Natural Gas Distribution Infrastructure Research Articles

Investigation of the Spatial Distribution of Methane Sources in the Greater Toronto Area Using Mobile Gas Monitoring Systems.

For methane emission reduction strategies in urban areas to be effective, large emitters must be identified. Recent studies in U.S. cities have highlighted the contribution of methane emissions from natural gas distribution networks and end use. We present a methane emission source identification and quantification method for the Greater Toronto Area (GTA), the largest metropolitan area in Canada, using mobile gas monitoring systems. From May 2018 to August 2019, we collected 77 surveys of methane mixing ratios, covering a distance of about 6400 km, and sampled emission plumes from sources such as closed landfills, natural gas compressor stations, and waterways. Our results indicate that inactive landfills emit less than inventory estimates. Despite this discrepancy, we confirm that the waste sector is the largest methane emitter in the GTA. We also report that the frequency of methane leaks from the local distribution system ranges between 4 and 22 leaks per 100 km of roadway in downtown Toronto, which is comparable to the range observed in U.S. cities, which have invested in modern natural gas distribution infrastructure. Last, we find that engineered waterways, whose emissions are currently not reported in inventories, may be a significant source of methane.

Risk Assessment of Incidents Response for Downstate New York Natural Gas Distribution Infrastructure

In the United States today, there are thousands of miles of an extended network of natural gas pipelines across the nation. Current pipeline explosions and leaks in several regions have challenged the natural gas industry to re-evaluate efforts and to pursue proactive strategies. Safety and the environmental threat has become a primary concern in the United States and around the world, but mostly in cases where natural gases, oil, and other hazardous wastes are intricate. Thus, a significant point in the natural gas pipeline industry that signifies both the economic and social issue is the unplanned pipeline risk. In this article, a quantitative data analysis was performed for Downstate New York companies, Con Edison and National Grid. There, the data from various natural gas pipelines was observed for the trend regarding failing material, failure cause, aging characteristics, and perform a risk assessment to come up with training and risk checklist that could be crucial for risk handling strategies. The statistical analyses of the natural gas pipeline-related incident data for distribution pipelines between 2012 and 2016, which were composed from Pipeline and Hazardous Material Safety Administration (PHMSA) of the United States Department of Transportation (DOT), are compiled. The total miles in the gas distribution pipelines in downstate New York is approximately 48,539 as of 2016. The equipment failure, other incident cause, other outside force, and excavation damages are the leading causes of the pipe-related incidents, which are responsible for over 20% of the total incidents between 2012 and 2016. As a result, a quantitative research methodology has been developed as the suitable approach to achieve risk assessment. Mainly, this approach aims towards risk management in natural gas industry projects using the maximum likelihood method on 70 rupture incidents between 2012 and 2016, which were collected from the PHMSA pipeline incident database. The hypothetical quantitative risk assessment of the gas distribution pipelines are illustrated by combining the statistics of the pipeline rupture incidents, as well as risk assessment performed in the present study.

Joint Costs in Electricity and Natural Gas Distribution Infrastructures: The Role of Urban Factors

This paper analyzes the joint cost structure of electricity and natural gas distribution investments. Assessing the joint costs is critical for urban development and public policy regarding competition at the local level. The paper accounts for the urban and geographic factors at the local level, while the previous literature primarily used company-level data with a few or no site-specific variables in joint cost analyses. An empirical analysis of the multi-utility capital costs suggests that the local urban and geographic conditions affect such costs, with economies of scope present in electricity and natural gas both in terms of total costs and underground investment costs. Hence, the joint service provision makes economic and environmental sense for urban policy makers.

A greenhouse gas abatement framework for investment in district heating

Biomass resources could be used in the Northeastern U.S. in centralized district heating networks supplied by combined heat and power (CHP) plants to reduce consumption of petroleum resources (fuel oil), generate renewable electricity, and cost-effectively reduce greenhouse gas (GHG) emissions when supplying buildings with space and water heating. Alternatively, the CHP plants could be powered by natural gas, which would reduce GHG emissions relative to conventional, individual heating solutions owing to the improved efficiency of cogeneration. To assess the potential for investment in these technologies, hourly heat load demand in residential and commercial buildings in all New England and New York state towns (populations > 5000) was estimated and used to optimize the energy efficiency of district heating networks using MODEST software. All of the 116 studied locations without access to natural gas distribution infrastructure showed negative carbon abatement costs, the majority between −$250 and −$38 per Mg CO2 equivalents (eq.), when biomass-fed district heating was implemented due to significantly reduced operational costs and life cycle GHG emissions. Similarly, almost all (465 out of 467) locations connected to the natural gas grid were found to have negative GHG abatement costs, ranging from −$4500 to −$400 per Mg CO2 eq., demonstrating strong economic feasibility for district heating. Natural has an economic advantage over biomass in district heating due to its combined cycle CHP plants being able to generate more electricity per heat unit compared to biomass CHP plants and its lower O&M costs. District heating in all locations could abate 2.6 billion Mg of CO2 eq. at an economic surplus over 30 ears of continuous operation. Using a framework that integrated spatial tools, optimization, LCA, and cost evaluation, this study uniquely identified promising locations in the U.S. where district heating could be both environmentally and economically beneficial. This framework can be applied to other global regions that have significant space heating needs, for CHP implementation, and as a tool for identifying alternative building energy investments, such as improved insulation or individual space heating solutions, which in some cases could yield higher GHG reductions per dollar.

Design and optimization of a natural gas-fired thermoelectric generator by computational fluid dynamics modeling

The paper reports the results of the computational part of an ongoing research and development project aimed at designing and optimization of a thermoelectric generator fired with natural gas. The idea of the project is to provide an independent and reliable source of power in the power range of 50–100W for island-mode supply, tailored for remote objects of the natural gas distribution infrastructure which, for economic reason, are not connected to the electric grid. The device includes a burner as a heat source, flow channels for air and for exhaust gases and a set of thermoelectric modules generating electric current if subject to temperature difference. The pre-selected design configuration (type E) was subject to parametric optimization. A corresponding numerical model based on the Ansys/Fluent computational fluid dynamics code was built. The optimization procedure aims to maximize the temperature difference across the thermoelectric module in order to maximize the generated power output. Simultaneously, it is essential to maintain the hot-side temperature below the required technical limit of 320°C. First, thirteen design parameters (most of them concerning geometry) influencing the target function were identified. A central value and a possible range for each parameter have been set. Next, the partial impact of each parameter on the target function was found, and the set of the design parameters was limited to eight. Finally, only five parameters were estimated to be non-monotonically related to the generated power. The impact of the selected five parameters on the target function was investigated using a central composite design optimization plan. The set of points obtained in the multi-dimensional response surface was then limited to points meeting the imposed limitation of maximum temperature. Eventually, three candidate points (i.e. three sets of design parameters) have been proposed for the next stage of the project involving an experimental set-up for the design of the prototype.

Comparing Low- and High-Temperature Electrochemical Process Pathways for Converting H2o and CO2 into Synthetic Natural Ga

The conversion of water and carbon dioxide into useful products such as synthetic natural gas using renewably supplied electrical energy can offer several advantages for stabilizing the electric grid and increasing the security of energy supply chains. In addition to providing increased grid operational flexibility for dealing with intermittent renewable electrical energy supplies, infrastructure changes such as hydrogen pipelines could conceivably be avoided in situations where natural gas pipelines and CO2 sources coincide. The natural gas distribution infrastructure is well developed in many countries, enabling the fuel to be transported long distances and easily delivered throughout cities. Using the existing pipeline to transport renewably generated synthetic natural gas (SNG) can further enhance the value of the product via offering grid services such as load leveling. While the price of natural gas is near record lows in the United States, many other countries are working to develop SNG as an alternative fuel for transportation and residential/commercial heating markets, especially in Europe and for island nations. This study presents pathway studies of low- and high-temperature electrolysis integrated with an SNG plant design and evaluates their performance for producing SNG by reacting renewably generated hydrogen with carbon dioxide. The carbon dioxide feedstock is assumed to be captured and scrubbed from either an existing coal fired power plant at the city-gate or from sequestered CO2, where the SNG plant is co-located. In the first pathway, water is split using either low-temperature alkaline or proton exchange membrane technology. In a second path, the co-electrolysis of steam and CO2 is done in-situ using high temperature (600°C) solid oxide cell technology. Historically, methanation has been a common practice for eliminating carbon monoxide and carbon dioxide in various chemical processes such as ammonia production and natural gas purification; for these processes, only small amounts (1-3% molar basis) of carbon oxides need to be converted to methane. A “bulk” methanation process is unique due to the high concentration of carbon oxides and hydrogen. In addition, the carbon dioxide is the only carbon source, and the reaction characteristics of carbon dioxide are much different than carbon monoxide. In process paths involving low-temperature electrolyzers, a methanation plant is required. In this study, thermodynamic and kinetic considerations of the methanation reaction are explored to model and simulate a system of reactors for the conversion of hydrogen and carbon dioxide to SNG. Multiple reactor stages are used to increase temperature control of the reactor and drain water to promote the forward direction of the methanation reaction. Heat recuperation and recovery using organic Rankine cycle units for electricity generation utilizes the heat produced from the methanation reaction. Bulk recycle is used to increase the overall reactant conversion while allowing a satisfactorily high methane content SNG product. A hydrogen membrane separates hydrogen for recycle to increase the Wobbe index of the product SNG by increasing the methane content to nearly 93% by volume. In both pathways, the product SNG has a minimum Wobbe index of 47.5 MJ/m3 which is acceptable for natural gas pipeline transport and end-use appliances in existing infrastructures. The overall plant efficiencies of both pathways are compared as well as the expected price of the product SNG using the H2A tool.

System Analysis of Poly-Generation of SNG, Power and District Heating from Biomass Gasification System

A transition towards synthetic fuels such as synthetic natural gas (SNG) is a requirement that can contribute to future energy security and sustainable development. Conventional coal gasification could be replaced with biomass gasification to produce synthetic natural gas that can be used in existing natural gas distribution infrastructure, transport, domestic and industrial sectors with almost no or little modifications. This study evaluates the integration of synthetic natural gas production using biomass gasification with combined heat and power plant (CHP). Various system performance indicators are used for comparing different systems such as carbon conversion, energy efficiencies, economic feasibility and commercial viability of technologies. For the evaluation of studied system, 100 MW of dried biomass is used as input for synthetic natural gas production together with power and district heating. The results obtained by integration of process showed a substantial synthetic natural gas production potential i.e. about 74.3 MW based on 100 MW biomass input. The process heat requirement of the system is about 26.60 MW and 0.60 MW for electrification. The results indicate that 27.35 MW heat is available for district heating and about 3.4 MW net amount of heat is available for power production by organic Rankine cycle (ORC). The results also show that the system is 74.3 % efficient based on lower heating value. Poly generation concept of SNG production along with power and district heating system claims its economic viability.

The effect of distributed electricity generation using natural gas on the electric and natural gas grids

The efficient and economical design and operation of individual small-scale distributed generation (DG) units has received considerable attention. It is now plausible to envision a future scenario where a large number of such units, spanning capacities from the kW to the MW scale, are deployed in a region. As distributed electricity generation using natural gas becomes more widespread, the dependency of the electric grid on the natural gas grid will increase. This concerns multiple interaction points along the two networks, and reaches beyond the natural gas demand of large-scale load following or baseload gas-fired powerplants. More specifically, a better understanding is required of the potential changes in the dynamic behavior and interaction of the electricity and natural gas grids at or close to residential use sites (neighborhoods), where the small-scale DG infrastructure is likely to be located. In this paper, an optimization-based framework is developed for analyzing the operation of an ensemble of small-scale natural gas fueled DG units, and quantify their ability to flatten the electric grid load (i.e., reduce the peak demand) of the neighborhood that they serve. Our analysis relies on realistic energy use data and takes into account capacity limitations of the current natural gas distribution infrastructure, centralized vs. decentralized control of the DG unit operation, equipment durability considerations, heating preferences of home users, and seasonal effects. There is a substantial increase in natural gas consumption near consumers for all scenarios considered, which has implications for the control of the natural gas grid. We demonstrate the importance of having a centralized decision-making scheme when multiple distributed generation resources are present, and make recommendations for the optimal sizing of generators.

Fugitive methane emissions from leak-prone natural gas distribution infrastructure in urban environments

Fugitive emissions from natural gas systems are the largest anthropogenic source of the greenhouse gas methane (CH4) in the U.S. and contribute to the risk of explosions in urban environments. Here, we report on a survey of CH4 emissions from 100 natural gas leaks in cast iron distribution mains in Metro Boston, MA. Direct measures of CH4 flux from individual leaks ranged from 4.0 – 2.3 × 104 g CH4•day−1. The distribution of leak size is positively skewed, with 7% of leaks contributing 50% of total CH4 emissions measured. We identify parallels in the skewed distribution of leak size found in downstream systems with midstream and upstream stages of the gas process chain. Fixing ‘superemitter’ leaks will disproportionately stem greenhouse gas emissions. Fifteen percent of leaks surveyed qualified as potentially explosive (Grade 1), and we found no difference in CH4 flux between Grade 1 leaks and all remaining leaks surveyed (p = 0.24). All leaks must be addressed, as even small leaks cannot be disregarded as ‘safely leaking.’ Key methodological impediments to quantifying and addressing the impacts of leaking natural gas distribution infrastructure involve inconsistencies in the manner in which gas leaks are defined, detected, and classified. To address this need, we propose a two-part leak classification system that reflects both the safety and climatic impacts of natural gas leaks.

Urban Model for the Analysis of the Brazilian Natural Gas Distribution Infrastructure

This paper analyses through the use of the analytic hierarchy process (AHP), the influence of several urban parameters in the expansion of natural gas distribution in the Brazilian market. The logic based on pair combination allows the verification of relationships such as demographic density and distribution of family income, residential and industrial concentration, distance between areas that could be served and others that are effectively attended by natural gas, defining through the attribution of a priorities scale, the decisive aspects in the selection of areas that must receive the natural gas expansion. The model intends to propose the integration between the city’s profile and the natural gas use, using the advance of natural gas on São Paulo City as a specific case study. As a conclusion, the model provides the neighbourhoods expansion rankings, verifying the coherence of the proposal based on urban parameters analysis through the test with suburban districts of the São Paulo city.