Residual fuel oil
(5%)
Distilled fuel oil
(21%)
Petroleum coke
(3%)
Heavy oils (3%)
Still Gas (3%)
0.4
0.5
1.5
0.5
0.5
0.8
1.8
6.0
3.7
0.3
0.3
1.3
0.2
0.2
0.2
6.2
1.5
kg/y
do11)
0.5
0.7
2.0
0.7
0.7
1.1
2.4
8.1
4.4
0.4
0.4
1.8
0.3
0.3
0.3
7.9
2.5
0.3
T1 , Estimated
THg Total
ppb kg/y
<10 500
<10 700
<10? (1) 2,000?
<10? 700?
<10 700
<10 1,100
<10? 2,400?
8,100
<2? 900?
<5 200
<10? 400
<5 900
50 1 ,500
50 1 ,500
<30? 900?
6,300
1 250
40? 7,200?
(1,500) (2)
250?
8,000
(1) question marks indicate major uncertainties in the estimated mean concentration
(2) from fuels used in refineries, included in total for all refinery products
60
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Table 7-18 - Fuels from Crude Oil Used by Refineries
(U.S. DOE 2000)
Fuel Type
LPG
Still gas
RFO/DFO (1)
Heavy Oils
Coke
Total
bpy
(106)
4
235
6
6
90
kg/y
(109)
0.4
20.6
0.8
0.9
15.8
THg
(ppb)
<10
<30?
<10
50
50
Amount
(kg Hg/y)
4
600
86
5
800
1,500
(1) residual fuel oil/distillate fuel oil
Source
Table 7-19 - Mercury in Major Crude Oil Imports
(Calculated from the data of Morris 2000)
bpy (1999) Percent of U.S. Total
(10*)
(6 x 10" bpy)
THg
(ppb)
Yearly amount
(kg Hg/y)
Venezuela
Middle East
African
Mexico
North Sea
0.50
0.74
0.22
0.48
0.15
8
12
4
8
3
5
5
5
5
5
359
531
158
345
108
Total
2.1
35
1,500
Mercury in Combusted Gas and Estimated
Emissions
Only limited data are available that provide specific
concentrations of mercury in gas or gas condensate
processed in the U.S. Chao and Attari (1993) surveyed
U.S. pipeline gas using gold collection and CVAA to
measure mercury. The sample volumes and detector
sensitivity combined to produce relatively high limits of
detection. Chao's data are reported in Table 7-20 and,
although the gas distribution system in the U.S. is well
covered, the reported concentrations do not provide
exact concentrations, only upper detection limits.
U.S. dry gas consumption in 1999 was approximately
525 billion cubic meters (U.S. DOE 2000). Using Chao
and Attari's higher concentration (THg<0.2 ug/m3) then
the maximum amount of mercury released to the
atmosphere from burning natural gas would be
approximately 100 kg. Using the lower number
(THg<0.02 ug/m3) the maximum amount would be
approximately 10 kg. Although the estimate for gas
provides some reassurance that natural gas is clean and
preferable to other types of fossil energy, the actual
mean amount of mercury in U.S. gas supplies remains to
be demonstrated.
61
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Table 7-20 - Total Hg Concentration in U.S. Pipeline Gas
(Chao and Attari, 1993)
Pipeline Composition (Source)
Mean THg
(ug/m3)
70-75% Gulf Coast, 25-30% Mid-continent <0.2
70-75% Mid-continent, 25-30% Rocky Mountain <0.2
Offshore Gulf Coast <0.2
Offshore Gulf Coast <0.2
Coal Seam <0.2
Appalachian <0.2
Appalachian Shale <0.2
Illinois Basin <0.2
San Juan Basin <0.2
55% Permian, 15% NM, 6 % Anadarko, 24% San Juan <0.2
56% San Juan, 44% Permian <0.2
75% Rocky Mountain, 25 % Canadian <0.2
California <0.1
California <0.1
Canadian <0.1
Canadian <0.02
80% Permian, 20% San Juan <0.02
Gulf Coast <0.02
Guff Coast <0.02
U.S. EPA Estimates
U.S. EPA estimates of mercury emissions from fuel oil
and gas are summarized in Table 7-21. Estimated
emissions of mercury to the atmosphere from
combusted fuels were compiled in the 1997 Mercury
Report to Congress (U.S. EPA 1997a). The EPA
estimated that approximately 11 tons of mercury
originated from burning fuel oil in boilers (utility,
commercial, residential) in the year analyzed (1994-95).
The method of estimation involved calculating an
emission factor (Ib Hg/Btu) and applying this factor to the
yearly fuel oil consumption.
The estimate for mercury emissions from utility boilers in
the EPA Mercury Report to Congress was based on an
ongoing (at that time) investigation of hazardous air
pollutants (HAPs) in fossil fuel fired utility boilers (U.S.
EPA 1998). The results of the utility toxics study were
published the year following the EPA mercury report to
Congress. In the utility HAP study, EPA analyzed for
mercury in fuel oil as part of an exercise to calculate
emission factors for utility boilers. The data for this
exercise are not published; however, the mean amount
used in calculations was approximately 10 ppb, which
translated to an annual emission amount from all U.S.
utility boilers that burn fuel oil of approximately 200 kg.
Emissions data were obtained from 58 emission tests
conducted by U.S. EPA, the Electric Power Research
Institute (EPRI), the Department of Energy (DOE), and
individual utilities. The mercury concentration in as-fired
oil and natural gas was estimated from emissions test
data for boilers burning these fuels. In the estimation of
mercury emissions, all oil-fired units were assumed to
burn residual oil because trace element data were
available only for residual oil. An average density of 8.2
Ib/gal was chosen to represent all residual oils. Trace
element analysis of natural gas was performed for only
two available emissions tests; these concentrations were
averaged. The calculated mercury concentration in the
oil and natural gas multiplied by the fuel feed rate
resulted in an estimate of the amount of mercury (in
kg/year) entering each oil- and natural gas-fired boiler.
62
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The emission ratios and modification factors for pollution
control devices pMFs) were calculated by dividing the
amount of mercury exiting either the boiler or the control
device by the amount of mercury entering the boiler. The
average EMF for specific boiler configurations and
control devices was calculated by taking the geometric
mean of the EMFs for that type of configuration or
control device. (The geometric mean was chosen rather
than the arithmetic mean because the distribution of
emission factors followed a lognormal distribution.) To
calculate the control efficiency, the EMF was subtracted
from 1. Boiler-specific emission estimates were then
calculated by multiplying the calculated inlet mercury
concentration by the appropriate EMF for each boiler
configuration and control device.
Mercury emissions for oil combustion in
commercial/industrial boilers were estimated on a per-
state basis using an emission factor of 6.8 lb/1012 Btu
for residual oil and 7.2 lb/1012 Btu) for distillate oil and
the oil consumption estimates for States. The total
annual emission for oil-fired commercial/industrial
boilers was estimated as 7 Mg/yr (7.7 tons/yr). No
estimate was given for mercury emissions from gas
fired industrial boilers.
Mercury emissions for oil combustion in residential
boilers were estimated on a per-state basis using an
emission factor of 6.8 lb/1012 Btu for residual oil and 7.2
lb/1012 Btu) for distillate oil and the oil consumption
estimates for States. The total annual estimated
emissions for oil-fired residential boilers is 2.9 Mg/yr
(3.2 tons/yr).
It is thought that the emissions estimates reported in
the 1997 EPA Mercury Report to Congress (U.S. EPA
1997a) were based on ongoing studies that were
reported independently. One report, issued the same
year, compiled data specific to mercury as part of the
ongoing EPA Air Toxics program.
U.S. EPA (1997b) estimated concentrations of mercury
in fuel oil based on data compiled by Brooks (1989).
Brooks assembled data for fuel oils and crude oils from
studies conducted in the 70's and early 80's. The EPA
report admitted no comprehensive oil characterization
studies had been done, but cited data in the literature
for the range of mercury concentrations in crude oil
between 0.023 to 30 ppm wt, and the range of
concentrations in residual fuel oil as 0.007 to 0.17 ppm
wt. Because only a single mean value was found in the
literature for mercury concentration in distillate fuel oil,
no conclusions were drawn about the range of mercury
in distillate oil.
Table 7-22 lists the values for mercury in oils used by
U.S. EPA (1997a) to calculate emission factors. The
numbers used were obtained by taking the average of
the mean values found in the literature (Shah et al.
1970). The value for distillate oil was the single data
point found in the literature and was not considered as
representative as the values for residual and crude oils.
Additional evidence concerning mercury in fuel oils is
available from the U.S. EPA studies of hazardous air
pollutants from electric utility boilers (U.S. EPA 1998).
U.S. EPA (Radian 1993 as contractor to EPRI)
measured mercury emission factors for several furnace
types used by utilities. In this study, U.S. EPA cited
mercury in residual fuel oil as 0.6 pounds per trillion Btu
based on analysis of 4 samples of fuel oil (mean
standard deviation = 0.3). The conversion factor
applied was 150,000 Btu/gallon of density 8.2 Ib/gallon,
thus yielding a mean mercury concentration of
approximately 10 ppb. The mercury in gas
concentration utilized in calculation of emission factors
was 0.5 ug/m3 but its origin was not documented.
The origin of the EPA estimate for mercury from oil
combustion (11 tons) cited in the Report to Congress
derives mainly from the estimate for mercury
concentrations in residual and distillate fuel oil cited for
commercial and residential boilers (7 Ib/trillion Btu).
These concentrations (100 ppb) are an order of
magnitude higher than those derived from emission
measurements for utility boilers (U.S. EPA 1997a) and
for the mean cited in U.S. EPA, 1997b, Locating And
Estimating Air Emissions From Sources Of Mercury
And Mercury Compounds and with the amount cited in
U.S. EPA 1998 (0.6 Ib/trillion Btu).
63
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Table 7-21 - U.S. EPA Estimates of Mercury in Fuel Oil
Boiler
Btu/year
do12)
Fuel Type
Fuel Oil
Amount
(1010 L/year)
Emission
Factor
(kg/1012Btu)
Hg
(kg/year)
THgin
Fuel
(ppb)
Utility
Industrial
Residential
840
2,178
890
RFO
RFO/DFO
RFO/DFO
2.4
6.2
2.5
0.24
3.09/3.27
3.09/3.27
200
7,000
2,900
10
100
100
Total
10,100
Table 7-22 - Mercury Concentration In Oils Used as Fuels
(U.S. EPA 1997b)
Mercury concentration
Residual (No. 6)
Distillate (No. 2)
Crude Oil
Number of
samples
6
3
46
Range Mean
(ppb) (ppb)
2-6 4(1)
<120(2)
7 - 30,000 3,500 (3)
(1) Midpoint of the range of values. (2) Average of data from three sites.
(3) Average of 46 data points was 6,860; if the single point value of 23,100 is eliminated, average based on
45 remaining data points is 1,750. However, the largest study with 43 data points had an average of 3,200
ppb wt. A compromise value of 3,500 ppb wt was selected as the best typical value.
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Standards, Research Triangle Park, NC.
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Wilhelm, S. M., 1999, Conceptual Design of Mercury
Removal Systems for Hydrocarbon Liquids,
Hydrocarbon Processing, 78(4):61-73.
Wilhelm, S. M., 2001, An Estimate of Mercury
Emissions from Petroleum, in press, Environ, Sci.
Tech.
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Chapters
Data Requirements to Estimate Mercury Emissions
Mercury extracted from the earth in oil and gas
including that in associated waste streams contributes
to the global mercury cycle. While the amount of
mercury that derives from burning coal can be stated
with reasonable confidence, the amount that derives
from petroleum cannot be stated with equal confidence
at present. The estimates compiled in this report merely
provide a framework upon which one can gain a rough,
but preliminary, idea of the amounts that may be
involved. With additional data inputs to the estimates, it
may eventually be possible to estimate the total
amounts of mercury emissions from oil and gas with
better accuracy. Table 8.1 summarizes the estimates
compiled and discussed in this report.
Currently available data for total mercury (dissolved
and suspended) in petroleum and fuel products, when
applied to a mass balance for mercury in the U.S.
refining system, provide an order of magnitude estimate
of the contribution of mercury in oil and gas to U.S.
anthropogenic emissions (Wilhelm 2001). The model
finds the mean amount of mercury in petroleum refined
in the U.S. to be close to 10 ppb and predicts that the
amount of mercury in fuel products burned in the U.S.
is on the order 6000 kg/y. The amount of mercury in
U.S. fuel oil was estimated to be approximately 1,500
kg/y, assuming a 10 ppb mean mercury concentration
in crude oil. This number is in conflict with current U.S.
EPA estimates of mercury in fuel oil (10,000 kg/year,
see EPA Estimates, Chapter 7).
While the estimates compiled in this report are useful in
the present timeframe, they are insufficient to answer
some major issues and questions that are important to
the determination of the contribution of mercury in
petroleum to global pools and fluxes. For example, data
on refined products are scarce and undocumented as
to the refineries from which they originate. Thus it
remains uncertain as to whether the mercury in crude
oil is mainly accounted for by the amount in products (>
50 percent) or if it distributes more prevalently to other
avenues of egress from refineries (solid waste,
wastewater, fugitive emissions).
It does appear, based on currently available data, that
approximately half of the entire amount of mercury
associated with oil and gas (exploration, production,
transportation, processing, fuel combustion) enters the
atmosphere in fuel combustion. Some unknown portion
of this amount is captured by pollution control
equipment but the total is less than 6 Mg/y (if the mean
amount of mercury in crude oil is less than 10 ppb).
This would suggest that, while oil and gas account for
approximately the same mass of fossil fuel burned
yearly in the U.S., the amount of mercury in combusted
petroleum and gas is about 10 times less that that
which derives from coal (66 Mg/y, U.S. EPA 1997).
The above estimate of course depends on the mean
amount of mercury in petroleum. Data are somewhat
limited on mercury in crude oil of known origin, age and
condition, all of which are important to calculation of an
accurate mean concentration in crude oils processed in
the United States. The statistical ensemble of mercury
concentrations in coal that was developed in 1999 (U.S.
EPA 2000) serves as an example of the rigor that could
be applied to petroleum. Given the estimated amount in
crude oil presently available, one could certainly argue
that some lesser amount of data would suffice to obtain
an accurate mean and distribution of total mercury
concentration in petroleum.
Wilhelm and Bloom (2000) and Bloom (2000) point out
that analytical uncertainties exist with currently
published data. Of major importance are the
percentage and species identities of suspended forms
of mercury. If, as suspected, mercuric sulfide is a major
component of the total mercury in crude feeds to
refineries, or if it is produced in the refining process at
the expense of other forms, then one can rationalize
the amount of mercury in petroleum coke and thus
achieve better confidence in the distribution of mercury
to heavy products and waste streams.
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The chemical stability and fate of elemental mercury in
refining are also important and largely unknown. Almost
certainly, any mercury that is found in light distillates is
volatile in the crude and enters light fractions in the
primary distillation. The elemental form is thought to be
the dominant volatile, but it remains uncertain as to
whether dialkylmercury is a major component in crude
oil or if dialkyl or other volatile species are generated in
the refining process.
The distribution of mercury to effluents and air
emissions in the refining process is an important issue
as well and little data are available upon which any
conclusions can be drawn relative to refinery
emissions. Insufficient data are available for many of
the major streams including wastewater, solid waste,
still gas, treatment fluids and products. If one were to
attempt to obtain a firm understanding of the fate of
mercury in refineries, it would be necessary to examine
individual unit processes. Some of these have been
previously discussed (Chapter 6) and include desalting,
distillations, hydrotreating and catalytic cracking. In
each case, the attempt to determine the distribution of
mercury would require tracking the various species of
mercury (volatile, oxidized, inert) through the process
and to measure concentrations of each species in all of
the streams that enter and exit the process in question.
The relationship of mercury and sulfur in the refining
process may be essential to the task of understanding
the fate of mercury in hydrocarbon processing. Little is
known at present, but given mercury's affinity for sulfur,
it would seem likely that sulfides of mercury are more
likely produced than consumed in the refining and gas
separation processes. If so, understanding the
chemical reactions that occur would help account for
the amount known to exist in petroleum coke as
opposed to gasoline, for example.
The fate of mercury in gas processing also remains
uncertain, but this question may be less important than
the questions that relate to the fate of mercury in
refining. All current estimates for the amount of mercury
in natural gas conclude that the amount is very small, at
least relative to the amount in crude oil. The precise
mean amount and range of concentrations of mercury
in natural gas remain to be exactly determined,
however. Thus while the data of Chao and Attari (1993)
and the EPA estimates (U.S. EPA 1998) infer that the
amounts are insignificant, it would be useful to have
better data upon which to calculate the contribution of
mercury in natural gas to the global cycle more exactly.
An interesting point to be made relative to the gas issue
is that mercury removal systems are commercially
available and widely applied to gas having sufficient
mercury concentration to affect petrochemical
processing. The percentage of gas that is subjected to
mercury removal treatments as a percentage of the
total amount processed in the U.S. is not known.
Secondly, pipelines are quite efficient scavengers of
mercury in gas and it is likely that major portions of
mercury that enter a pipeline, never exit but are
retained on pipe interior surfaces indefinitely. Thus the
concentration of mercury at the point of consumption
will always be less than the concentration upstream of
compressors at gas processing facilities.
Of minor importance, but still of some curiosity, is the
fate of mercury in gas treatment systems such as glycol
dehydration, amine treaters and sorbents. Glycol in
particular is suspected to remove mercury by transfer to
the glycol regen gas and water vapor vents. The
reactions of mercury in amine systems remain
unstudied.
Even with knowledge of the amounts of mercury in
fuels, and their chemical identities, little is known
concerning the fate of mercury in liquid fuel combustion
processes. It seems unlikely that mercury is retained in
internal combustion engines in any major proportion,
but some could be. The amount in used motor oil as
compared to new, and the amounts possibly retained
by emission controls (catalytic converters) would then
need to be determined to answer this question
conclusively.
Emission factors for a limited number of refinery
processes are discussed in the previous section of this
report. While these data are useful and informative,
they are insufficient to allow major conclusions as to the
fate of mercury in refineries or in other types of liquid
fuel combustion processes. In addition, speciation of
mercury in liquid fuel combustion processes is not
reported and detailed investigations would be
necessary to establish the forms of mercury that are
emitted in boilers and heaters that burn liquid fuels.
The evolving database on mercury in both crude oil and
refined products is optimistic to the conclusion that
mercury that derives from petroleum is small in
absolute terms, and especially when compared to that
which derives from coal. The eventual conclusions to
be reached regarding mercury in oil and natural gas
and the amounts and avenues of incorporation to the
global cycle await focused studies that account for the
various species of mercury, the reactions that occur in
processing and the fate of mercury in the various
combustion process in which petroleum products are
consumed.
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References
Bloom, N., 2000, Analysis and Stability of Mercury
Speciation in Petroleum Hydrocarbons, Fresenius'
J. Anal. Chem., 366(5):438.
Chao, S. S. and A. Attari, 1993, Characterization and
Measurement of Natural Gas Trace Constituents,
Part 1: Natural Gas Survey, Institute of Gas
Technology Report to Gas Research Institute,
Contract No. 5089-253-1832 (November), GRI,
Chicago, IL.
Ruddy, D., 1982, Development Document for Effluent
Limitations Guidelines, New Source Performance
Standards, and Pretreatment Standards for the
Petroleum Refining Point Source Category,
EPA/440/1-82/014 (NTIS PB83-172569), Office of
Water Regulations and Standards, Washington, DC.
U.S. EPA, 1997, Mercury Study Report to Congress,
EPA/452/R-97/003 (NTIS PB 98-124738), Office of
Air Quality Planning and Standards, Research
Triangle Park, NC and Office of Research and
Development, Washington, DC.
U.S. EPA, 1998, Study of Hazardous Air Pollutant
Emissions from Electric Utility Steam Generating
Units - Final Report to Congress, EPA/453/R-
98/004a (NTIS PB98-131774), Office of Air Quality
Planning and Standards, Research Triangle Park,
NC.
U.S. EPA, 2000, Unified Air Toxics Website: Electric
Utility Steam Generating Units, Section 112 Rule
Making, Office of Air Quality Planning and
Standards, Research Triangle Park, NC.
www.epa.gov/ttn/uatw/combust/utiltox/utoxpg.html
Wilhelm, S., and N. Bloom, 2000, Mercury in
Petroleum, Fuel Proc. Technol., 63:1.
Wilhelm, S. M., 2001, An Estimate of Mercury
Emissions from Petroleum, in press, Environ. Sci.
Tech.
Table 8-1 - Summary of Estimates for Mercury Emissions from Oil and Gas Production and Processing
Type Industry Segment
Water
Oil and Gas
Production
Oil Refining
Oil Transportation
r Amount of THg Estimated Annual
category Discharge (ppb) Emission Rate
(109 kg/year) (kg/year)
Produced Water 500 1?(1)
Refinery 25Q
Wastewater
Tanker ballast ? 1?
500
250
?
Total
Solid Waste
Total
Air
Oil and Gas
Exploration
Oil refining
Drilling Waste
Refinery Waste
50
30
100?
50?
>750
5,000
1,200
6,200
Total
TOTAL
Oil Production
Oil Production
Gas Production and
Transmission
Oil
Gas
Flared gas
Fugitive
Fugitive
Fuel Combustion
Fuel Combustion
4.5
1
5.9
790
341
1.5?
185?
?
<8
<0.3?
10
185
?
6,000
100
>6
13,250
,300
(1) Question marks indicate that the mercury concentrations utilized are not based on definitive data
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