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Abstract Amine sweetening units are widely used in the gas industry to remove acid gases (H2S, other sulfur species, and/or CO2) from sour natural gas. Field and laboratory measurements have shown that VOCs and HAPs present in the natural gas are partially absorbed into the lean amine solution. Depending on composition of the natural gas entering the sweetening unit and the gas throughput, these units may represent a significant source of VOC and HAP emissions if the acid gas stream from the amine regenerator is discharged directly into the atmosphere. This paper presents measurements from six field tests showing the amounts of VOCs and HAPs (primarily BTEX species) absorbed by amine solutions and the distribution of these species between flash gas, regenerator overhead gas, and lean amine streams. Introduction In recent years there has been increased interest in the potential for emissions of volatile organic compounds (VOCs) and specific hazardous air pollutants (HAPs), especially benzene, toluene, ethylbenzene, and xylenes (BTEX) from gas production, treatment, and conditioning facilities. Field measurements have shown, for example, that the regenerator vent stream from glycol dehydrators, which are widely used to condition natural gas, can be a major source of VOC and HAPs emissions. A fraction of the VOCs and HAPs in the natural gas are dissolved in the glycol in the absorber or contactor and are subsequently separated from the glycol in the flash gas or regenerator overhead gas streams. Gas Research Institute (GM) has sponsored research into methods for sampling glycol units and the development of tools for estimating emissions from these units and other natural gas industry emission sources. Gas sweetening, another widely used natural gas conditioning process, removes acid gases (primarily hydrogen sulfide, other sulfur species, and/or carbon dioxide) from sour natural gas. The majority of natural gas sweetening units in the U.S. use regenerable chemical solvents, principally aqueous solutions of amines including diethanolamine (DEA), monoethanolamine (MEA), methyldiethanolamine (MDEA), Diglycolamine (DGA), and proprietary blends. The operation of amine sweetening units is similar to dehys, in that undesirable constituents present in the natural gas are removed by contacting the gas with a solvent, which is subsequently thermally regenerated and pumped back to the absorber. GM has also sponsored work to investigate the absorption of VOCs and HAPs from natural gas and their distribution between the sweetening unit's outlet streams: flash gas and the regenerator overhead gas stream. Since it is typically either used as fuel gas or subsequently sweetened, amine unit flash gas does not usually represent an emission stream. The regenerator overhead stream may be vented directly to the atmosphere in some cases, such as when CO2 is the primary acid gas species removed. For these units, the flow rates of VOC and HAPs in the regenerator overhead stream may be of concern from an air emissions standpoint. If, as is more often the case, the regenerator overhead stream is routed to a sulfur recovery unit (e.g., Claus unit) or combusted in an incinerator or flare, most of the organics will be destroyed and the resulting VOC and HAPs emissions will be low. However, the organics content of acid gas routed to a sulfur recovery unit is still of concern to the operator because of the potential negative process impacts of these species (e.g., catalyst fouling, reduced sulfur recovery, increased sulfur emissions). This paper presents the results of measurements of the amounts of VOCs and HAPs absorbed by amine solutions and the subsequent distribution of these species between flash gas, regenerator overhead gas, and lean amine streams. P. 17^
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Health, Safety, Environment & Sustainability > Environment > Air emissions (1.00)
- (2 more...)
Assessment of the Subsurface Environmental Fate of Amines Used by the Gas Industry
Sorensen, J.A. (Energy & Environmental Research Center) | Hawthorne, S.B. (Energy & Environmental Research Center) | Gallagher, J.R. (Energy & Environmental Research Center) | Thompson, J.S. (Energy & Environmental Research Center) | Harju, J.A. (Energy & Environmental Research Center) | Evans, J.M. (Gas Research Institute) | Chollak, D. (Canadian Occidental Petroleum Ltd.)
Abstract Alkanolamines are commonly used by the natural gas industry to remove acid gases from the natural gas stream. At gas processing plants that use alkanolamines for acid gas removal (AGR), spills and the on-site management of wastes containing alkanolamines and their associated sludges have commonly resulted in subsurface contamination that is presently the focus of some environmental concern. Research has been conducted by the Energy & Environmental Research Center that examines the subsurface transport and fate of the most commonly used alkanolamines, namely, monoethanolamine (MEA), diiethanolamine (DEA), and methyldiethanolamine (MDEA), and process-derived sludge from AGR units that utilize each of those compounds. Experimental activities were conducted that can be grouped into three areas:qualitative, semiquantitative, and quantitative characterization of alkanolamine-derived sludges; investigations of the interactions of MEA, DEA, and MDEA with soils; and activities investigating the biodegradability of MEA, DEA, MDEA, and associated sludges. Characterization of the sludges was performed using gas chromatography coupled with mass spectroscopy (GC-MS). In order to examine the potential effects of different soil types on subsurface transport and fate, investigations of interactions between alkanolamines and soil and of biodegradation of alkanolamines and process-derived sludges were performed using soils collected from Louisiana, New Mexico, and Alberta. These areas were selected to represent not only three unique soil types, but also to represent three regions of North America that produce an abundance of sour natural gas. The results of this research provide the natural gas industry with data and insights that will enable them to 1) significantly improve the assessment of subsurface alkanolamine-related contamination where it is known or suspected to occur and 2) make soundly based decisions concerning the remediation of that contamination. Introduction The natural gas industry commonly uses alkanolamines to remove hydrogen sulfide (H2S), carbon dioxide (CO2), and other acid gases from the natural gas in which they occur ("sour" gas if H2S is present). At sour gas processing plants, as at all plants that use alkanolamines for acid gas removal (AGR), unplanned releases and on-site management of wastes containing alkanolamines and process-derived thermal reaction products have commonly resulted in subsurface contamination that is presently the focus of some environmental concern in Canada. In the United States, there are at least 394 gas-sweetening facilities that use amine-based AGR units, and the production and processing of sour gas is expected to increase in the coming years. A few workers have reported toxicity associated with waste material generated by amine-based AGR units. Generally, adequate data exist to confirm the presence of alkanolamines and at least some of their thermal reaction and biodegradation products in soils and groundwater at the sites in question. However, analytical and other difficulties have typically prevented the nature and extent of alkanolamine-related contamination from being determined in detail at individual sites. At the same time, limited work has been done on the behavior of the chemical species in question in the subsurface; therefore, little is known about their subsurface transport and fate. This places the natural gas industry in the difficult position of having to effectively address a contamination issue that is neither well defined nor well understood. The results of this research program will enable the natural gas industry to significantly improve the assessment of subsurface alkanolamine-related contamination at sites where it is known or suspected to occur and make soundly based decisions concerning the remediation of that contamination. This program, which through directed research is specifically focused on monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolam inc (MDEA), and process-derived wastes from AGR units that utilize each of those compounds, includes activities which can be grouped into three areas: P. 255^
- North America > United States > Texas (0.28)
- North America > Canada > Alberta (0.25)
- North America > United States > New Mexico (0.24)
- North America > United States > Louisiana (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.82)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Gas processing (1.00)
Abstract Under the 1993 general discharge permit for produced waters on the Outer Continental Shell, discharges must be tested periodically to determine chronic toxicity to marine organisms. If toxicity is observed, regulators are likely to require the permittee to undertake Toxicity Identification Evaluation (TIE) studies to determine the cause of toxicity. Information on the toxicity of total salinity or individual ions is essential for guiding TIE studies with produced waters. The Gas Research Institute is sponsoring the development of such information for three common marine test species: mysid shrimp (Mysidopsir bahia), sheepshead minnow (Cyprinodon variegatus), and inland silverside minnow (Menidia heryllina). Based on test results, Salinity-Toxicity Relationship (STR) models are being constructed that will predict the survival of these three species upon exposure to a produced water of known ionic composition. Similar models for freshwater organisms are already in use. When routine biomonitoring indicates that a sample of produced water is toxic to one of the test organisms, the STR model can be used to determine whether the ionic composition of the sample is a contributing factor. If the predicted toxicity of the sample is similar to the measured toxicity, the effect can be presumed to be due to an excess or deficiency of one or more ions, or of total salinity. The STR model can then be used to identify the ion or ions in excess or deficiency, and to suggest strategies for eliminating the sample toxicity by restoring the appropriate ion balance. If the STR model predicts that the sample should not be toxic based on its ionic composition, other sources of toxicity (e.g., trace metals) are implied. Introduction and Background Like most industries, the gas industry uses water in numerous activities and releases water as a byproduct of specific operations. The greatest source of byproduct water in the gas industry, however, is the water that is coproduced during gas production operations. Produced water is, in fact, the largest waste stream in the oil and gas industry. Produced water can vary greatly in composition and salinity, depending on the type of production operation, geologic source of water, and the treatment of the water once brought to the surface. Produced water may be concentrated brine several times the salinity of seawater, or it may be relatively fresh water that is suitable for consumption by livestock. In general, produced waters have total dissolved solids (TDS) concentrations higher than most fresh and marine surface waters, although individual TDS values may vary widely (2,000 to 200,000 mg/L TDS; natural seawater is about 32,000 to 35,000 mg/L). Typically, the predominant cation and anion in produced waters are sodium and chloride, respectively. However, although chloride is usually the predominant anion and can sometimes reach concentrations of 200,000 mg/L in produced waters, bicarbonate >9,000 mg/L) was reported as the dominant anion in coalbed methane-produced water from Colorado in the United States. Examples of the ion concentrations in seawater and produced water are shown in Table 1. TDS, or salinity, in produced water has been shown to cause toxicity to freshwater and marine organisms. The cause of this toxicity may be osmotic stress or it may be due to specific actions of certain ions. Potassium, for example, is the major factor in establishing cell membrane potential and minor alterations of the potassium concentration in the extracellular fluid can produce major physiological changes. Toxicity Identification Evaluations. Produced waters are complex mixtures, and it is often difficult to separate toxicity due to common ions and toxicity due to other chemicals. P. 213^
- Water & Waste Management > Water Management (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.69)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Colorado Field (0.99)
- North America > United States > Mississippi > Houston Field (0.89)
- North America > United States > Colorado > DJ (Denver-Julesburg) Basin > Fort Collins Field (0.89)
Biocide and Corrosion Inhibition Use in the Oil and Gas Industry: Effectiveness and Potential Environmental Impacts
Brandon, D.M. (ENSR Consulting and Engineering) | Fillo, J.P. (ENSR Consulting and Engineering) | Morris, A.E. (Bioindustrial Technologies, Inc.) | Evans, J.M. (Gas Research Institute)
Abstract Treatment chemicals are used in all facets of the natural gas industry (NGI) from well development through transmission and storage of natural gas. The multitude of chemicals used, combined with the dozens of chemical manufacturers and/or suppliers has lead to the availability of hundreds of possible chemical products. Because of the widespread use of chemical products and their numerous sources, the NGI needs access to consistent data regarding their effectiveness and potential environmental impacts. The objective of this work was to evaluate the effectiveness and potential environmental impacts of chemical products used in the NGI. This assessment was initially focused on biocides and corrosion inhibitors and their use in the gas production, storage and transmission facilities, The overall approach was to obtain the necessary data on chemical use and effectiveness directly from the oil and gas industry supplemented with data/information obtained from the published literature. Five case histories of chemical use were documented and evaluated to assess the effectiveness of these chemicals. Potential environmental impacts were addressed by performing a screening environmental assessment on the use of glutaraldehyde, a widely used biocide. Prototype discharge scenarios were formulated and modeled to evaluate potential impacts to groundwater and surface water. The paper describes the basis for the study, provides an overview of chemical use with a focus on biocides and corrosion inhibitors, describes and assesses the specific uses of chemicals, and presents the results of the environmental assessment. It was found that various chemicals can be effective in treating microbiologically influenced corrosion and souring, but that the effectiveness of specific chemicals is dependent on the operational scenario and the site-specific conditions. Results of the screening environmental assessment indicated that surface and groundwater impacts were not significant for the scenarios evaluated. P. 431
- Water & Waste Management > Water Management > Constituents > Treated Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- (3 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract Research to characterize the toxicity of common ions to freshwater organisms resulted in the development of predictive toxicity models (FW STR) for three freshwater species (Ceriodaphnia dubia, Pimephales promelas, and Daphnia magna). The FW STR models, derived from acute toxicity data, focused on the toxicity of seven common ions. These predictive models were used in conjunction with Phase I TIE procedures to evaluate the contribution of common ion toxicity in six produced water samples ranging in total salinity from 1.7 to 58.1 g/L. Initial toxicities of all six samples were compared to the model predictions. Four produced water samples were found to have toxicity due to common ion concentrations only. Two samples were found to exhibit more toxicity than expected from ion concentrations alone. These samples were subjected to Phase I TIE procedures. Toxicities were reduced by specific Phase I TIE manipulations to those predicted by the FW STR models. Mock effluents were used to verify the results. The combination of the FW STR models with Phase I TIE procedures successfully quantified the toxicity due to common ions. INTRODUCTION AND BACKGROUND Salinity in produced waters can cause acute toxicity to freshwater organisms due to an excess of common ions which usually are not thought of as toxicants. These ions are present with other chemicals in produced waters as a complex mixture, making it difficult to quantify the toxicity due to the concentrations of common ions. Toxicity identification evaluation (TIE) studies have been developed to systematically identify the causative toxicants present in effluents and other waters. Phase I TIE procedures involve subjecting effluent solutions to a series of physical/chemical manipulations, each of which has been shown to be effective at removing specific toxicants. P. 393
- Water & Waste Management > Water Management (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract As part of previous research, the Gas Research Institute, ENSR, and the University of Wyoming developed a series of multivariate logistic regression equations (called Salinity/Toxicity Relationships or STRS) that predict acute toxicity to three freshwater organisms based on major ion composition. While these equations did an excellent job of representing responses in the laboratory data set on which they were based, their validity and usefulness lay in their ability to make accurate predictions for independent data sets and real-world samples. Accordingly, the STR equations were applied to a series of data sets from different sources. This exercise shows that the equations generally provide accurate predictions of toxicity, even across waters with very different ionic compositions. STR equations were also able to detect the presence of toxicants other than major ions in the samples. These results indicate that the STR approach will provide a valuable tool for assessing and managing produced waters and other waters with elevated concentrations of dissolved ions. INTRODUCTION AND BACKGROUND During the last decade, regulatory authorities have turned increasingly toward the use of freshwater and marine toxicity tests to evaluate the potential for environmental effects from waterborne chemicals. In particular, effluent toxicity testing ("biomonitoring") has become a centerpiece of effluent regulation under the National Pollutant Discharge Elimination System (NPDES) mandated by the Clean Water Act. Whole effluent toxicity testing and accompanying limits for aquatic toxicity have been incorporated into NPDES permits for many discharge categories. In addition to wastewaters from traditional municipal and industrial facilities, many produced waters are also subject to effluent toxicity limits in areas where these waters are discharged to surface waters. Probably the most pronounced characteristic of produced waters is their tendency to contain elevated concentrations of total dissolved solids (TDS), relate to fresh water. While not typically thought of as "toxics," the ions comprising TDS (e.g., chloride) can cause toxicity to freshwater organisms if present in sufficiently high concentrations. As a result, many produced waters can show toxicity caused by major ions, like chloride, regardless of the presence of hydrocarbons, metals, or other potentially toxic materials. Accordingly, appropriate management and treatment of produced waters can depend, in part, on understanding the role of TDS in causing aquatic toxicity. Sodium and chloride are typically considered to be the predominant major ions in produced water and other waters arising as by-products of the fossil fuel industry. However, sodium and chloride are not universally predominant. For example, many coalbed methane waters from the San Juan Basin have elevated concentrations of bicarbonate (personal communication, D.H. Pope, Bioindustrial Technologies, Inc., Georgetown, Texas); leachates from oil shale may contain high concentrations of magnesium and sulfate. P. 605^
- Research Report > Experimental Study (0.48)
- Research Report > New Finding (0.34)
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock (0.57)
- Water & Waste Management > Water Management (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Saline Field (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Alabama > Black Warrior Basin (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Alabama Field (0.98)
Abstract Increasingly stringent environmental regulations have caused emissions of air toxics from natural gas dehydration units to be a concern for the natural gas industry. Of particular interest are emissions of benzene, toluene, ethylbenzene, and xylenes, collectively known as BTEX. Radian Corporation and the Gas Research Institute have developed a software program called GRI-DEHYยฉ to provide gas producers with an easy-to-use tool for estimating emissions of BTEX and other VOCs from triethylene glycol dehydration units. This program uses fundamental chemical engineering thermodynamics along with available experimental data to make its emissions estimates. GRI-DEHY provides a rapid, inexpensive method for determining which dehydration units are in compliance with applicable regulatory emission levels, which units may require minor control approaches, and which units may require retrofit controls. Pre-release testing has shown that GRI-DEHY provides good emissions estimates, especially for the BTEX compounds. INTRODUCTION Glycol dehydration units are employed to remove water from produced natural gas streams to prevent hydrate formation and corrosion in the pipelines. Triethylene glycol (TEG) is used in approximately 95% of glycol dehydration units and has gained wide acceptance in this application for the following reasons:High affinity for water; Chemical stability; and Low cost. It has been estimated that there may be up to 30,000 glycol dehydration units operating in the United States and up to 100,000 operating worldwide. Approximately 17 to 18 trillion cubic feet per year of natural gas are currently dehydrated in North America, with the United States treating a large fraction of that amount (1). Figure 1 presents a schematic flow diagram for a glycol dehydration unit. The moist natural gas enters the bottom of the absorber, where it is contacted countercurrently with the cool, lean glycol to remove the water. The dry gas exits the top of the absorber. The rich glycol leaves the bottom of the absorber and, in larger units, often goes through a balance pump to a flash tank. Much of the natural gas that was captured at the high absorber pressures is separated from the glycol at the flash tank. After a series of heat exchangers and filters, the rich glycol enters the still and reboiler, where water is distilled/stripped from the glycol. Some units inject a stripping gas to produce higher purity glycol at normal reboiler temperatures. Lean glycol from the surge tank is pumped back to the absorber.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Emissions of benzene, toluene, ethyl benzene, and the xylene isomers (BTEX) and volatile organic compounds (VOC) from the reboiler still vent of glycol dehydration units have become a major concern for the natural gas industry as a result of increasing regulatory pressure. The Clean Air Act Amendments (CAAA) of 1990 have provided an impetus for air toxics regulations, and several states are regulating or considering regulation of these units. A key issue in developing approaches for handling these emissions has been accurate measurement of the emissions. The primary method used to date has been rich/lean glycol sampling at atmospheric pressure, which is favored for its simplicity. However, there are several potential errors associated with this approach, including the flashing and loss of BTEX and VOC during sampling. Direct (stack) measurement of these emissions has not been widely used because of the stream temperature and water content. To address these difficulties, the Gas Research Institute (GRI) is sponsoring a program to develop and refine sampling and analytical methods. Input to the program is provided by an Industry Working Group that contains representatives from several industry organizations. After an initial field experiment was performed to screen potential methods, surviving methods were refined in the laboratory using a synthetic still vent overhead stream. The refined methods are being evaluated in two additional field experiments, and the final, recommended methods will be validated in a series of experiments in mid-1993. INTRODUCTION AND BACKGROUND Glycol dehydration units are used to remove water from produced natural gas streams to prevent hydrate formation and corrosion in the pipeline. Figure I presents a simplified flow diagram for a glycol dehydration unit. The moist natural gas enters the bottom of the absorber. Where it is contacted countercurrently with the cool, lean glycol (typically triethylene glycol [TEG]) to remove the water. The dry gas exits the top of the absorber. The rich glycol leaves the bottom of the absorber and often goes through a balance pump to a flash tank, which is normally present only on larger units. The flash tank separates much of the natural gas that was captured at high pressure from the glycol. After a series of heat exchangers and filters, the rich glycol enters the still and reboilers where water is distilled/stripped from the glycol (some units inject a stripping gas to produce higher purity glycol at normal reboiler temperatures). Lean glycol from the surge tank is pumped back to the absorber. During the absorption step, the glycol, which has a high affinity for aromatic compounds, also removes BTEX from the natural gas. (BTEX compounds are usually present in the natural gas at levels less than one percent by volume). Since the boiling points of BTEX range from 80C to 140C, they are not lost to a significant extent in the flash tank but are separated from the glycol in the still. Although many of the lighter hydrocarbons may be removed from the glycol in the flash tank, some remain in the glycol and are also separated in the still. These separations in the still result in BTEX and other VOC emissions. P. 125^
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Mercury Contamination at Gas Industry Sites
Charlton, D.S. (Energy and Environmental Research Center) | Beaver, F.W. (Energy and Environmental Research Center) | Butler, R.D. (Energy and Environmental Research Center) | Harju, J.A. (Energy and Environmental Research Center) | Hassett, D.J. (Energy and Environmental Research Center) | Henke, K.R. (Energy and Environmental Research Center) | Monson, L.L. (Energy and Environmental Research Center) | Kuhnel, Vit (Energy and Environmental Research Center) | Schmit, C.R. (Energy and Environmental Research Center) | Stepan, D.J. (Energy and Environmental Research Center) | Evans, J.M. (Gas Research Inst.)
Abstract The past and present use of mercury-filled flowmeters (manometers) at gas industry metering stations has resulted in contamination of soils with elemental mercury. These manometers are used throughout the gas industry at production wells, along pipelines, at gas processing plants, at underground storage facilities, and within gas distribution systems. Soils contaminated with mercury at metering sites may be subject to Resource Conservation and Recovery Act (RCRA) regulations if a sample of the excavated soil exceeds 0.2 mg/L of mercury by the U.S. Environmental Protection Agency (USEPA) toxicity characteristic leaching procedure (TCLP) analysis. Under the Land Disposal Restrictions (Land Ban), mercury-contaminated soils that are determined to be hazardous by TCLP analysis (D009) cannot be landfilled without meeting certain treatment standards. For high-mercury soils (greater than 260 mg/kg total mercury), the Best Demonstrated Available Technology (BDAT) is specified as roasting or retorting. The mercury research program at the Energy and Environmental Research Center (EERC) is part of a broader, multidisciplinary effort to investigate potential contamination of soil and groundwater at gas industry sites. The primary tasks of this mercury research program include 1) the conduct of a mercury workshop for the gas industry; 2) a literature review and development of a bibliographic database; 3) an assessment of computer models applicable to mercury migration; 4) the development of a risk assessment model for mercury-contaminated sites; 5) the evaluation of sampling, preservation, and analytical protocols for mercury; 6) the characterization and monitoring of field sites; 7) the conduct of laboratory experiments evaluating leaching techniques; and 8) an evaluation of the application of existing or developing remediation technologies with mercury-contaminated soils. Several of these tasks have been completed, resulting in the distribution of proceedings of the mercury workshop and the bibliographic database. Four field sites have been characterized, and monitoring wells are continuing to be sampled. A mobile prototype of a remediation technology based on physical separation has been tested. P. 433^
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)