Natural Gas Facilities Research Articles

Spatial variations in daytime methane and carbon dioxide emissions in two urban landscapes, Sakai, Japan

To obtain an accurate understanding of carbon dioxide (CO2) and methane (CH4) emissions from urban areas, it is important to estimate their spatial variations because the heterogeneous nature of urban land use results in different emissions patterns. We measured CH4 and CO2 fluxes from two urban landscapes in Japan with the eddy covariance method and evaluated the spatial distributions of fluxes by combining flux footprint analysis and mobile measurements of gas concentrations. CH4 hotspots were identified at sewage plants, oil refineries, and natural gas facilities in the urban center. The fluxes (60 ± 65 nmol m−2 s−1) affected by hotspots were higher than those in the suburban and residential areas (22 ± 30 nmol m−2 s−1). High CH4 concentrations of up to 5130 ppb from the hotspots were also observed in the mobile measurements. The measured fluxes showed that the study area generally acted as a CH4 source irrespective of the presence of hotspots. The mobile measurements suggested several CH4 sources: gas leaks from natural gas networks, sewage pipes, gas-powered air conditioners, and moats. The CO2 fluxes were larger in commercial and industrial areas than residential and suburb areas, and fluxes from vegetated areas were nearly CO2-neutral in the daytime.

Development of Liquefied Natural Gas Facilities in the Baltic Sea Ports: a Geographical Perspective

This paper presents an overview of the liquefied natural gas (LNG) facilities development in the Baltic Sea. The value of the paper lies in its seek to demonstrate how the process of interaction between the shipping and energy networks unfolds through infrastructural developments of ports. The analysis is based on mapping, cartographic and spatial contextual methods. The mapping of gas supply networks, LNG facilities and traffic patterns establish the originality of this research. It shows that factors motivating the development of LNG terminals in the Baltic ports come from areas of energy and maritime policy. Moreover, in future, the emerging LNG infrastructure may have an effect on port competition in the Baltic Sea Region.

Neural networks to locate and quantify fugitive natural gas leaks for a MIR detection system

Abstract Fugitive natural gas leaks from abnormal operations or failed containment at oil and gas production fields and gas supply chains are a significant source of atmospheric methane (CH4), a potent greenhouse gas. This realization of significant CH4 leaks has stimulated efforts at mitigation using cost effective detection methods. US DOE's ARPA-E MONITOR program has supported transformational research to locate and quantify fugitive methane leaks at natural gas facilities in order to achieve a 90% reduction in CH4 emissions. This paper describes the development, application, and evaluation of a MONITOR program sponsored source attribution technology solution, wherein an artificial neural network (ANN) infers as outputs, a leak location and release rate given inputs of measured sonic anemometer wind velocities and methane sensor time series. We discuss development of our ANN model, its training, computational implementation and use to design effective sampling strategies over a range of source and sensor locations, and meteorological conditions. We report on the deployment and performance of our ALFaLDS in blind tests at Colorado State University's METEC well pad facility in Ft. Collins. Test results demonstrate that our ALFaLDS locates the engineered methane leaks to better than 8% of the domain length scale and has the ability to quantify fluxes, more accurately at high flux rates, less so at low rates. Our ANN overestimates leak source rates by an average scale factor of about 1.83 for small pads and by an average of 1.77 for larger domains. The scale factor can be used operationally but needs more research to assess its generality. This capability of leak location with high skill, speed and accuracy at moderate cost promises new automatic affordable sampling of fugitive gas leaks at well pads and oil and gas fields.

Application, Selection, and Design of Three-Winding Transformers in LNG and Petrochemical Facilities

Transformers are used in power systems to transform (step-down) voltages while maintaining the same frequency. Electrical engineers designing the power systems for a liquefied natural gas (LNG) or petrochemical facilities typically use two-winding transformers to feed multiple process units in redundant distribution schemes throughout the facility. This method is repeated further to derive different voltage levels to feed process loads. As the industry moves toward larger production facilities, which increase the power demand, multiple large two-winding transformers are utilized. This approach leads to an increase in substation footprint, switchgear equipment, power feeders, site works, etc. This article focuses on an alternative design using three-winding transformers for LNG and petrochemical facilities. The input and output of a three-winding transformer generally consist of one primary ( H ) input winding and two output windings defined as secondary ( X ) and tertiary ( Y ). The three-winding transformers are connected in a redundant configuration to feed multiple process units. In this article, different types of three-winding configurations and construction (radial or axial) methods are reviewed. In addition, this article addresses the application of tap changers, overall system performance, defining impedance parameters, and specification requirements.

Residential gas supply, gas losses and CO2 emissions in China

Natural gas has become an important energy source as its combustion is much cleaner than coal combustion and emits significantly less carbon. However, as natural gas combustion does result in some carbon emissions, government policy and monitor are needed to improve natural gas use, and reduce CO2 emissions. Previous research has tended to focus on natural gas production efficiency and the relationships between natural gas and economic growth; however, there have been few papers focused on natural gas consumption efficiency evaluations in terms of urban and industrial energy consumption efficiency and CO2 emissions efficiency. To fill this research gap, this study examined the natural gas consumption efficiencies (Natural gas consumption efficiency refers to the efficiency of natural gas from production to final consumer purchase) in 30 provinces/municipalities/autonomous in China from 2007 to 2016 by collecting and analyzing the main natural gas industry input-output index data: labor, natural gas pipe length, fixed assets, natural gas sales volume, residential gas supply, gas losses, and CO2 emissions. An Undesirable DDF (directional distance function) Dynamic Data Envelopment Analysis model was then used to analyze and compare the efficiencies in each natural gas industry index (gas industry index indicates whole indicator used on efficiency evaluation in this paper, such as labor, natural gas pipe length, natural gas sales volume, residential natural gas supply, natural gas losses, CO2 emission) in each province. We also set carry over variable which can link each period, here fixed assets is set as carry over due to its character that accumulates over period. It was found that the overall efficiency in 16 provinces. had been declining year on year and there were significant improvements needed in natural gas pipe length and natural gas losses; however, it was also found that the natural gas industry in most provinces needed to place greater importance on improving CO2 emissions efficiency. The results indicated that to improve overall gas industry operating efficiency and CO2 emission efficiency, new technologies were needed in several key areas: pipeline design, construction and maintenance management to reduce the loss rate in the old pipeline infrastructure, natural gas facilities to improve energy use, and personnel training and management to improve construction capabilities. This study is an interdisciplinary survey. Natural gas is an energy issue, CO2 emission is an environmental issue, and the method used in this study is DEA which is widely used in management and economic research. Therefore, this study combines different issues and the empirical data of China to do an interdisciplinary research.

Commonwealth Forum: Should State Government Subsidizee the Economic Development of Natural Gas Facilities?

Commonwealth Forum: Should State Government Subsidizee the Economic Development of Natural Gas Facilities?

Published Gas Price Indices Causing Concerns

The past year was unusual due to major efforts to reform renewable energy and environmental policy laws that will affect the cost and environmental effects of renewable energy and natural gas facilities. Both the Federal Energy Regulatory Commission (FERC) and the President's Council on Environmental Quality started to reform the 40‐year‐old Public Utility Regulatory Policies Act (PURPA) and the 50‐year‐old National Environmental Policy Act of 1969 (NEPA), respectively. Both laws have had a good run; however, today's electricity and natural gas markets—as well as viewpoints regarding the use of fossil fuels, renewable energy, and climate change—are very different from what they were when Congress passed both bills. The reforms may take away the competitive advantages long enjoyed by new renewable energy projects that receive state subsidies, lower the cost of payments to wind and solar power by electric utilities, and roll back a growing trend calling for the effects of federal actions on climate change. All the while, electric battery storage is beginning to establish a beachhead in wholesale electricity markets, which could accelerate the clean energy transition and have significant implications for the renewable natural gas, hydrogen, and carbon capture and storage technologies initiatives being proposed by the oil and gas industry.

Repeated leak detection and repair surveys reduce methane emissions over scale of years

Reducing methane emissions from the oil and gas industry is a critical climate action policy tool in Canada and the US. Optical gas imaging-based leak detection and repair (LDAR) surveys are commonly used to address fugitive methane emissions or leaks. Despite widespread use, there is little empirical measurement of the effectiveness of LDAR programs at reducing long-term leakage, especially over the scale of months to years. In this study, we measure the effectiveness of LDAR surveys by quantifying emissions at 36 unconventional liquids-rich natural gas facilities in Alberta, Canada. A representative subset of these 36 facilities were visited twice by the same detection team: an initial survey and a post-repair re-survey occurring ∼0.5–2 years after the initial survey. Overall, total emissions reduced by 44% after one LDAR survey, combining a reduction in fugitive emissions of 22% and vented emissions by 47%. Furthermore, >90% of the leaks found in the initial survey were not emitting in the re-survey, suggesting high repair effectiveness. However, fugitive emissions reduced by only 22% because of new leaks that occurred between the surveys. This indicates a need for frequent, effective, and low-cost LDAR surveys to target new leaks. The large reduction in vent emissions is associated with potentially stochastic changes to tank-related emissions, which contributed ∼45% of all emissions. Our data suggest a key role for tank-specific abatement strategies as an effective way to reduce oil and gas methane emissions. Finally, mitigation policies will also benefit from more definitive classification of leaks and vents.

High efficiency gas-turbine power generator GTU-2U

Introduction: the analysis of the main areas of energy transition (energie wende) from fossil fuels and nuclear power generation to renewable sources of energy has identified the following four key problems: electric power shortage; ageing of power generation facilities; insufficient infrastructure; growing demand for gas fuel. In Russia, distributed small-scale power generation facilities serve those consumers who have no access to centralized power supply or network channels of regular power generation. A combination of versatile approaches to electric power generation should be applied in the course of designing a specific energy generation facility in this context.Methods: the research project represents an analysis of the works written by the leading Russian and foreign researchers specializing on power engineering, namely, energy supply to consumers. The expert assessment method has identified the niches which are best fitted by gas turbine facilities. Computerized and simulation modeling techniques were used to perform the analytical and statistical processing of the project findings.Results and discussion: the trend for the structural improvement of small-scale liquefied natural gas facilities has been identified in the course of the research. The author has substantiated development of systems for power supply to smallcapacity liquefied natural gas production facilities. The proposed gas turbine GTU-2U is designated for generation of electric energy, if in operation as a standalone facility as part of a centralized heating and power plant in the standalone mode of operation, or in case of concurrent operation along with an energy generation system within the framework of distributed small capacity networks. The co-authors have substantiated the unit’s practical application and identified the GTU-2U distribution market both in Russia and abroad: small capacity distributed power generation industry and power supply to small-capacity liquefied natural gas production facilities. The latter is a relatively new market which is in the process of proactive development both in mature and developing economies. This power supply pattern will enable to monetize gas deposits, located far from pipelines and to supply gas to hard-to-access regions.Conclusion: the key trends in the development of the contemporary power generation industry are considered in the article. Gas turbine unit GTU-2U has been designed. This unit is capable of generating power both as a standalone facility, as a component of a centralized heating and power plant in the standalone mode of operation, or in case of concurrent operation along with an energy generation system. Its strengths substantiate its practical application both in the Russian and international power generation markets.

Verifying the extent of plumes from produced formation water: a Wheatstone case study

Chevron Australia Pty Ltd operates the Wheatstone liquefied natural gas facility in Western Australia under a Joint Operating agreement. Hydrocarbons from Wheatstone, Iago and Julimar-Brunello fields are sent to the Wheatstone Platform (the Platform), located ~50 km north of the Montebello Islands, for dewatering and dehydration before being transported onshore for final processing. Produced formation water (PW) is processed (treated) and, once criteria are met, discharged overboard. PW at Wheatstone is predicted to rapidly dilute in the receiving ocean to concentrations below water quality criteria (Australian and New Zealand Environment Conservation Council guidelines and ecotoxicology), though empirical evidence is needed to verify the actual discharge risk. Seawater (i.e. cooling water, CW) is also abstracted for cooling duty on the Platform, chlorinated and discharged. This paper describes a field verification campaign aimed at understanding PW and CW behaviour in the water column post-discharge, dilution with distance and whether numerical modelling of dilutions is accurate. The campaign was designed to evaluate plume characteristics by monitoring both entrained PW constituents (i.e. hydrocarbons and metals) and using a Rhodamine WT tracer dye. Monitoring of these constituents was done using an array of sampling techniques, including fluorometry, remotely operated vehicles and discrete water samplers. Results indicate rapid dilutions post PW and CW discharge, with dye fluorometry proving a valuable tool for understanding plume characteristics. Water sampling data interpretation indicated dilutions were likely orders of magnitude greater than anticipated, likely due to variable flow effects and turbulence induced by the Platform structure for PW, and the influence of entrained air within the plume for CW.

Using Concepts from the Study of Social Movements to Understand Community Response to Liquefied Natural Gas Development in Clatsop County, Oregon

Shifts in natural gas supply and demand since the early 2000s have triggered proposals for import and export terminals in coastal locations around the United States. Demand for such facilities is likely to grow with increasing rates of natural gas exports. Clatsop County, Oregon, is one such location that experienced over 10 years of debate surrounding the development of these facilities. The first liquefied natural gas (LNG) facility was proposed in this area in 2004; the final was withdrawn in 2016. While residents expressed both support and opposition early on, opposition dominated by the end. Drawing on insights from the literature on social movements, we conduct a case study of community response to LNG proposals in Clatsop County. We show how opponents were able to successfully frame the potential risks of LNG in a manner that had strong community salience, allowing them to appropriate resources and create political opportunities to advance their cause and influence local and state decisions. Engaging with this case provides an opportunity to observe the behavior and decisions of both opponents and supporters over time, and how they affected project outcomes. LNG proposals in Oregon have been among the most controversial cases of LNG development in the United States. As shale gas development continues to grow, understanding the conflicts involved with its associated infrastructure is critical to creating a more just and equitable energy system.

Cost-based fire risk assessment in natural gas industry by means of fuzzy FTA and ETA

Fire is the most prevalent accident in natural gas facilities. In order to assess the risk of fire in a gas processing plant, a fault tree analysis (FTA) and event tree analysis (ETA) has been developed in this paper. By utilizing FTA and ETA, the paths leading to an outcome event would be visually demonstrated. The framework was applied to a case study of processing plant in South Pars gas complex. All major underlying causes of fire accident in a gas processing facility determined through a process hazard analysis (PHA). Fuzzy logic has been employed to derive likelihood of basic events in FTA from uncertain opinion of experts. The outcome events in event tree has been simulated by computer model to evaluate their severity. In the proposed methodology the calculated risk has the unit of cost per year which allows the decision makers to discern the benefit of their investment in safety measures and risk mitigation.

Natural gas distribution proposal in Lima’s urban hills through lean logistic and mixed whole linear programming

The availability of natural gas in Lima — Peru, from Camisea, in several urban areas of Lima, for technical reasons there are no natural gas facilities especially in peripheral urban areas in the highlands or hills. This is compensated by FISE government social programs providing subsidized liquefied petroleum gas balls. In this context, a proposal has been developed to provide natural gas to these elevated areas, in particular to Cerro San Cristóbal, located in the boundaries of the districts of Rímac and San Juan de Lurigancho — Lima. This proposal is based on the principles of Lean Logistic and linear programming of mixed burials. The results will imply a better supply of natural gas to peripheral areas and energy poverty, the inherent security problems must also be addressed.

A time-dependent probabilistic model for fire accident analysis

Fire is among the most common and devastating accidents in the hydrocarbon production and processing industry. Many efforts have been dedicated to assessing fire accident likelihood; however, most of these studies considered fire probability as spatially distributed, ignoring the time dependence of the fire accident scenario. In this study, a robust and practical model is proposed to analyze fire accident probability in a congested and complex processing area. This model integrates a conditional probability approach – the Bayesian network (BN) - with a time-dependent scenario evolution approach, Stochastic Petri Nets (SPN). The computational fluid dynamics (CFD) tool is used to estimate the time-dependent scenario consequences. The outcome of the model is fire probability as a function of time and location caused by a specific leak rate and leak duration. A case study of fire probability analysis in a Floating Liquified Natural Gas facility (FLNG) is presented. This study demonstrates the importance of the temporal dependency of the fire scenario and the proposed model can serve as the required tool for time-dependent fire probability analysis, further safety measures’ application and system optimization.

Measurements of Blowdown Thrust Loading in Natural Gas Facilities

Abstract The thrust loading on a vertical blowdown stack during a natural gas blowdown was investigated using a combined experimental and modeling approach. A gravimetric vessel initially at 4000 kPa-g was blown down through two geometrically different stack assemblies. Thrust loads were measured using a dynamic weigh scale typically used for gravimetric calibration of gas flow meters. A one-dimensional (1D) compressible flow model, calibrated using the experimental data, revealed stagnation pressure losses at the entrance to the riser, resulting in lower thrust loads. A comparison between thrust loading obtained from the measurements and the 1D compressible flow model is presented. This work shows that the analytical flow model predicts the blowdown thrust loads within ±30%.

Technology Focus: Offshore Facilities (September 2019)

Technology Focus I had the pleasure of reviewing 322 offshore-facilities papers submitted to SPE during the past year and selected three for inclusion in this issue as well as three for additional reading. This is my first assignment as a member of JPT’s Editorial Committee, and I am grateful. During my summer family vacation, I enjoyed reading all of the papers and considered a special theme related to today’s disruption of our oil and gas industry known as “Industry 4.0.” The first industrial revolutions were related to the commencement of electrification, followed by machinery. The third is the computer era, and the fourth (4.0) is the current age of machine learning, artificial intelligence, data analytics, and the Internet of things. Therefore, to start our discussion, let us ask the basic question: What is the definition of offshore-facilities project success in the context of Industry 4.0? Generally, cost (economic), time, and scope (quantity and quality, including safety) are the common project-success indicators. However, I believe we can expand these indicators to the social and environmental areas. So, for the oil and gas upstream industry, Industry 4.0 is the strategic positioning of technologies that can benefit production assets, business, and sustainability (social and environmental). The development of new subsea and offshore technologies, methods, processes, and monitoring should consider the tangible benefit of social and environmental effects. The selection of innovative subsea processing systems, platforms, real-time monitoring applications, automation, smart fields, intelligent wells, data analytics, and well/reservoir/facilities technologies and decommissioning should reflect an initiative to improve environmental performance. For instance, when a stakeholder selects a subsea processing and facilities technology scheme, it should optimize and accelerate the recovery of hydrocarbon, increasing its yield, extending the life of the field, reducing the floating production facilities while minimizing carbon footprint, and creating a positive social effect and low environmental impact. Let us consider another offshore-facilities project example. The world’s offshore liquefied-natural-gas (LNG) production concepts began in the 1970s but were only significantly enhanced in the mid-1990s. I was a finalist in the SPE Student Paper competition at the national level in 1997, and I wrote about the concept of floating liquefied natural gas (FLNG) facilities in Indonesia as a case study. The FLNG concept has been used because it has the capability to transport the LNG to nearly any location. However, we know that the design of FLNG facilities has many challenges, including floating design, process selection, equipment sizing, process safety, wind effects, metocean effects, and product transfer. Therefore, for FLNG, bigger is not always better and a sustainable business model is important. It took almost 25 years for engineers and experts to construct an FLNG facility. Now, the Prelude FLNG is the world’s largest FLNG facility as well as the largest offshore facility ever constructed. To derive the greatest benefit from Industry 4.0, we must develop strong and reliable data, lessons learned, experiences, and knowledge management. The three papers and recommended additional reading presented here reflect support for the implementation of Industry 4.0 such as innovation, digitalization (automation), low-cost facilities development, project flexibility, and facilities life extension. I hope you enjoy reading these papers as much as I did. Recommended additional reading at OnePetro: www.onepetro.org. OTC 28256 Standardization and Replication of Lean Wellhead Platform To Accelerate Hydrocarbon Maturation From Exploration to Production for Marginal-Field Development by H. Yong, Shell, et al. OTC 28276 Cost-Effective Riser Solutions for Deepwater Gas Developments: Steel Lazy Wave Riser and Tethered Catenary Riser by Stéphan Eyssautier, Subsea 7, et al. OTC 28340 Pragmatic and Consistent Approach to Life Extension of Floating Structures by Cedric Morandini, Bureau Veritas, et al.

The 2017 ISO New England System Operational Analysis and Renewable Energy Integration Study (SOARES)

The bulk electric power system in New England is fundamentally changing. The representation of nuclear, coal and oil generation facilities is set to dramatically fall, and natural gas, wind and solar facilities will come to fill their place. The introduction of variable energy resources (VERs) like solar and wind, however, necessitates fundamental changes in the power grid’s dynamic operation. VER forecasts are uncertain, and their profiles are intermittent; thus requiring greater quantities of operating reserves. This paper describes the methodology and the key findings of the 2017 ISO New England System Operational Analysis and Renewable Energy Integration Study (SOARES). This study was commissioned by the ISO New England stakeholders to investigate the effect of several scenarios of varying generation mix on normal operating reserves. The project was conducted using the holistic assessment approach called the Electric Power Enterprise Control System (EPECS) simulator. The study finds a minimal impact on current normal operating conditions in the ISO-NE system for scenarios with relatively low penetration of VERs. Nevertheless, for scenarios with a significant presence of VERs, the system may require additional amounts of both upward and downward load following reserves and upward and downward ramping reserves to effectively maintain reliable operations. In these scenarios, the curtailment of semi-dispatchable resources also becomes an integral part of balancing performance; in part to complement operating reserves and in part to mitigate the topological limitations of the system. Indeed, the integration of significant amounts of VERs in relatively remote regions significantly increases the potential of congestion on several key interfaces. In many of these scenarios, the system experiences heavy saturations of regulation reserves and their increase would enhance the response to residual imbalances. The concludes with final insights into the emerging roles of curtailment, energy storage, and demand response as integral parts of normal balancing performance.

About this title - Groundwater in Fractured Bedrock Environments: Managing Catchment and Subsurface Resources

Fractured bedrock aquifers have traditionally been regarded as low-productivity aquifers, with only limited relevance to regional groundwater resources. It is now being increasingly recognised that these complex bedrock aquifers can play an important role in catchment management and subsurface energy systems. At shallow to intermediate depth, fractured bedrock aquifers help to sustain surface water baseflows and groundwater dependent ecosystems, provide local groundwater supplies and impact on contaminant transfers on a catchment scale. At greater depths, understanding the properties and groundwater flow regimes of these complex aquifers can be crucial for the successful installation of subsurface energy and storage systems, such as deep geothermal or Aquifer Thermal Energy Storage systems and natural gas or CO 2 storage facilities as well as the exploration of natural resources such as conventional/unconventional oil and gas. In many scenarios, a robust understanding of fractured bedrock aquifers is required to assess the nature and extent of connectivity between such engineered subsurface systems at depth and overlying receptors in the shallow subsurface.

New Operators, Well Designs Drive Record Gas Production in Haynesville

The Haynesville Shale might be the greatest comeback story of the US shale revolution. At one point in 2016, there were just 13 active rigs in the dry-gas play that stretches between Louisiana and Texas. That figure has increased fourfold to today and, in April, the Haynesville set a new production record of 10.5 Bcf/D—the strongest output since 2011, per the US Department of Energy (DOE). The resurgence has been led not by the large operators who initially put the Haynesville on the map, but by a group of private equity-backed operators that entered the play within the last few years. Their momentum has been driven by liquefied natural gas (LNG) facilities that began exporting the product from the US Gulf Coast in 2016. Petroleum engineers have also moved the needle by creating a class of horizontal wells that look nothing like what the region has seen before in terms of productivity. “I think that over the past 3 or 4 years, the understanding of optimal frac design and the selection of the targets has evolved quite dramatically,” said Artem Abramov, the head of shale research for Rystad Energy in Oslo. The nearly 300 wells that were brought online in the Haynesville during 2017 have produced a cumulative average of 3.6 Bcf. They continue to generate an average of 8.5 MMcf/D, according to public data compiled by ShaleProfile. This is a marked improvement over 2015 vintage wells that managed only 1.5 MMcf/D after reaching the same cumulative production point. In terms of long-tail production, this is an increase of more than 450%. One of the most critical factors behind the improved recovery is the increased use of proppant in horizontal wells. Thanks to lower prices made possible by the in-basin mine trend taking hold across the US shale sector, operators can afford to place two or three times the amount of sand into Haynesville’s tight-rock system than they were prior to 2016. Abramov remarked that this development has effectively “re-established it as a completely new play.” Too Much of a Good Thing Rig counts have remained steady at around an average of 55 since the start of the year but the region is seeing more completion activity and has become one of the fastest-growing demand centers for hydraulic fracturing crews in the US. As the race to reawaken the sleeping giant continues on, there are concerns that too much production could harm the play’s economic standing. Calgary-based RS Energy Group (RSEG) recently looked at the issue and found that takeaway capacity may hit a wall as early as this summer, possibly curtailing drilling plans for the rest of the year. “It’s not a Haynesville constraint in isolation,” explained Trevor Sloan, an executive director and co-head of research at RSEG. “Rather, Haynesville producers share common routes to coastal demand centers—including LNG facilities—with northeast producers, and the midcontinent for that matter. Potential from all those basins could cause some congestion on routes south.”

Implementation of a top-down noise control strategy for a liquefied natural gas peak-shaving facility

ABSTRACTThere have been many previous noise-related studies on liquefied natural gas (LNG) facilities in the United States; however, noise control of these facilities using a top-down approach has not been explored in detail. Most studies have demonstrated noise compliance to applicable standards by focusing on a combination of treatments and specifications, with less consideration on control technology feasibility, ranking, and cost-effectiveness. The Federal Energy Regulatory Commission (FERC) prohibits natural gas facilities from emitting day-night noise levels in excess of 55 dB(A) (equivalent to 24-hr continuous level of 49 dB(A)) at nearby receivers. A case study was conducted to evaluate a top-down approach to reduce noise at a typical LNG peak-shaving facility under normal operating conditions, accounting for technical feasibility, control effectiveness, and cost implications. A modeling approach (International Organization for Standardization standard ISO 9613-2) was used to predict and evaluate the facility’s noise reduction potential. The study found that the strategy could achieve feasible and environmentally effective reductions up to 11 dB(A) at 500 m from the facility by first identifying source groups with highest-emitting sources and then targeting major noise source contributors per group. This approach is cost-effective because the FERC noise goals can still be achieved by avoiding unnecessary control costs associated with lower-ranked sources. The study identified the following four source groups as the highest noise emitters: (1) liquefaction and instrument air, (2) boil-off gas (BOG) compression, (3) glycol water system (air coolers), and (4) pretreatment. Of all the treatments evaluated, installation of enhanced silencers for gas turbine (GT) package—as well as construction of an acoustical building for the BOG compressors and drivers—resulted in the greatest noise reduction at nearby receivers. The study notes that incremental treatment costs presented in this paper are approximate estimates that may vary depending on factors such as facility size and region.Implications: This study assessed potential noise reductions associated with implementing a top–down noise control strategy on a typical LNG peak-shaving facility. The study determined the top–down noise control strategy could achieve feasible and environmentally effective reductions up to 11 decibels at receivers within 500 m from the facility’s center. As LNG suppliers need to support potential supply disruptions, some regions of the US, including New England and Gulf Coast with projected increase in LNG exports and growing needs from power sector, may find information in this study useful with regard to evaluating and prioritizing noise reduction potential of their LNG peak-shaving facilities.