United States EPA/600/R-01/066 

Environmental Protection

Agency September 2001 

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

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. 
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
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. 

ii 
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

iii 
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 
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

v
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 Typical Refining Process..................................................................... 20

Figure 4-2 Primary Distillation ............................................................................ 21

Figure 4-3 Vacuum Distillation ............................................................... 21

Figure 4-4 Segregated Water Treatment System for a Typical Refinery ............ 22

Figure 4-5 Gas Process Schematic ..................................................................... 23

Figure 5-1 Solubility of Elemental Mercury in Normal Alkanes ............................. 30

Figure 5-2 Distribution of Mercury Compounds in Liquids .................................... 30

Figure 6-1 Primary Separation .............................................................................. 37

Figure 6-2 Crude Oil Desalting .............................................................................. 38

Figure 6-3 Mercury (Total) in Distilled Products .................................................... 39

Figure 6-4 Distribution of THg Concentrations in Petroleum Coke ....................... 39

vi
Abbreviations 

API American Petroleum Institute

BP Boiling Point

bpd barrels per day

bpy barrels per year

CVAA Cold Vapor Atomic Absorbance

CVAF Cold Vapor Atomic Fluorescence

DFO Distillate Fuel Oil

DOE (U.S.) Department of Energy

EOR Enhanced Oil Recovery

EPA (U.S.) Environmental Protection Agency

GF Gulf (of Mexico)

HPLC High Performance Liquid Chromatography

ICP Inductively Coupled Plasma

LNG Liquefied Natural Gas

Mg Megagram (106

 grams)

MS Mass Spectroscopy

NAA Neutron Activation Analysis

NGL Natural Gas Liquids

NPDES National Pollutant Discharge Elimination System

OAR Office of Air and Radiation (U.S. EPA)

OPEC Organization of Petroleum Exporting Countries

ORD Office of Research and Development (U.S. EPA)

OSWER Office of Solid Waste and Emergency Response (U.S. EPA)

OW Office of Water (U.S. EPA)

PBT Persistent, Bioaccumulative, Toxic

RFO Residual Fuel Oil

SCF Standard Cubic Foot

TDS Total Dissolved Solids

TEG Triethyleneglycol

TMDL Total Maximum Daily Load

TRI Toxic Release Inventory

USGS United States Geological Survey

UV Ultraviolet

VP Vapor Pressure

vii 
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. 

viii 
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 coalfired 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 

1 
m m

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 m g/m3

 meaning m g 

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/R97/002 (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. 

2 
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 

3 
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 11 x 106

 kg (0.5 - 3 ppt ocean; 1 – 10 ppt fresh water) 

Air 5 x 106

 kg (1 - 10 ng/m3; mean lifetime > 1 year) 

Flux (yearly) 

Ocean to Air 2 x 106

 kg/y (evasion) 

Air to Ocean 2 x 106

 kg/y (marine deposition) 

Air to Ground 3 x 106

 kg/y (terrestrial deposition) 

Ground to Air 3 x 106

 kg/y (natural 1 + man 2) 

Human Production 4 x 106

 kg/y (local 2 + air 2) 

Sink (yearly) 

Marine precipitation 0.2 x 106 kg/y 

4 
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 96.9 

125.3 86.9 

47.2 32.8 

(47.0) (32.6) 

(0.2) (0.1) 

(<0.1) (0.0) 

26.9 18.7 

25.8 17.9 

(18.8) (13.1) 

(7.0) (4.9) 

14.6 10.1 

6.4 4.4 

3.3 2.3 

(2.9) (2.0) 

(0.4) (0.3) 

0.9 0.6 

0.2 0.1 

<0.1 0.0 

14.4 10.0 

1.3 0.9 

(1) Total for percentage amounts includes non-point sources 

5 
Chapter 3

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 

6 
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) 

Paraffins Aromatics Naphthenes Sulfur API Crude source (% vol) (% vol) (% vol) (% wt) gravity 

USA -Mid-continent

North Sea -Brent

Nigeria -Light

Saudi Arabia -Light

USA -W. Texas Sour

Venezuela -Light

Saudi Arabia -Heavy

Venezuela -Heavy

- - - 0.4 40 

50 16 34 0.4 37 

37 9 54 0.2 36 

63 19 18 2.0 34 

46 22 32 1.9 32 

52 14 34 1.5 30 

60 15 25 2.1 28 

35 12 53 2.3 24 

7 
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 15,495 

Canada 2,694 

Mexico 3,523 

United States 9,278 

Central & South America 6,974 

Western Europe 6,999 

Eastern Europe & Former U.S.S.R. 7,454 

Middle East 22,454 

Africa 7,851 

Far East & Oceania 7,926 

World Total 75,152 

Table 3-3 - World Natural Gas (dry) Production (1998) 

(U.S. DOE 2000) 

Region/Country Rate (1012 SCF/y) 

North America 26.17 

Canada 6.04 

Mexico 1.27 

United States 18.86 

Central & South America 3.09 

Western Europe 9.66 

Eastern Europe & Former U.S.S.R. 25.16 

Middle East 6.61 

Africa 3.70 

Far East & Oceania 8.58 

World Total 82.97 

8 
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) 1,991 21,034 

Natural Gas (billion SCF) 18,720 164,041 

Gas Liquids (million barrels) 833 7,524 

Imported (OPEC (1)) Oil (million barrels) 1,500 

Imported (Non- OPEC) Oil (million barrels) 1,600 

(1) OPEC – Organization of Petroleum Exporting Countries 

9 
Table 3-5 – U.S. Crude Oil Reserves and Production

(1998, 106

 Barrels)

(U.S. DOE 2000)

State or Region Reserves Production 

12/31/97 1998 

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) 

5,161 437 

17,385 1,554 

47 7 

45 7 

3,750 270 

198 20 

91 6 

92 10 

10 1b 

238 34 

20 2 

714 83 

68 8 

183 19 

159 14 

21 3 

735 59 

279 33 

43 6 

605 62 

17 1 

5,687 417 

234 14 

26 1 

627 58 

3,477 417 

528 45 

2,587 336 

362 36 

19 2 

22,546 1,991 

10 
Table 3-6 - Top Thirty U.S. Oil Fields 

(U.S. DOE 2000) 

Rank by Field Name Location Discovery 1998 Production 

Reserves Year (106

 barrels) 

1 Prudhoe Bay AK 1967 

3 Kuparuk River AK 1969 

2 Midway-Sunset CA 1901 

15 Point McIntyre AK 1988 

6 Kern River CA 1899 

4 Belridge South CA 1911 

9 Mississippi Canyon Block 807 GF (1) 1989 

40 Garden Banks Block 426 GF 1987 

10 Milne Point AK 1982 

18 Green Canyon Block 244 GF 1994 

13 Spraberry Trend Area TX 1950 

5 Yates TX 1926 

8 Elk Hills CA 1919 

23 Wilmington CA 1932 

50 Viosca Knoll Block 990 GF 1981 

44 Niakuk AK 1984 

61 Ewing Bank Block 873 GF 1991 

21 Cymric CA 1916 

14 Endicott AK 1978 

60 Giddings TX 1960 

54 Viosca Knoll Block 956 GF 1985 

7 Wasson TX 1937 

11 Slaughter TX 1937 

12 Hondo CA 1969 

28 East Texas TX 1930 

24 Lost Hills CA 1910 

35 Seminole TX 1936 

25 Pescado CA 1970 

58 Eugene Island SA Block 330 GF 1971 

14 Levelland TX 1945 

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 

Total Production of Top 30 927 

(1) GF = Gulf of Mexico 

11 
Table 3-7 - Top Thirty U.S. Natural Gas Fields 

(U.S. DOE 2000) 

Rank by Field Name Location Discovery 

Reserves Year 

1998 Production 

(109

 SCF) 

1 Blanco / Ignacio-Blanco NM & CO 1927 

2 Basin NM 1947 

3 Hugoton Gas Area KS & OK & TX 1922 

4 Prudhoe Bay AK 1967 

15 Giddings TX 1960 

6 Carthage TX 1936 

7 Mobile Bay AL 1979 

11 Antrim MI 1965 

12 Panhandle West TX 1918 

10 Wattenburg CO 1970 

79 Matagorda Island Block 623 GF (1) 1980 

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 

21 

46 

19 

52 

51 

25 

37 

45 

53 

43 

36 

27 

22 

23 

29 

17 

41 

26 

66 

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

CA 1919 

GF 1987 

KS 1956 

TX 1960 

UT & WY 1980 

WY 1978 

GF 1985 

TX 1990 

NM 1963 

AK 1968 

TX 1978 

OK 1972 

TX 1953 

TX 1967 

Mocane-Laverne Gas Area OK & KS & TX 1947 

Red-Oak Norris OK 1910 

Watonga-Chickasha Trend OK 1948 

Gomez TX 1963 

Waltman WY 1959 

Total of Top 30 4573 

(1) GF = Gulf of Mexico 

12 
Table 3-8 – Oil Imports to U.S. Refineries 

(U.S. DOE 2000) 

Crude Oil LPG 

1000 b/d 1000 b/d 

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

2,053 53 

10 50 

336 

300 

1 

1,404 3 

3 

2,116 11 

50 

609 

1,377 11 

4,427 87 

465 

80 

31 

23 

1 

1,209 108 

25 

-7 

349 -1 

70 

98 -1 

11 

207 

23 

-5 

-24 

26 

1,321 -23 

221 6 

41 

9 

53 

0 

161 6 

4 

34 -8 

8,596 151 

(3.1 x 109

 b/y) (0.06 x 109 b/y TOTAL 

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 106

)

Cenozoic Quaternary 

Cenozoic Tertiary 

Cretaceous 

Mesozoic Jurassic 

Triassic 

Permian 

Carboniferous 

Pennsylvanian 

Mississippian Paleozoic Devonian 

Silurian 

Ordovician 

Cambrian 

Precambrian 

Recent 

Pleistocene 

Pliocene 

Miocene 

Oligocene 

Eocene 

Paleocene 

0.01

3

12

25

38

55

65

135

180

225

275

350

413

430

500

600

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 H2S 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 H2S 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, hydrotreating, 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 Separation Thermal Separate 

distillation fractions 

Desalted crude 

oil 

Gas, gas oil, 

distillate, 

residual 

Vacuum 

distillation Separation Thermal Separate w/o 

cracking 

Atmospheric 

tower residual 

Gas oil, lube 

stock, residual 

17 
Table 4-2 – Decomposition Processes 

(OSHA 2000) 

Process name Action Method Purpose Feedstocks Products 

Catalytic 

cracking Alteration Catalytic Upgrade gasoline 

Gas oil, coke 

distillate 

Gasoline, 

petrochemical 

feedstock 

Coking Polymerize Thermal 

Convert 

vacuum 

residuals 

Gas oil, coke 

distillate 

Gasoline, 

petrochemical 

feedstock 

Hydrocracking Hydrogenate Catalytic Convert to 

lighter HC's 

Gas oil, 

cracked oil, 

residual 

Lighter, higherquality 

products 

Hydrogen 

steam 

reforming 

Decompose Thermal/ 

catalytic 

Produce 

hydrogen 

Desulfurized 

gas, O2, steam 

Hydrogen, CO, 

CO2 

Steam cracking Decompose Thermal Crack large 

molecules 

Atm. tower hvy 

fuel/ distillate 

Cracked 

naphtha, coke, 

residual 

Visbreaking Decompose Thermal Reduce 

viscosity 

Atmospheric 

tower 

residual 

Distillate, tar 

Table 4-3 – Unification and Rearrangement Processes 

(OSHA 2000) 

Process Action Method Purpose Feedstock Products 

Alkylation Unite olefins & Combining Catalytic isoparaffins 

Tower 

isobutane/ 

cracker olefin 

Iso-octane 

(alkylate) 

Grease Combine 

compounding Combining Thermal soaps & oils 

Lube oil, fatty 

acid, alky metal 

Lubricating 

grease 

High-octane 

naphtha, 

petrochemical 

stocks 

Unite two or Polymerizing Polymerize Catalytic more olefins Cracker olefins 

Catalytic 

reforming 

Alteration/ Upgrade lowdehydration Catalytic octane naphtha 

Coker/ hydrocracker 

naphtha 

High-octane 

Reformate/ 

aromatic 

Isomerization Rearrange Catalytic 

Convert 

straight chain 

to branch 

Butane, 

pentane, 

hexane 

Isobutane/ 

pentane/ 

hexane 

18 
Table 4-4 – Treatment Processes 

(OSHA 2000) 

Process Action Method Purpose Feedstocks Products 

Amine treating Treatment 

Remove 

Extraction acidic 

contaminants 

Sour gas, HCs 

w/CO2 & H2S 

Acid free gases 

& liquid HCs 

Desalting Dehydration Remove Extraction contaminants Crude oil Desalted crude 

oil 

Drying & 

sweetening Treatment Adsorption Remove H2O 

Thermal & sulfur 

compounds 

Liquids, LPG, 

alkylation 

feedstock 

Sweet & dry 

hydrocarbons 

Solvent Upgrade mid Cycle oils & lube High quality Furfural extraction extraction Absorption distillate & feedstocks diesel & lube oil lubes 

Remove High-sulfur Desulfurized Hydrodesulfurization Treatment Catalytic sulfur, 

contaminants residual/gas oil olefins, HCs 

Remove 

Hydrotreating Hydrogenation Catalytic impurities, 

saturate 

Residuals, 

cracked HCs 

Cracker feed, 

distillate, lube 

HC's 

Phenol extraction Solvent 

extraction 

Adsorption 

Thermal 

Improve 

viscosity & 

color 

Lube oil base 

stocks 

High quality lube 

oils 

Solvent 

deasphalting Treatment Absorption Remove 

asphalt 

Vacuum tower 

residual, 

propane 

Heavy lube oil, 

asphalt 

Solvent dewaxing Treatment Cool/ filter 

Remove wax 

from lube 

stocks 

Vacuum tower 

lube oils 

Dewaxed lube 

basestock 

Solvent Absorption Separate Gas oil, High-octane Solvent extraction extraction precipitation unsat. oils reformate, gasoline distillate 

Remove Untreated High-quality Sweetening Treatment Catalytic H2S, convert distillate/gasoline distillate/gasoline mercaptan 

Table 4-5 - Refined Products 

(U.S. DOE 2000) 

Specific Gravity Refined Products Barrel/y kg/y 

g/mL (109

) (1011) 

0.75 Transportation fuels (60%) 3.7 4.4 

0.80 Naphthas (5%) 0.3 0.4 

0.85 Residual fuel oil (5%) 0.3 0.4 

0.85 Distilled fuel oil (21%) 1.3 1.8 

1.10 Petroleum coke (3%) 0.2 0.3 

0.90 Asphalt, Heavy oils (3%) 0.2 0.3 

0.55 Still Gas (3%) 0.2 0.2 

TOTAL 6.2 7.8 

19 
Figure 4-1 - Typical Refining Process 

20
Figure 4-2 – Primary Distillation 

Figure 4-3 – Vacuum Distillation 

21
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. 

Figure 4-5 – Gas Process Schematic 

23 
Chapter 5

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[I] or mercurous), or the +2 (mercury[II] or 

mercuric) valence states. Mercurous compounds 

usually involve Hg-Hg bonds and are generally 

unstable and rare in nature. 

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 0

C/torr

13.546 g/cm3 at 20 C (0.489 lb/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/cm2

hr 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. 

Table 5-2 – Solubilities and Volatilities of Mercury Compounds 

Formula State Volatility Hg Solubility in Name H20; 25 C 

Hg0 Liquid Boiling Point 357 C 

Vapor Pressure 25 mg/m3

 (25 C) 50 ppb Elemental 

HgCl2 Solid Boiling Point 302 C 70 g/L Mercuric chloride 

HgSO4 Solid decomposes 300 C 0.03 g/L Mercuric sulfate 

HgO Solid decomposes 500 C 0.05 g/L Mercuric oxide 

HgS Solid Sublimes under vacuum; decomposes 560 C - log Ksp(1) = 52 Mercuric sulfide 

HgSe Solid Sublimes under vacuum, decomposes 800 C - log Ksp ~ 100 Mercuric selenide 

(CH3)2Hg Liquid Boiling Point 96 C < 1 ppm Dimethylmercury 

(C2 H5)2Hg Liquid Boiling Point 170 C < 1 ppm 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 (Hg0

) – Elemental 

mercury is soluble in crude oil and hydrocarbon 

25 
liquids in atomic form to a few ppm. Elemental 

mercury is adsorptive 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, C2H5, etc. and X = Cl 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 Hg0

. 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 Hg0 

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 Hg0 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. Hg0 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. Hg0

 was not seen in 

naphthas as would be expected assuming a normal 

distillation profile. The more volatile Hg0

 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 

HCl 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 HCl 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 Hg0 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. 

Frech 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 

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 Hg0 or KCl 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 Hg0

 and HgCl2 react to form Hg2Cl2 

that is insoluble in hydrocarbons and precipitates. 

Hg0 + HgCl2 fi Hg2Cl2 fl 

27 

2 
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 Hg0

, HgCH3

+

 and Hg(CH3)2 stable 

in paraffin oil stored in glass. HgCl2 was not stable in 

paraffin oil and Hg0

 and HgCl2 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 Hg0

 species. No reductive 

mechanisms are known that would account for 

generation of Hg0

 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 Hg0 in coproduced hydrocarbon liquid and gas, Hg0

 typically is 

dominant in both. This suggests that Hg0

 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 

Hg0 T D D D 

(CH3)2Hg ? T T, (S?) T, (S?) 

HgCl2 S? N S S 

HgS D N Suspended Suspended 

HgO T? N N N 

CH3 HgCl ? N T? 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 
m

m

Table 5-4 - Approximate Solubility of Mercury Compounds in Liquids; 25 C 

Species Water Oil Glycol 

(ppm) (ppm) (ppm) 

HgO 0.05 2 <1 

XHgX ? miscible >1 

HgCl2 70,000 >10 >50 

HgS 0.01 < 0.01 < 0.01 

HgO 50 low 

CH3 HgCl >10,000 1,000 >1,000 

Table 5-5 - Concentrations of Mercury Compounds

in Natural Gas Condensates (m g/liter Hg) (Zettlitzer et al. 1997)

Sample Hg0 HgCI2 Other RHgCl Sum (a) Total HgS 

Low-Temp. Separator 250 400 644 6 1300 3500 2200 

(percent) 19.2 30.8 49.5 0.5 100.0 

Ambient temp. 

Separator 2000 400 2600 100 5100 5500 400 

39.2 7.8 51.0 2.0 100.0 

Storage tank 200 200 1250 50 1700 4300 2600 

11.8 11.8 73.5 2.9 100.0 

(1) Sum =Hg0 + HgCI2 + RHgCl + other; other = acid extracted - HgCI2; HgS = Total- sum 

Table 5-6 - Operational Hg Speciation in Petroleum Samples (Bloom 2000) 

unfiltered Hg, ng/g 0.8 m filtered Hg, ng/g 

Sample ID Total Hgo dissolved total Hg(II) CH3Hg 

condensate #1 20,700 3,060 5,210 2,150 3.74 

condensate #2 49,400 34,5001 36,800 2,370 6.24 

crude oil #1 1,990 408 821 291 0.25 

crude oil #2 4,750 1,120 1,470 433 0.26 

crude oil #3 4,610 536 1,680 377 0.27 

crude oil #4 4,100 1,250 1,770 506 0.62 

crude oil #5 15,200 2,930 3,110 489 0.45 

crude oil #6 1.51 0.09 1.01 0.39 0.15 

crude oil #7 0.42 0.17 0.41 0.02 0.11 

(1) This sample was contained particulate Hgo that was re-dissolved in hexane. 

29 
Figure 5-1 – Solubility of Elemental Mercury in 

Normal Alkanes as a Function of Temperature 

Figure 5-2 – Distribution of Mercury Compounds in Liquids 

(Tao et al. 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 preconcentration (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 [(CH3)2Hg], inorganic mercury, 

particulate mercury, and elemental mercury (Hg0

), 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, Hg0

 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 

(Hg0

) 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 (1000

 to 2000 C) without 

compromise of quantitative mercury collection. 

Iodated 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. Iodated carbon traps are less 

sensitive to contaminants in hydrocarbons than gold 

traps. Iodated 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 (Shafawi 

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 (SnCl2) to 

Hg0

, 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 BrCl, 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 (10-13 g). 

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 = Hg0

 + (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 nonoxidative extraction. The volatile elemental form (Hg0

) 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 (GCCVAF, GC-ICP/MS) are required. 

References 

Bloom, N. S., 1995, Mercury as a case study of ultraclean 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. 

Frech, 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., Frech, 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., Frech, 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 
Chapter 6

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 Hg0

 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 Hg0 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 Hg0

 is 

approximately 20, based upon the relative solubilities of 

Hgo

 in water (60 ng/mL) and paraffin oil (1200 ng/mL) 

at room temperature. The trend to lower KOW 

(octanol/water partition ratio) for elemental mercury was 

thought to be due, in part, to oxidation (possibly by 

oxygen in air) of Hg0

 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 Hgo HgCl2 CH3HgCl 

oil [Hg], ng/mL 170.6 5.5 32.2 

2 min water [Hg], ng/mL 5.0 160.2 98.9 

Kow 

(1) 34.1 0.034 0.33 

oil [Hg], ng/mL 167.0 1.7 32.7 

6 min water [Hg], ng/mL 12.2 167.6 98.3 

Kow 13.7 0.010 0.33 

oil [Hg], ng/mL 151.8 0.85 33.4 

12 min water [Hg], ng/mL 18.9 169.9 99.4 

Kow 8.0 0.005 0.34 

(1) KOW (oil/water partition ratio) 

36 
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 nonvolatile 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 (Hg0

, 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 

(5000

 - 5500 C). Coke is the solid residual material from 

the vacuum still and other coking processes. The 

volatilization (sublimation) temperature for mercuric 

sulfide is approximately 5600

 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, hydrotreating, 

etc. Based on purely chemical considerations, any 

organic or ionic mercury in feeds to hydrotreaters would 

be expected to be converted to Hg0

, which would then 

incorporate to the separated gas streams (H2S, H2, 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 THg (ppm) 

1 41 

2 4 

3 39 

4 0.01 

Figure 6-2 – Crude Oil Desalting 

38 
Figure 6-3 – Mercury (Total) in Distilled Products 

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 sulfurimpregnated activated carbon (Nishino et al. 1985, 

Matviya et al. 1987), mercury (Hg0

) physically adsorbs 

and then reacts to form non-volatile mercuric sulfide. 

The reaction between Hg0 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 (Al2O3) 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 Carbon HgS Gas 

Metal Sulfide Al2O3; Carbon HgS Gas, Condensate 

Iodide Carbon HgI2 Condensate 

Hydrogen, Metal Sulfide Al2O3 HgS Condensate 

Ag Zeolite Ag/Hg amalgam Gas, Condensate 

Metal Oxide Sulfided metal oxide HgS Gas, Condensate 

42 
Chapter 7

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 reinjected (usually to the formation it came from). Reinjection 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 Hg0

 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 Hg0

 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 Hg0

, 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 Discharge Rate THg Reference 

(109

 L/y) (ppb) 

Gulf of Mexico Ocean 0.64 <0.010 Ray 1998 

Gulf of Mexico Ocean 0.40 <0.010 Ray 1998 

Gulf of Mexico Coastal LA 1.74 0.007 - 27; 

Mean 7.08; SD 11.26 Meinhold et al. 1996 

North Sea Brent <3 Jacobs et al. 1992 

North Sea Northern <3 Jacobs et al. 1992 

North Sea Central <3 Jacobs et al. 1992 

North Sea UK <1 Jacobs et al. 1992 

North Sea Dutch 4 Jacobs et al. 1992 

Gulf of Mexico Coastal 140 <0.01 – 0.2, 

n = 37 Trefry et al. 1996 

45 
Table 7-2 - Mercury Concentrations in Produced Water

(Southern CA, year 1990)

(Raco 1993)

Platform No. Volume THg

Samples (106

 L/y) (ppb) 

Elly

Edith

Hogan

Hillhouse

A

B

C

Habitat

Irene

Grace

Gail

Gilda

2 1 <1

1 176 <1

2 225 <1

1 361 <1

2 1184 0.5

2 726 2.5

2 836 <1

1 21 <1

4 608 0.5

2 139 1

5 273 1.6

2 704 <1

5,254 

Data 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 Value Basis 

(mg/L) 

Trace Metals 

Arsenic 0.0050 API (1978; 1981) 

Chromium 0.0680 API (1978; 1981) 

Copper 0.0180 API (1978; 1981) 

Mercury 0.0009 Ruddy (1982) 

Nickel 0.0100 API (1978; 1981) 

Selenium 0.0172 Ruddy (1982) 

Zinc 0.0610 API (1978; 1981) 

Trace Organics 

Benzene 0.0005 API (1978; 1981) 

Toluene 0.0005 API (1978; 1981) 

Ethylbenzene 0.0008 API (1978; 1981) 

Acenaphthene 0.0011 Ruddy (1982) 

Benz[a]anthracene 0.0004 API (1978; 1981) 

Benzo[a]pyrene 0.0007 API (1978; 1981) 

Chrysene 0.0003 API (1978; 1981) 

Phenanthrene 0.0002 Ruddy (1982) 

Pyrene 0.0005 API (1978; 1981) 

2,4-Dimethylphenol 0.0022 API (1978; 1981) 

46
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. 

3 Approximately 9 billion m of methane is emitted 

annually by the gas industry (Kirchgessner et al. 1997). 

Approximately 90 percent of emitted gas is noncombusted 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 mg/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 3 metric tons (1.5 billion m 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 

47 

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 = A x EF x [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. 
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 directfired 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 400-4500

 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 

5000

 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 lb/Mgal, 700 ppb) while the other two 

were much lower (5 x 10-5, 9 x 10-6 lb/Mgal; 7 ppb, 1 

ppb). 

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 lb 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 lb/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 Fuel APC (1) Emission Units No. of Hg (2) Units Factor Tests 

Asphalt Blow Gas TO 9.00E-03 lb/MMcf 1 146 (3) mg/m3 

Boiler Fuel Oil None 1.03E-05 lb/Mgal 1 1.4 ppb 

Boiler Still Gas None 3.23E-04 lb/MMcf 1 5.2 mg/m3 

Boiler Still Gas SCR 3.23E-04 lb/MMcf 1 5.2 mg/m3 

Coke Calcining Gas SD/FF 4.63E-05 lb/ton coke 1 23 ppb 

Heater Fuel Oil None 1.72E-05 lb/Mgal 1 2.4 ppb 

Heater Still Gas DeNOx 2.02E-04 lb/MMcf 1 3.3 mg/m3 

Heater Still Gas None 2.02E-04 lb/MMcf 1 3.3 mg/m3 

Heater Still Gas SO2 Scrub 2.02E-04 lb/MMcf 1 3.3 mg/m3 

Steam Generator Crude None 2.19E-03 lb/Mgal 3 327 ppb 

Steam Generator Crude SO2 Scrub 2.19E-03 lb/Mgal 3 327 ppb 

Turbine Still Gas SCR/COC 4.63E-03 lb/MMcf 2 75 mg/m3 

Turbine Still Gas COC 2.15E-02 lb/MMcf 1 348 mg/m3 

(1) APC – air pollution control; COC - CO Oxidation Catalyst; DeNox (SNCR) - Selective Non-Catalytic NOx

Reduction; FF - Fabric Filter; SCR - Selective Catalytic NOx 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 waterbase 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 Rightto-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 prefiltration (1 mm pore size) of the oil; hence mercury 

existing as particulates above 1 mm 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 

(Shah et al. 1970) 

Source Amount SD Notes 

(ppb) (ppb) Detection Limit 4 ppb 

California 114 2.8 

California 81 1.9 

California 88 3.0 

California 29,688 103.9 

California 78 2.4 

Libya 2,079 11.9 

Libya 62 5.1 

Libya 75 1.7 

Louisiana 23 1.8 

Wyoming 77 3.4 

Mean 3,200 

Cymric 

Range 23 – 30,000 ppb 

Table 7-6 – Total Mercury Concentrations in Crude Oils by NAA 

(Filby and Shah 1975) 

Source THg Notes 

(ppb) 

California (Tertiary) 23,100 5 Replicates; Mean = 21,200; S.D. 0.36 

Venezuelan (Boscan) 27 

Alberta (Cretaceous) 84 

Libya <4 Detection Limit 4 ppb 

Mean 5,803 

52 
Table 7- 7 - Total Mercury Concentrations in Alberta Crude Oils 

(Hitchon and Filby 1983) 

Stratigraphic Number Number High Low Mean (2) Median 

Era of Above (ppb) (ppb) (ppb) (ppb) SD 

Samples DL 

Upper Cretaceous 21 11 202 <2 (1) 17.6 2.5 46.0 

Lower Cretaceous 18 7 138 <2 17.1 1 38.1 

Jurassic 3 0 1 <2 1 1 

Triassic 4 2 6 <2 3 2.5 2.4 

Carboniferous 8 4 19 <2 5 1.5 6.3 

Devonian 32 13 399 <2 36 1 92.5 

Total 86 37 399 <2 21.9 1 63.6 

(1) Detection limit = 2 ppb 

(2) Calculated by assuming <DL = 1 ppb 

Table 7-8 – Total Mercury Concentrations in Libyan Crude Oils 

(Musa et al. 1995) 

Field THg SD Notes 

(ppb) (ppb) 

Hamada 0.10 0.01 

Sabah 2.1 0.23 

Brega 3.19 0.15 

Zella 0.314 0.024 

Aswed 0.368 0.025 

Oxyblend 3.353 0.39 

Agip 12.20 0.34 

Mean 3.1 

DL < 0.10 

Range 0.1 to 12.2 

53 
Table 7-9 – Mercury Concentrations in U.S. West Coast Crude Oils 

(Magaw et al. 1999) 

Region 

Number Range Mean of 

Samples (ppb) (ppb) 

Middle East 2 <10 (1) <10 

Africa 4 <10 <10 

North America 11 <10 – 1,560 146 

Asia 4 <10 <10 

South America 4 <10 <10 

North Sea 1 <10 <10 

26 ND – 1,560 65 

(1) DL = 10 ppb 

Table 7-10 - Total Mercury Concentrations in Crude Oils 

(Bloom 2000) 

Number of Range Mean SD Notes Samples (ppb) (ppb) 

76 NR (1) 1,505 3,278 All 

37 NR 1 1.49 Lowest 37 samples 

39 NR 3,000 4,140 Top 39 samples 

(1) NR – not reported 

54 
Table 7-11 – Mercury Concentrations in Crude Oils

Processed in New Jersey Refineries

(Morris 2000)

Type Mean THg Field (ppb) 

Africa (Angola) 2.7 Palanca 

Africa (Angola) 1.5 Soyo 

Africa (Congo) 1.8 Kitina 

Africa (Gabon) 1.8 Rabi 

Africa (Nigeria) 1.0 Escravos 

Africa (West) 3.2 

Africa (West) 1.5 

Arabia (Dubai) 2.9 Nemba 

Canada (Newfoundland) 1.9 

Mexico 2.7 

Mexico 0.1 

Mixed 3.1 

North Sea 3.4 

North Sea 9.3 Ecofisk 

North Sea 2.5 Gullfaks 

North Sea 4.7 Norne 

Saudi Arabia 5.7 

South America (Columbia) 12.3 

South America (Columbia) 2 

South America (Venezuela) 4.8 

South America (Venezuela) 5.1 

South America (Venezuela) 0.8 

South America (Venezuela) 6 

MEAN 3.5 Range = 0.1 – 12.3 

55 
Table 7-12 - Total Mercury Concentrations in Crude Oils 

(Environment Canada 2000, Cao 1992) 

Field Name Location THg Notes (ppb) 

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

BCF 24

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

<15 (1) Crude 

<15 Bitumen 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 Crude 

<15 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 <2 <2 <2 

B <2 <2 <2 

C <2 <2 <2 

D <2 9 2 

E <2 <2 <2 

F <2 <2 <2 

G <2 <2 <2 

H <2 7 4 

Mean 1.5 

Table 7-14 - Summary of THg in Crude Oils and Gas Condensates 

Reference Type 

Number 

of 

Samples 

Range 

(ppb) 

Mean SD Notes (ppb) 

Shah et al. 1970 Crude Oil 10 23 - 29,700 3,200 U.S. and imports 

Hitchon and Filby 

1983 Crude Oil 86 <2 - 399 22 63.6 Canada 

Filby and Shah. 

1975 Crude Oil 4 <4 - 23,100 5,803 U.S. and imports 

Musa et al. 1995 Crude Oil 6 0.1 - 12.2 3.1 4.2 Libyan 

Tao et al. 1998 Crude Oil 1 <1 Asia 

Magaw et al. 1999 Crude Oil 26 <10 - 1,560 65 West Coast 

Refineries 

Bloom 2000 Crude Oil 76 NR(1) 1,505 3,278 Origins not reported 

Liang et al. 2000 Crude Oil 11 1.6 – 7.2 4.4 1.0 Origins not reported 

Morris 2000 Crude Oil 23 0.1 - 12.2 3.5 New Jersey 

Refineries 

Cao 1992 Crude Oil 24 All <DL = 15 8 Canada and Imports 

Duo et al. 2000 Crude Oil 8 <2 - 9 1.6 1.6 Canadian 

Refineries 

Olsen et al. 1997 Condensate 4 NR 15 Origins not reported 

Bloom 2000 Condensate 18 NR 3,964 11,665 Mostly Asian 

Shafawi et al. 1999 Condensate 5 9 - 63 30 18.6 S.E. Asia 

Tao et al. 1998 Condensate 7 15 - 173 40 Asian 

(1) NR – not reported 

57 
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 

Number of Range Mean Reference Type Samples (ppb) (ppb) SD Notes 

Liang et al. 1996 Gasoline 5 0.22 – 1.43 0.7 NR (1) U.S. 

Liang et al. 1996 Gasoline 4 0.72 – 3.2 1.5 NR Foreign 

Liang et al. 1996 Diesel 1 0.4 0.4 NR U.S. 

Liang et al. 1996 Diesel 1 2.97 2.97 NR Foreign 

Liang et al. 1996 Kerosene 1 0.04 0.04 NR U.S. 

Liang et al. 1996 Heating Oil 1 0.59 0.59 NR U.S. 

Bloom 2000 Light distillates 14 NR 1.32 2.81 U.S. 

Bloom 2000 Utility fuel oil 32 NR 0.67 0.96 U.S. 

Bloom 2000 Asphalt 10 NR 0.27 0.32 U.S. 

Olsen et al. 1997 Naphtha 4 3 - 40 15 NR 

Tao et al. 1998 Naphtha 3 8 - 60 40 NR Asian 

U.S. EPA 2000 Petroleum 

Coke 1000 0 - 250 50 NR U.S. 

(1) NR – not reported, ND – not detected 

Table 7-16 – Summary of Mercury Concentrations in Fuel Oils 

Number of Range Mean Reference Type Samples (ppb) (ppb) SD Notes 

Liang et al. 1996

Bloom 2000

EPA 1997b

EPA 1997b

EPA 1997a

EPA 1997a

EPA 1997a

EPA 1998

Heating Oil 1 0.59 0.59 NR (3) U.S. 

Utility fuel oil 32 NR 1 0.96 U.S. 

RFO 6 6 2 - 6 4 (1) 

DFO 2 3 <120 (2) 

Utility RFO 10 Measured 

Commercial 100 Calculated RFO/DFO 

Residential 100 Calculated RFO/DFO 

RFO 4 10 0.3 

(1)Median (2) Average (3) ND – not detected 

58 
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 
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 Estimated 

(U.S. DOE 2000) (U.S. DOE 2000) kg/y THg Total 

(109

) (1011) ppb kg/y 

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%)

GOM (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 <10 500 

0.5 0.7 <10 700 

1.5 2.0 <10? (1) 2,000? 

0.5 0.7 <10? 700? 

0.5 0.7 <10 700 

0.8 1.1 <10 1,100 

1.8 2.4 <10? 2,400? 

6.0 8.1 8,100 

3.7 4.4 <2? 900? 

0.3 0.4 <5 200 

0.3 0.4 <10? 400 

1.3 1.8 <5 900 

0.2 0.3 50 1,500 

0.2 0.3 50 1,500 

0.2 0.3 <30? 900? 

6.2 7.9 6,300 

1.5 2.5 1 250 

0.3 40? 1,200? 

(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 
Table 7- 18 - Fuels from Crude Oil Used by Refineries 

(U.S. DOE 2000) 

Fuel Type bpy kg/y THg Amount 

(106

) (109) (ppb) (kg Hg/y) 

LPG 4 0.4 <10 4 

Still gas 235 20.6 <30? 600 

RFO/DFO (1) 6 0.8 <10 86 

Heavy Oils 6 0.9 50 5 

Coke 90 15.8 50 800 

Total 1,500 

(1) residual fuel oil/distillate fuel oil 

Table 7-19 - Mercury in Major Crude Oil Imports 

(Calculated from the data of Morris 2000) 

Source bpy (1999) Percent of U.S. Total THg 

(109

) (6 x 109 bpy) (ppb) 

Yearly amount 

(kg Hg/y) 

Venezuela 0.50 8 5 359 

Middle East 0.74 12 5 531 

African 0.22 4 5 158 

Mexico 0.48 8 5 345 

North Sea 0.15 3 5 108 

Total 2.1 35 5 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 
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

75% Rocky Mountain, 25 % Canadian

California

California

Canadian

Canadian

80% Permian, 20% San Juan

Gulf Coast

Guff Coast

<0.2 

<0.2 

<0.1 

<0.1 

<0.1 

<0.02 

<0.02 

<0.02 

<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 (lb 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 

lb/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 
The emission ratios and modification factors for pollution 

control devices (EMFs) 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 perstate 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 lb/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 lb/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 lb/trillion Btu). 

63 
Table 7-21 – U.S. EPA Estimates of Mercury in Fuel Oil 

Boiler Fuel Oil Emission Btu/year Fuel Type Hg Amount Factor 

THg in 

Fuel 

(1012) (1010 L/year) (kg/1012 Btu) (kg/year) (ppb) 

Utility 840 RFO 2.4 0.24 200 10 

Industrial 2,178 RFO/DFO 6.2 3.09/3.27 7,000 100 

Residential 890 RFO/DFO 2.5 3.09/3.27 2,900 100 

Total 10,100 

Table 7-22 - Mercury Concentration In Oils Used as Fuels 

(U.S. EPA 1997b) 

Mercury concentration 

Number of Range Mean 

samples (ppb) (ppb) 

Residual (No. 6) 6 2 - 6 4 (1) 

Distillate (No. 2) 3 <120 (2) 

Crude Oil 46 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.

References 

American Petroleum Institute, 1977, Water Reuse 

Studies, API Publication No. 949, Washington, DC. 

American Petroleum Institute, 1978, Analysis of 

Refinery Wastewaters for the EPA Priority 

Pollutants, API Publication No. 4296, Washington, 

DC. 

American Petroleum Institute, 1981, Refinery 

Wastewater Priority Pollutant Study – Sample 

Analysis and Evaluation of Data, API Publication 

No. 4336, Washington, DC. 

American Petroleum Institute, 1995, Management of 

Residuals, API Publication No. 4296, Washington, 

DC. 

American Petroleum Institute and Western States 

Petroleum Association, 1998, Air Toxic Emission 

Factors For Combustion Sources Using Petroleum 

Based Fuels, Final Report, Volume 2 -

Development of Emission Factors Using CARB 

Approach, API Publication No. 348, Washington, 

DC. 

Bloom, N. S. and A. Falke, 1996, The Importance of 

Chemical Speciation in the Assessment and 

Treatment of Hg, As, and Se Contaminated Waste 

Streams, Pacific Northwest Pollution Control 

Association Conference, Boise, ID, October 27-30. 

Bloom, N. S., 2000, Analysis and Stability of Mercury 

Speciation in Petroleum Hydrocarbons, Fresenius’ 

J. Anal. Chem., 366(5):438. 

64 
Brooks, G., 1989, Estimating Air Toxics Emissions from 

Coal and Oil Combustion Sources, EPA-450/2-89-

001 (NTIS PB89-194229), U.S. EPA, Office of Air 

Quality and Standards, Research Triangle Park, 

NC. April. 

Brown, T., Smith, D., Hargis, R., and W. O'Dowd, 1999, 

Critical Review - Mercury Measurement and Its 

Control: What We Know, Have Learned, and Need 

to Further Investigate, J. Air & Waste Manage. 

Assoc., June, pp. 1-97. 

Cao, J. R., 1992, Microwave Digestion of Crude Oils 

and Oil Products for the Determination of Trace 

Metals and Sulphur by Inductively-Coupled Plasma 

Atomic Emission Spectroscopy, Environment 

Canada Manuscript Report Number EE-140, 

Ottawa, Ontario, Canada. 

Chao, 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. 

Duo, W., Guthrie, T., and W. Edwards, 2000, Mercury 

Emissions from The Petroleum Refining Sector In 

Canada, for Environment Canada, Trans-boundary 

Air Issues Branch, Hazardous Air Pollutants 

Program, Ottawa, Canada, EC Contract: K2216-9-

0078. 

Environment Canada, 2000, Properties of Crude Oils 

and Oil Products - 12/99, Emergencies Science 

Division, Ontario, Canada. 

Filby, R. H., and K. R. Shah, 1975, Neutron Activation 

Methods for Trace Metals in Crude Oil, in The Role 

of Trace Metals in Petroleum, by T. F.Yen, Ann 

Arbor Science Publishers, Ann Arbor, MI. 

Frankiewicz, T. C and S. Tussaneyakul, 1997, 

Upgrading production facilities on the Funan 

platform to remove hydrocarbons and heavy metals 

from produced water, Proceedings: Offshore 

Technology Conference, May 1997, pp. 299-310. 

Hitchon, B., Filby, R. H., and K. R. Shah, 1975, 

Geochemistry of Trace Elements in Crude Oils, 

Alberta, Canada, in The Role of Trace Metals in 

Petroleum; by T. F. Yen, Ann Arbor Science 

Publishers: Ann Arbor, MI. 

Hitchon, B. and R. Filby, 1983, Geochemical Studies – 

Trace Elements in Alberta Crude Oils, Open File 

Report 1983-02, Alberta Research Council for 

Alberta Energy and Utilities Board and Alberta 

Geological Survey. 

Jacobs, R., Grant, R., Kwant, J., Maequine, J., and E. 

Mentzer, 1992, The Composition of Produced 

Water from Shell Operated Oil and Gas Production 

in the North Sea, in Produced Water, Technological 

and Environmental Issues and Solutions, Ray, J., 

ed., Plenum Press, New York, NY. 

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., 

Harrison, M. R., and T. M. Shires, 1997, Estimate 

of Methane Emissions from the U.S. Natural Gas 

Industry, Chemosphere, 35, 6:1365. 

Liang, L., Horvat, M., and P. Danilchik, 1996, A Novel 

Analytical Method for Determination of Picogram 

Levels of Total Mercury In Gasoline and Other 

Petroleum Based Products, Sci. Tot. Environ., 

187:57. 

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. 

Magaw, R., McMillen, S., Gala, W., Trefry, J., and R. 

Trocine, 1999, Risk evaluation of metals in crude 

oils, Proceedings SPE/EPA Exploration & 

Production Environmental Conference, SPE Paper 

No. 52725. 

Meinhold, A., DePhillips, M., and S. Holtzman, 1996, 

Final Report: Risk Assessment for Produced Water 

Discharges to Louisiana Open Bays, Brookhaven 

National Laboratory Report No. BNL-62579 for U.S. 

DOE, Brookhaven, NY. 

Morris, R., 2000, New TRI Reporting Rules on Mercury, 

Proceedings National Petroleum Refiners 

Association Meeting, San Antonio, TX, 

(September). 

Mulyono, M., Desrina, R., Priatna, R., Sudewo, B., and 

M. Sawolo, 1996, Heavy Metals in Water Base 

Drilling Muds Used in Several Locations of Oil 

Fields in Indonesia, SPE paper No. 35980. 

Musa, M., Markus, W., Elghondi, A., Etwir, R., Hannan, 

A., and E. Arafa, 1995, Neutron Activation Analysis 

of Major 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. 

Petrusak,R., Freeman, B., and G. Smith, 2000, 

Baseline Characterization of U.S. Exploration and 

Production Wastes and Waste Management, SPE 

Paper No. 63097 presented at the SPE Annual 

Technical Conference and Exhibition, Dallas, TX, 

October. 

65 
Raco, V., 1993, Estimated Discharges from Offshore 

Oil Platforms in the Southern California Bight 

(Santa Barbara Channel and Santa Maria Basin) in 

1990, Southern California Coastal Water Research 

Project Annual Report 1992-93, Los Angeles, CA. 

Radian Corporation, 1993, Preliminary Draft Reports on 

Field Chemical Emissions Monitoring Project. 

Prepared for Electric Power Research Institute from 

the following reports: Site 10, October 6, 1992; Site 

11, October 6, 1992; Site 12, November, 23, 1992; 

Site 15, October 6, 1992; Site 21, May 14, 1993. 

Austin, TX. 

Ray, J. P., 1998, Findings of the Offshore Operators 

Committee Produced Water Bioaccumulation 

Study, SPE Paper No. 46838, Society of Petroleum 

Engineers, Dallas, TX. 

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. 

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. 

Shah, K. R., Filby, R. H., and W. A. Haller, 1970, 

Determination of Trace Elements in Petroleum by 

Neutron Activation Analysis, Journal of 

Radioanalytical Chemistry, 6:413. 

Stephenson, M., 1992, A Survey of Produced Water 

Studies, Produced Water: Technological and 

Environmental Issues and Solutions, Ray, J., ed., 

Plenum Press, New York, NY. 

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. 

Trefry, J., Trocine, R., Naito, K., and S. Metz, 1996, 

Assessing the Potential for Enhanced 

Bioaccumulation of Heavy Metals from Produced 

Water Discharges to the Gulf of Mexico, in 

Produced Water 2, Environmental Issues and 

Mitigation Technologies, Reed, M. and Johnsen, 

S., eds., Plenum Press, New York, NY. 

U.S. DOE, 1999, Estimation of Greenhouse Gases, 

Energy Information Administration, National Energy 

Information Center, Report EIA/DOE-0573(99). 

U.S. DOE, 2000, Energy Statistics for 1998, 1999, 

Energy Information Administration, National Energy 

Information Center, Washington, D.C. 

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, 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. 

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Emissions From Sources Of Mercury And Mercury 

Compounds, EPA-454/R/97-012 (NTIS PB98-

117054), Office of Air Quality Planning and 

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Factor Documents, EPA/454/R-95-015, Office of 

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Triangle Park, NC. 

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66 
Chapter 8

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. 

67 
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. 

68 
References 

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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/R98/004a (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 

Amount of THg Estimated Annual Type Industry Segment Category Discharge (ppb) Emission Rate 

(109

 kg/year) (kg/year) 

Water 

Total 

Solid Waste 

Total 

Air 

Total 

TOTAL 

Oil and Gas 

Production 

Oil Refining

Oil Transportation

Oil and Gas

Exploration

Oil refining

Oil Production

Oil Production

Gas Production and

Transmission

Oil

Gas

Produced Water 

Refinery 

Wastewater 

Tanker ballast 

Drilling Waste 

Refinery Waste 

Flared gas 

Fugitive 

Fugitive 

Fuel Combustion 

Fuel Combustion 

500 1? (1) 500 

250 1? 250 

? 1? ? 

>750 

50 100? 5,000 

30 50? 1,200 

6,200 

4.5 1.5? 10 

1 185? 185 

5.9 ? ? 

790 <8 6,000 

341 <0.3? 100 

>6,300 

13,250 

(1) Question marks indicate that the mercury concentrations utilized are not based on definitive data 

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