Equivalent leak definitions for Smart LDAR (leak detection and repair) when using optical imaging technology

Controlling fugitive emissions from leaks in petrochemical industry process equipment now requires periodic monitoring of valves, flanges, pumps etc., typically on a quarterly basis. Previous studies have shown that over 90% of the reducible emissions come from approximately 0.1% of the components, i.e. the large leakers. A new, and more cost-effective approach for controlling these large leakers would entail more frequent monitoring of process equipment, allowing for the detection and repair of the highly leaking components that contribute the most to emissions. This approach has been called "Smart LDAR." New optical imaging instruments, which significantly reduce monitoring costs, are now available to implement such an alternative work practice. This work describes the determination of the leak detection sensitivity (equivalency threshold) that an optical imaging instrument must achieve to ensure that it will provide at least the equivalent emission control of the current leak detection and repair practice. Equivalency thresholds were developed for various monitoring intervals. The U.S. Environment Protection Agency's Monte Carlo simulation approach was used to perform the analysis and to demonstrate that optical imaging, which is capable of identifying all of the largest leakers, can provide better control of fugitive emissions.     

Aerially guided leak detection and repair: A pilot field study for evaluating the potential of methane emission detection and cost-effectiveness

Novel aerial methane (CH₄) detection technologies were used in this study to identify anomalously high-emitting oil and gas (O&G) facilities and to guide ground-based “leak detection and repair” (LDAR) teams. This approach has the potential to enable a rapid and effective inspection of O&G facilities under voluntary or regulatory LDAR programs to identify and mitigate anomalously large CH₄ emissions from a disproportionately small number of facilities. This is the first study of which the authors are aware to deploy, evaluate, and compare the CH₄ detection volumes and cost-effectiveness of aerially guided and purely ground-based LDAR techniques. Two aerial methods, the Kairos Aerospace infrared CH₄ column imaging and the Scientific Aviation in situ aircraft CH₄ mole fraction measurements, were tested during a 2-week period in the Fayetteville Shale region contemporaneously with conventional ground-based LDAR. We show that aerially guided LDAR can be at least as cost-effective as ground-based LDAR, but several variable parameters were identified that strongly affect cost-effectiveness and which require field research and improvements beyond this pilot study. These parameters include (i) CH₄ minimum dectectable limit of aerial technologies, (ii) emission rate size distributions of sources, (iii) remote distinction of fixable versus nonfixable CH₄ sources (“leaks” vs. CH₄ emissions occurring by design), and (iv) the fraction of fixable sources to total CH₄ emissions. Suggestions for future study design are provided.

Implications: Mitigation of methane leaks from existing oil and gas operations currently relies on on-site inspections of all applicable facilities at a prescribed frequency. This approach is labor- and cost-intensive, especially because a majority of oil and gas–related methane emissions originate from a disproportionately small number of facilities and components. We show for the first time in real-world conditions how aerial methane measurements can identify anomalously high-emitting facilities to enable a rapid, focused, and directed ground inspection of these facilities. The aerially guided approach can be more cost-effective than current practices, especially when implementing the aircraft deployment improvements discussed here.     

Methods to determine response factors for infrared gas imagers used as quantitative measurement devices

Response factors (RF) can be used to characterize relative sensitivity of one compound vs. another compound for the same measurement instrument. Use of RF allows the analysts/operators to calibrate the instrument with one compound and make measurement for a large number of compounds. This method is adopted for Flame Ionization Detector (FID) based survey instruments used in the Leak Detection and Repair (LDAR) practice for control of fugitive emissions of volatile organic compounds. Gas detecting Infrared (IR) cameras have been used for leak detection. However, the RF for IR cameras has not been well established despite some attempt to develop a method for IR camera RF. In addition to a method proposed earlier (Method 1), two new methods for IR camera RF are proposed in this paper: Method 2 based on theoretical approach and Method 3 based on experimental approach. All three methods are examined and compared. Both Methods 2 and 3 have shown the ability to characterize the behavior of RF for various compounds and substantially higher accuracy than Method 1. Method 2 provides a mechanism to generate RF for a large number of compounds without conducting experiments, and is recommended for implementation. The RF derived from this method can be used both in the emerging field of Quantitative Optical Gas Imaging (QOGI) and to answer the most common question that IR camera users ask—whether a particular compound can be imaged by a particular IR camera.Implications: Infrared imager is an efficient tool for detecting gas leaks from process equipment and has been used in leak detection and repair (LDAR) programs for control of fugitive emissions. However, the information regarding which chemical compounds can be imaged and how sensitive a given infrared imager is for various compounds is limited. A theoretical method is presented in this paper that can answer these questions without conducting resource-intensive experiment. The results of this theoretical method has good agreement with experimental data. The method has been used to predict relative sensitivity for 398 compounds.     

Derivation of new emission factors for quantification of mass emissions when using optical gas imaging for detecting leaks

This paper describes the development of new "leak/no-leak" emission factors that are suitable for estimating facilities' fugitive emissions when using an alternative work practice (AWP) that is based on optical gas imaging technology for detecting leaking piping system components. These emission factors were derived for valves, pumps, and connectors/flanges for instrument leak detection thresholds ranging from 3 to 60 g/hr using a combination of field data and Monte Carlo statistical simulation techniques. These newly derived leak/no-leak emission factors are designed to replace the U.S. Environment Protection Agency (EPA) 1995 Protocol factors, which were based on Method 21 monitoring of leaks at "uncontrolled" facilities. The emission factors published in the 1995 Protocol have not been updated since the 1970s. This derivation is based on results where the authors document the use of a Monte Carlo simulation technique to quantify the required leak detection thresholds that provide equal--or better--environmental benefits for an AWP. The use of these newly derived emission factors is demonstrated for different methods of computing fugitive emissions from a hypothetical model refinery. The resulting facility emissions calculated by using these new emission factors is compared with the existing emission estimation methods provided in the EPA 1995 Protocol. The results demonstrate that the new emission factors provide an emission estimate that is the closest to that obtained from the direct determination of total emissions by Monte Carlo simulations.     

Sensor transition failure in the high flow sampler: Implications for methane emission inventories of natural gas infrastructure

Quantification of leaks from natural gas (NG) infrastructure is a key step in reducing emissions of the greenhouse gas methane (CH₄), particularly as NG becomes a larger component of domestic energy supply. The U.S. Environmental Protection Agency (EPA) requires measurement and reporting of emissions of CH₄ from NG transmission, storage, and processing facilities, and the high-flow sampler (or high-volume sampler) is one of the tools approved for this by the EPA. The Bacharach Hi-Flow Sampler (BHFS) is the only commercially available high-flow instrument, and it is also used throughout the NG supply chain for directed inspection and maintenance, emission factor development, and greenhouse gas reduction programs. Here we document failure of the BHFS to transition from a catalytic oxidation sensor used to measure low NG (~5% or less) concentrations to a thermal conductivity sensor for higher concentrations (from ~5% to 100%), resulting in underestimation of NG emission rates. Our analysis includes both our own field testing and analysis of data from two other studies (Modrak et al., 2012; City of Fort Worth, 2011). Although this failure is not completely understood, and although we do not know if all BHFS models are similarly affected, sensor transition failure has been observed under one or more of these conditions: (1) Calibration is more than ~2 weeks old; (2) firmware is out of date; or (3) the composition of the NG source is less than ~91% CH₄. The extent to which this issue has affected recent emission studies is uncertain, but the analysis presented here suggests that the problem could be widespread. Furthermore, it is critical that this problem be resolved before the onset of regulations on CH₄ emissions from the oil and gas industry, as the BHFS is a popular instrument for these measurements.

Implications: An instrument commonly used to measure leaks in natural gas infrastructure has a critical sensor transition failure issue that results in underestimation of leaks, with implications for greenhouse gas emissions estimates as well as safety.     

Estimating Fugitive Emissions of Volatile Compounds from Equipment Leaks

This paper is directed to those concerned with estimating releases to the air of volatile compounds from equipment component leaks. We compared emission rates for equipment component leaks using EPA’s Average Emission Factor Method, Leak/No-Leak Emission Factor Method, and Stratified Emission Factor Method. The latter two methods may be used if there are concentration measurements about the components. An organic vapor analyzer was applied with the appropriate response factor to measure the concentrations around each equipment component using EPA Method 21. We analyzed this data to determine mass emission rates. Results show that the Average Emission Factor Method substantially overstates the emission rates calculated using these other two methods. We conclude that use of Method 21 concentration measurements with the Leak/No Leak or Stratified Emission Factor Method may increase the accuracy and reduce significantly the estimated releases to the air of volatile compounds from equipment component leaks for many facilities.     

Auto Emissions,Engine Size,and Fuel Economy

EPA Reference Method 25 for measurement of total gaseous nonmethane organics as carbon in source emissions was evaluated in the laboratory and through field testing. Laboratory evaluation included development and testing of a nonmethane organic analyzer. In addition, a series of tests was performed on the condensate trap recovery system. The tests involved evaluation of two different condensate trap recovery system designs. The first design was very similar to the Federal Register design and the second design was a modified system for minimizing interference from trapped carbon dioxide. Field testing of the method was performed at two different printing plants. Both plants used carbon bed adsorption for solvent recovery and control of VOC emissions. Samples were collected from the inlet and outlet streams of adsorption units at both plants. In addition to Method 25 samples, Method 18 samples were collected for analysis by gas chromatography with flame ionization detection. The results of all the laboratory and field test samples are described.     

Detection limits of optical gas imagers as a function of temperature differential and distance

Optical gas imaging (OGI) is an effective tool for detecting gas leaks from process equipment. Despite the fact that OGI has been used for leak detection for over a decade, its detection limit is an elusive performance metric and has not been systematically characterized and quantified like other detection instruments. A substantial body of research has been performed that has shed some light on the OGI detection limits and the factors that dictate the detection limits. The OGI detection limit expressed as ppm-m and ppm now can be quantified as a function of ΔT (differential temperature between the gas plume and the background), the OGI camera type, and the specific gas in question. Furthermore, the OGI detection limit expressed as grams per hour can be calculated based on the ΔT and the distance from the OGI camera to the leak location under common leak survey conditions. For the same OGI camera, the detection limit can vary by several orders of magnitude due to ΔT and distance. The present work has demonstrated how different OGI detection limits can be. More importantly, this work has, for the first time, formulated equations that can be used to determine OGI detection limits with a given set of leak detection conditions. Being able to quantify OGI detection limit and understand the variables that dictate the detection limit is a significant advancement. It will help OGI to become accepted as a mature field instrument. The variables characterized in this work should have an impact on the development of OGI leak survey protocols, such as Appendix K to Code of Federal Regulations 40 CFR Part 60 in the United States. Established detection limits will also help emission inventory for fugitive emissions when OGI is used as the sole leak detection method.

Implications: Optical gas imaging (OGI) has been used for leak detection and control of fugitive volatile organic compound (VOC) emissions and methane emissions due to equipment leaks. However, detection limits of OGI have not been characterized and quantified like other detection instruments. The lack of well-understood detection limits has hindered broader applications of OGI. The work presented in this paper represents important steps that will enable OGI users and policymakers to establish (1) OGI detection limits under various conditions, (2) OGI leak survey criteria for a desired minimum detectable leak size, and (3) maximum potential emissions from the nondetect sources in emission inventory studies.     

A life-cycle comparison of alternative automobile fuels

We examine the life cycles of gasoline, diesel, compressed natural gas (CNG), and ethanol (C2H5OH)-fueled internal combustion engine (ICE) automobiles. Port and direct injection and spark and compression ignition engines are examined. We investigate diesel fuel from both petroleum and biosources as well as C2H5OH from corn, herbaceous bio-mass, and woody biomass. The baseline vehicle is a gasoline-fueled 1998 Ford Taurus. We optimize the other fuel/powertrain combinations for each specific fuel as a part of making the vehicles comparable to the baseline in terms of range, emissions level, and vehicle lifetime. Life-cycle calculations are done using the economic input-output life-cycle analysis (EIO-LCA) software; fuel cycles and vehicle end-of-life stages are based on published model results. We find that recent advances in gasoline vehicles, the low petroleum price, and the extensive gasoline infrastructure make it difficult for any alternative fuel to become commercially viable. The most attractive alternative fuel is compressed natural gas because it is less expensive than gasoline, has lower regulated pollutant and toxics emissions, produces less greenhouse gas (GHG) emissions, and is available in North America in large quantities. However, the bulk and weight of gas storage cylinders required for the vehicle to attain a range comparable to that of gasoline vehicles necessitates a redesign of the engine and chassis. Additional natural gas transportation and distribution infrastructure is required for large-scale use of natural gas for transportation. Diesel engines are extremely attractive in terms of energy efficiency, but expert judgment is divided on whether these engines will be able to meet strict emissions standards, even with reformulated fuel. The attractiveness of direct injection engines depends on their being able to meet strict emissions standards without losing their greater efficiency. Biofuels offer lower GHG emissions, are sustainable, and reduce the demand for imported fuels. Fuels from food sources, such as biodiesel from soybeans and C2H5OH from corn, can be attractive only if the co-products are in high demand and if the fuel production does not diminish the food supply. C2H5OH from herbaceous or woody biomass could replace the gasoline burned in the light-duty fleet while supplying electricity as a co-product. While it costs more than gasoline, bioethanol would be attractive if the price of gasoline doubled, if significant reductions in GHG emissions were required, or if fuel economy regulations for gasoline vehicles were tightened.     

A Life-Cycle Comparison of Alternative Automobile Fuels

ABSTRACT

We examine the life cycles of gasoline, diesel, compressed natural gas (CNG), and ethanol (C₂H₅OH)-fueled internal combustion engine (ICE) automobiles. Port and direct injection and spark and compression ignition engines are examined. We investigate diesel fuel from both petroleum and biosources as well as C₂H₅OH from corn, herbaceous bio-mass, and woody biomass. The baseline vehicle is a gasoline-fueled 1998 Ford Taurus. We optimize the other fuel/powertrain combinations for each specific fuel as a part of making the vehicles comparable to the baseline in terms of range, emissions level, and vehicle lifetime. Life-cycle calculations are done using the economic input-output life-cycle analysis (EIO-LCA) software; fuel cycles and vehicle end-of-life stages are based on published model results.

We find that recent advances in gasoline vehicles, the low petroleum price, and the extensive gasoline infrastructure make it difficult for any alternative fuel to become commercially viable. The most attractive alternative fuel is compressed natural gas because it is less expensive than gasoline, has lower regulated pollutant and toxics emissions, produces less greenhouse gas (GHG) emissions, and is available in North America in large quantities. However, the bulk and weight of gas storage cylinders required for the vehicle to attain a range comparable to that of gasoline vehicles necessitates a redesign of the engine and chassis. Additional natural gas transportation and distribution infrastructure is required for large-scale use of natural gas for transportation. Diesel engines are extremely attractive in terms of energy efficiency, but expert judgment is divided on whether these engines will be able to meet strict emissions standards, even with reformulated fuel. The attractiveness of direct injection engines depends on their being able to meet strict emissions standards without losing their greater efficiency. Biofuels offer lower GHG emissions, are sustainable, and reduce the demand for imported fuels. Fuels from food sources, such as biodiesel from soybeans and C₂H₅OH from corn, can be attractive only if the co-products are in high demand and if the fuel production does not diminish the food supply. C₂H₅OH from herbaceous or woody biomass could replace the gasoline burned in the light-duty fleet while supplying electricity as a co-product. While it costs more than gasoline, bioethanol would be attractive if the price of gasoline doubled, if significant reductions in GHG emissions were required, or if fuel economy regulations for gasoline vehicles were tightened.     

The effect of coal combustion flue gas components on low-level chlorine speciation using EPA method 26A

U.S. Environmental Protection Agency (EPA) Method 26A is the recommended procedure for capturing and speciating halogen (X2) and hydrogen halide (HX) stack emissions from combustion sources. Previous evaluation studies of Method 26A have focused primarily on hydrogen chloride (HCl) speciation. Capture efficiency, bias, and the potential interference of Cl2 at high levels (> 20 ppm [microgram/m3]) and NH4Cl in the flue gas stream have been investigated. It has been suggested that precise Cl2 measurement and accuracy in quantifying HX or X2 using Method 26A are difficult to achieve at Cl2 concentrations < 5 ppm; however, no performance data exist to support this. Coal contains low levels of Cl, in the range of 5-2000 ppmw, which results in the presence of HCl and Cl2 in the products of combustion. HCl is the predominant Cl compound formed in the high-temperature combustion process, and it persists in the gas as the products of combustion cool. Concentrations of Cl2 in coal combustion flue gas at stack temperatures typically do not exceed 5 ppm. For this research, bench-scale experiments using simulated combustion flue gas were designed to validate the ability of Method 26A to speciate low levels of Cl2 accurately. This paper presents the results of the bench-scale tests. The effect of various flue gas components is discussed. The results indicate that SO2 is the only component in coal combustion flue gas that has an appreciable effect on Cl2 distribution in Method 26A impingers, and that Method 26A cannot accurately speciate HCl and Cl2 in coal combustion flue gas without modification.     

Fate and Transport of Fuel Components Below Slightly Leaking Underground Storage Tanks

Fuel leaks from underground storage tanks (USTs) and piping have been a major source of groundwater contamination. In the U.S. and Europe, regulations requiring upgrading of USTs to meet specific standards have significantly reduced instances of fuel contamination. Leak detection is primarily dependent on physical measurement systems that are generally capable of detecting leak rates as small as 0.2 L/h. Fuel leaks that are smaller than this detection threshold may remain undetected for long periods of time, posing a risk of contamination to shallow groundwater resources in sensitive areas. This risk was evaluated by modeling fate and transport of fuel components from small UST leaks under a variety of subsurface conditions and assuming that secondary containment does not exist. It was found that small leaks do have the potential to impact shallow groundwater, particularly if subsurface conditions are not conducive to natural attenuation processes. This may explain situations where groundwater contamination has been found below service stations in virgin areas that have upgraded leak detection systems. Modeling indicates that passive venting of tank and piping backfill could virtually eliminate the volatile components of fuel resulting from small leaks. Monitoring the tank and piping backfill for persistent gasoline vapor under very low vapor extraction conditions may be the best way to detect small chronic fuel leaks. Routine monitoring of shallow groundwater should be a component of a leak detection program, particularly in high-risk areas.     

Comparing lifetime emissions of natural gas and conventional fuel vehicles: an application of the generalized ANCOVA model

New regulations and incentives are encouraging the use of clean, alternative fuel vehicles (AFVs) in urban areas. These vehicles are seen as one option for reducing air pollution from mobile sources. However, because of the limited number of AFVs on the road, little is known about actual lifetime emissions characteristics of in-use AFVs. This study describes the use of a generalized analysis of covariance model to evaluate and compare the emissions from natural gas vehicles with emissions from reformulated gasoline vehicles. The model describes fleet-wide emissions deterioration, while also accounting for individual vehicle variability within the fleet. This ability to measure individual vehicle variability can then be used to provide realistic bounds for the emissions deterioration in individual vehicles and the fleet as a whole. In order to illustrate the use of the model, the carbon monoxide, oxides of nitrogen (NOx), non-methane hydrocarbon (NMHC), and carbon dioxide emissions characteristics of a fleet of dedicated natural gas Dodge Ram vans and a fleet of dedicated reformulated gasoline Dodge Ram vans operating in the U.S. government fleet are explored. The analysis demonstrates the utility of the statistical method and suggests a potential for natural gas Dodge Ram vans to be generally cleaner than their conventional fuel counterparts. However, in the case of NOx and NHMCs, the analysis also suggests that these emissions benefits might be reduced over the vehicle lifetime due to higher emissions deterioration rates for natural gas vehicles. As this paper is aimed at illustrating the analysis of the covariance model, the results reported herein should be considered within the context of a more comprehensive study of these data before general conclusions are possible. Generalization of these findings to other vehicle models and alternative fuel technologies is not justified without further study.     

In-stack condensible particulate matter measurements and issues

Particulate matter (PM) emitted from fossil fuel-fired units can be classified as either filterable or condensible PM. Condensible PM typically is not measured because federal and most state regulations do not require sources to do so. To determine the magnitude of condensible PM emissions relative to filterable PM emissions and to better understand condensible PM measurement issues, a review and analysis of actual U.S. Environmental Protection Agency (EPA) Method 202 (for in-stack condensible PM10) and EPA Method 201/201A (for in-stack filterable PM10) results were conducted. Methods 202 and 201/201A results for several coal-burning boilers showed that the condensible PM, on average, comprises approximately three-fourths (76%) of the total PM10 stack emissions. Methods 202 and 201/201A results for oil- and natural gas-fired boilers showed that the condensible PM, on average, comprises 50% of the total PM10 stack emissions. Methods 202 and 201/201A results for oil-, natural gas-, and kerosene-fired combustion turbines showed that the condensible PM, on average, comprises 69% of the total PM10 stack emissions. Based on these limited measurements, condensible PM can make a significant contribution to total PM10 emissions for fossil fuel-fired units. A positive bias (indicating more condensible PM than is actually emitted) may exist in the measured data due to the conversion of dissolved sulfur dioxide to sulfate compounds in the sampling procedure. In addition, these Method 202 results confirm that condensible PM, on average, is composed mostly of inorganic matter, regardless of the type of fuel burned.     

Air Pollutant Emissions from Coal-Fired Power Plants,Report No. 2

The Public Health Service and the Bureau of Mines are conducting a joint study to evaluate a number of flue-gas-stream components from coal-burning power plants. Emissions of fly ash, sulfur oxides, nitrogen oxides, polynuclear hydrocarbons, total gaseous hydrocarbons, formaldehyde, certain metals, and carbon dioxide are determined. A previous paper covered air pollutant emissions from vertical-fired and front-wall-fired power plant boilers. This paper includes a comparative evaluation of emissions from a tangential-fired and a turbo-fired power plant boiler.     

Air pollutant emissions from the development,production, and processing of Marcellus Shale natural gas

The Marcellus Shale is one of the largest natural gas reserves in the United States; it has recently been the focus of intense drilling and leasing activity. This paper describes an air emissions inventory for the development, production, and processing of natural gas in the Marcellus Shale region for 2009 and 2020. It includes estimates of the emissions of oxides of nitrogen (NO_x), volatile organic compounds (VOCs), and primary fine particulate matter (≤2.5 µm aerodynamic diameter; PM_2.5) from major activities such as drilling, hydraulic fracturing, compressor stations, and completion venting. The inventory is constructed using a process-level approach; a Monte Carlo analysis is used to explicitly account for the uncertainty. Emissions were estimated for 2009 and projected to 2020, accounting for the effects of existing and potential additional regulations. In 2020, Marcellus activities are predicted to contribute 6–18% (95% confidence interval) of the NO_x emissions in the Marcellus region, with an average contribution of 12% (129 tons/day). In 2020, the predicted contribution of Marcellus activities to the regional anthropogenic VOC emissions ranged between 7% and 28% (95% confidence interval), with an average contribution of 12% (100 tons/day). These estimates account for the implementation of recently promulgated regulations such as the Tier 4 off-road diesel engine regulation and the U.S. Environmental Protection Agency's (EPA) Oil and Gas Rule. These regulations significantly reduce the Marcellus VOC and NO_x emissions, but there are significant opportunities for further reduction in these emissions using existing technologies.

Implications: The Marcellus Shale is one of the largest natural gas reserves in United States. The development and production of this gas may emit substantial amounts of oxides of nitrogen and volatile organic compounds. These emissions may have special significance because Marcellus development is occurring close to areas that have been designated nonattainment for the ozone standard. Control technologies exist to substantially reduce these impacts. PM_2.5 emissions are predicted to be negligible in a regional context, but elemental carbon emissions from diesel powered equipment may be important.     

Understanding oil and gas pneumatic controllers in the Denver–Julesburg basin using optical gas imaging

ABSTRACT

In the spring of 2018, a 10-day field study was conducted in Colorado’s Denver-Julesburg oil and natural gas production basin to improve information on well pad pneumatic controller (PC) populations and identify PCs with potential maintenance issues (MIs) causing excess emissions through a novel optical gas imaging (OGI) survey approach. A total of 500 natural gas-emitting PCs servicing 102 wells (4.9 PCs/well) were surveyed at 31 facilities operated by seven different companies. The PCs were characterized by their designed operational function and applications, with 83% of the PC population identified as intermittent PCs (IPCs). An OGI inspection protocol was used to investigate emissions on 447 working PCs from this set. OGI detected continuous emissions from 11.3% of observed IPCs and these were classified as experiencing some level of MIs. OGI imaging modes were observed to have a significant effect on emission detectability with high sensitivity mode detection rates being approximately 2 times higher compared to auto mode. Fourteen snapshot emission measurements (not including actuations) were conducted on IPCs in this category using a high-volume sampling device with augmented quality assurance procedures with observed emissions rates ranging from 0.1 up to 31.3 scf/hr (mean = 2.8 scf/hr). For PCs with continuous depressurization type (CPC), 36.8% had continuous emissions observed by OGI. Four supporting emission measurements were conducted on CPCs with one unit exceeding the low bleed regulatory emission threshold with an emission rate of 9.9 scf/hr (mean = 4.2 scf/hr). Additional information was collected on PC actuation events, as observed with OGI, which showed a strong correlation between observed actuation events and facility production compared to observed continuous emissions caused by MIs which did not correlate with facility production.

Implications: A novel survey approach of pneumatic controllers at oil and natural gas production facilities in the Denver-Julesburg basin, using optical gas imaging and supporting emission measurements, was demonstrated as an effective method to identify controllers with potential maintenance issues causing excess emissions. The results of the pneumatic controller and optical gas imaging surveys improved information on pneumatic controller populations within the basin and also demonstrated the significant effect optical gas imaging modes have on emission detections.     

Factors controlling the emissions of volatile organic acids from leaves of Quercus ilex L. (Holm oak)

Direct emissions and emission of precursor compounds of acetic and formic acid from higher plants are a significant source of these acids in the atmosphere. To travel from the plant cell to the atmosphere, a gas molecule must first leave the liquid phase and then enter the internal leaf gas phase. The apoplast (cell wall) is the last barrier before the molecule can escape through the stomata. During field experiments we monitored the gas exchange (H₂O, CO₂, organic acids) of Quercus ilex L. leaves. The exchange rates of acetic and formic acid under field conditions followed a typical diurnal pattern and ranged between −10 (uptake) and 52 (emission) nmol m^-2 leaf area min^-1 with the maximum around noon. Growth chamber experiments indicate that the emission is related to the stomatal conductance. We discussed the exchange rate of organic acids between the cell wall and the atmosphere in connection with Henry’s law, and the physicochemical conditions in the cell wall. The evaluation showed that for apoplastic pH values between 4 and 5, 26–130% of the measured acetic acid emission based on leaf area could be predicted.     

Early atmospheric detection of carbon dioxide from carbon capture and storage sites

The early atmospheric detection of carbon dioxide (CO₂) leaks from carbon capture and storage (CCS) sites is important both to inform remediation efforts and to build and maintain public support for CCS in mitigating greenhouse gas emissions. A gas analysis system was developed to assess the origin of plumes of air enriched in CO₂, as to whether CO₂ is from a CCS site or from the oxidation of carbon compounds. The system measured CO₂ and O₂ concentrations for different plume samples relative to background air and calculated the gas differential concentration ratio (GDCR = ?ΔO₂/ΔCO₂). The experimental results were in good agreement with theoretical calculations that placed GDCR values for a CO₂ leak at 0.21, compared with GDCR values of 1–1.8 for the combustion of carbon compounds. Although some combustion plume samples deviated in GDCR from theoretical, the very low GDCR values associated with plumes from CO₂ leaks provided confidence that this technology holds promise in providing a tool for the early detection of CO₂ leaks from CCS sites. Implications: This work contributes to the development of a cost-effective technology for the early detection of leaks from sites where CO₂ has been injected into the subsurface to enhance oil recovery or to permanently store the gas as a strategy for mitigating climate change. Such technology will be important in building public confidence regarding the safety and security of carbon capture and storage sites.     

Levels and characteristic homologue patterns of polychlorinated dibenzo-p-dioxins and dibenzofurans in various incinerator emissions and in air collected near an incinerator

Polychlorinated dibenzo-p-dioxins and dibenzofurans (PCDD/Fs) were monitored in stack gas and fly ash of various Korean incinerators and in air samples collected near the facilities. Concentrations of PCDD/Fs in emissions were investigated, and characteristic PCDD/F homologue patterns were classified using statistical analyses. The PCDD/F emission levels in stack gas and fly ash samples from small incinerators (SIs) were higher than those from municipal solid waste incinerators (MSWIs). The PCDD/F concentrations ranged between 0.38 and 1.16 pg I-TEQ/m3 (21.2-75.2 pg/m3) in ambient air samples. The lower-chlorinated furans were the dominant components in most of the stack gas and fly ash samples from SIs, although this was not the case for fly ash from MSWIs. This homologue pattern is consistent with other studies reporting a high fraction of lower-chlorinated furans in most environmental samples affected by incinerator emissions, and it can be used as an indicator to assess the impact of such facilities on the surrounding environment.