Gas Technology Institute Research Articles

Multi-channel capacitive sensing system for cross bore detection and classification by machine learning

Cross bore is an intersection of an existing underground pipeline such as a sewer pipeline by a second utility such as a gas pipeline installed using the trenchless technique, which could lead to severe incidents like explosions. There are hundreds of thousands of existing cross bores in the U.S., at an estimated average rate of 0.4 per mile of pipeline reported by Cross Bore Safety Association, which is at high risk and a significant threat to public safety if not well detected, characterized, and mitigated. The research on high-accuracy nondestructive evaluation (NDE) methods that can identify cross bore areas more effectively and efficiently under challenging field environment is of vital importance. This paper proposes a multi-channel capacitive sensing system for cross bores detection and classification, which passes through the gas pipe to inspect the dielectric property changes of surrounding materials and indicates the existence of cross bores. A 3-D simulation modeling tool was developed to optimize the footprint of multi-channel sensor, and the effect of four cross bore types on the received capacitance values was investigated. The lab-scale experiments were performed using the developed multi-channel capacitive sensing system through a soil box setup, and the experimental results indicated that the developed system can identify the four types of cross bores. To achieve an automated decision making for the cross bores detection and classification, machine learning (ML) algorithms were developed through the experimental dataset, and it was found that the subspace k-nearest neighbors (SKNN) performed better with a high classification accuracy. Finally, field test validation was performed at the pipe farm (Gas Technology Institute, IL, USA) and the superior capability of the developed sensing system in identifying cross bores as well as other key parts in gas pipelines including butt fusion and saddle fitting with coil was demonstrated.

Evaluation protocols for flammable and toxic dispersion models

AbstractThe siting of liquefied natural gas (LNG) facilities requires several types of hazards to be quantified so that the risk to the public and public property in areas surrounding each facility can be properly assessed. In order to quantify the hazards from potential accident scenarios, computational tools must be used. Given the multiplicity of tools available, ranging from empirical models to 3D computational fluid dynamics packages, the agency responsible for reviewing the hazard analysis may not have the methodologies or protocols necessary to determine the suitability of a given model to a certain scenario, its accuracy, and any other setup requirements. The Pipeline and Hazardous Materials Safety Administration (PHMSA) commissioned Blue Engineering and Consulting and the Gas Technology Institute to develop a set of model evaluation protocols (MEPs) that will allow the review of modeling tools for several different hazards, including flammable and toxic dispersion, source terms for dispersion models, vapor cloud explosions, and boiling liquid expanding vapor explosions (BLEVEs). The project will provide PHMSA with the means to properly evaluate modeling tools for these hazards, which are required to be evaluated in an LNG facility siting study. It will also provide clarity to LNG plant developers and their safety consultants on which models may be used and which safety factors need to be applied, and will increase the public's confidence in the regulatory review process of LNG facilities. This article discusses the first two MEPs completed as part of this project, which are focused on evaluating flammable dispersion and toxic dispersion models, respectively. This article describes the evaluation methodology, including the information to be submitted by the model proponents and the review process, and the model validation databases compiled for each protocol.

Technology Focus: Gas Production (August 2021)

The carbon-free future should not be confused with a utopian future. A zero-carbon world will include the difficult realities experienced in Texas in February 2021. As shown in a graph of US EIA data, during the recent extreme cold event in Texas, wind and solar could not hold flat compared with their baseline the week before (4–8 February). Coal and nuclear remained mostly steady, while natural-gas producers ramped up supplies delivered to power plants by a factor of 4, helping people who were struggling to heat their homes. Natural gas may not receive well-deserved recognition from some quarters, and blackouts and loss of life still occurred, but our industry stepped up when people needed us most. Texas generates 25% of the wind power in the US and has more solar potential than 18 northern states combined, yet wind and solar simply failed when called upon. As the world attempts to go carbon-free, this reviewer hopes that more consumers will see the difference between results and public-relations promises. It will take a legitimate technological step-change before an unsubsidized renewable energy source is capable of replacing reliable fossil fuels. Imagine if Sir Isaac Newton, with all his brilliance, had tried to be the first man to land on the moon. In 1720, the cumulative knowledge did not exist to allow that to happen, and, if he had tried, he could have spent the entire British treasury and still failed. By standing upon the shoulders of giants like Newton, others were able to reach the moon 250 years later. Step-change technological breakthroughs happen when their time has come, not when mandated by political pressure. Until you hear that commercial fusion reactors are online or that low-cost, grid-scale electricity storage made from commonplace materials can handle a 10-day cold snap or heat wave, there is no need to hang up your pipe wrenches. Fossil fuels will remain the most energy-dense, cost-effective, reliable energy source until an extraordinary breakthrough creates a better alternative. The three papers selected for this feature demonstrate the continued critical role of gas production, and innovation therein, in the necessary daily role of supplying the world’s energy needs. One discusses means of exploiting stranded offshore gas reservoirs; the second details an Eagle Ford cyclic-gas-injection enhanced-oil-recovery effort; and the third focuses on the fracturing interference of multi-well pads in shale gas reservoirs. Reference Wilson, Scott. 2021. “EIA Texas Power Generation Data, February 2021.” Recommended additional reading at OnePetro: www.onepetro.org. SPE 200468 Hydraulic-Fracturing Test Site Phase-2 Enhanced-Oil-Recovery Pilot: Huff ’n’ Puff Pilot in the Permian Midland Basin by Shadi Salahshoor, Gas Technology Institute, et al. SPE 202448 Unconventional Gas Development in Queensland, Australia: How Well Does It Align With the Golden Rules of Gas? by Katherine Witt, The University of Queensland, et al. SPE 203208 Underbalanced Well Intervention to Re-Enter a Dead Well Changed the Future Dynamics of the Largest Gas Field in Pakistan—A Successful Pilot Project by Qasim Ashraf, Weatherford, et al.

Oxy-combustion Roadmap to Commercialization

Oxy-combustion is a form of low-carbon power generation, where the oxygen is separated from the air for combustion, yielding a flue gas consisting largely of CO2 and water, which in turn allows for relatively easy CO2 capture. Oxy-combustion comes in several forms, including atmospheric oxy-combustion, which can be done at conventional or higher flame temperatures, and a variety of pressurized oxy-combustion concepts. A special case of oxy-combustion is chemical looping combustion (CLC) where the air separation is done using an oxygen carrier, eliminating the need for an energy-intensive cryogenic air separation unit. Another special case, where the oxy-combustion is performed directly within the cycle, is the direct-fired supercritical CO2 (sCO2) power cycle (“Allam Cycle”). Oxy-combustion in its various forms has the potential to capture CO2 economically along with generating water and potentially other revenue streams. However, despite its potential, these technologies are not yet commercial, and their end states are hence unknown. Various oxy-combustion technologies are at different stages of maturity with multiple developers involved. Developing a roadmap that provides the status of the technology and its relative maturity level; reviews potential applications for oxy-combustion; assesses the performance, costs, and benefits; identifies the critical technical challenges that could limit successful commercial deployment; lays out a pathway to address those challenges; and includes a timeline required to reach commercial deployment, is necessary to get a better understanding of the potential of this novel technology. The Electric Power Research Institute, Inc. (EPRI) led a team that developed such an oxy-combustion roadmap, focusing on technologies that have established developers and are beyond lab-scale efforts. These technologies were: • Babcock & Wilcox Company’s (B&W) Coal Direct Chemical Looping: A CLC technology, which uses a form of oxy-combustion where the oxygen separation is done using an oxygen carrier, eliminating the need for an energy-intensive air separation. B&W utilizes iron-based oxygen carriers in its system. • Clean Energy Systems, Inc.’s (CES) Tri-Gen: One of several pressurized oxy-combustion processes that yield smaller components and allow the latent heat recovery of water at useful temperatures designed to improve efficiency. CES’ system uses platelet combustors and customized turbomachinery and heat exchangers with one of its initial targets focused on biomass. • General Electric’s (GE) Limestone Chemical Looping Combustion™: A CLC technology, GE uses a calcium-based oxygen carrier in its system. • Gas Technology Institute’s Oxy-Pressurized Fluidized-Bed Combustion: A pressurized oxy-combustion process that utilizes fluidized beds. • ITEA’s Flameless Pressurized Oxy-Combustion: A pressurized oxy-combustion process that utilizes flameless combustion. • Jupiter Oxygen Corporation’s High-Temperature Oxy-Combustion: A form of atmospheric oxy-combustion that employs high flame temperature through a modified burner designed to improve heat transfer. • Natural Resources Canada’s G2: A pressurized oxy-combustion process that is being designed to be coupled with an sCO2 power cycle. • NET Power, LLC / 8 Rivers, LLC Allam Cycles: Direct-fired, sCO2 power cycle that performs oxy-combustion in-situ, yielding a working fluid of CO2 and water that drives a turbine. NET Power, LLC is developing the natural gas version, while 8 Rivers, LLC is developing the coal-syngas version. • Washington University in St. Louis’ Staged, Pressurized Oxy-Combustion: A pressurized oxy-combustion process that stages the combustion using multiple boilers. The provides detailed information on each technology’s status and work done in the field, assess its maturity level, give data on its costs and performance (in some cases calculated independently by EPRI), review technology gaps that must be addressed, and present multiple timelines for when each is projected to be commercially ready―the first is a deliberate, conservative approach developed by EPRI, and the second was provided by the developer, which generally is an accelerated, more aggressive (and hence riskier) approach that seeks to shorten the timeline.

A Look Into What Fractures Really Look Like

Reports from the Hydraulic Fracturing Test Site offer a glimpse into what hydraulic fractures really look like. The featured attraction in the 13 technical papers presented over two mornings at the Unconventional Resources Technology Conference (URTeC) was 600 ft of rock fractured in late 2015 near wells in the upper and middle Wolfcamp. Those core samples spawned a mind-boggling array of observations about the rock, proppant, and natural and hydraulic fractures, and how they all interact. In the more than 2 years since the samples were gathered, the sections of core have been meticulously analyzed by teams of experts. More than 700 fractures were categorized based on whether each one was created by nature, hydraulic force, or the stress of drilling the slant well. And the majority of the 400 stages pumped were studied using tracers and/or monitored using advanced diagnostics. The density and distribution of the fractures were measured as the scientists worked to understand how natural and hydraulic fractures interact. The bits of sand, calcite, and drilling mud found in and around the rock were collected and sorted. Automated imaging and painstaking manual examinations were used to measure the size, shape, and translucence of each grain in order to identify and quantify the grains. The “incredible complexity” observed was “far beyond what current simulations can model and predict,” said Jordan Ciezobka, manager for research and development for the Gas Technology Institute (GTI), which managed the federal grant supporting test site 1 and is planning Hydraulic Fracturing Test Site 2 (URTeC 2937168). Ciezobka predicted that findings from the first Permian test site hosted by Laredo Petroleum in the Midland Basin would be studied for years to come. The public-private partnership is just beginning to deliver the delayed reports of what it learned from the $25-million research project. Federal funding for the project requires the partnership to ultimately disclose its results, with data releases beginning later this year. The lag time rewards companies that supported the project with a long first look. Cause and Effect? The completion engineers in the room those two mornings likely left wanting more. With one exception, the talks avoided mentions of the ultimate measure of what works—production. Instead, they challenged widely held mental images of fracturing. For one, fracture height is overrated. While microseismic testing indicated that fractures grew up about a 1,000 ft, the height of the propped fractures—the fractures most likely to produce oil and gas—was about 30 ft. Proppant distribution was sporadic. While there were thick fractures full of sand inside, a paper describing fracturing (URTeC 2902624) said that only three of them were found among hundreds of propped fractures. And all of those were found in the upper Wolfcamp. While the fractured lateral in the middle Wolfcamp was further from the slant well—135 ft vs. 90 ft from the nearest stage—the middle Wolfcamp core has a lot more proppant than the upper Wolf-camp core (URTeC 2902364).

Multiple regression and genetic programming for coal higher heating value estimation

ABSTRACTThe higher heating value (HHV) is an important characteristic for the determination of fuels quality. Nevertheless, its experimental measurement requires intricate technologies. In this work, the HHV of coal was predicted from ultimate composition using two methods: multiple regression and genetic programming. A dataset of 100 samples from literature was exploited (75% for training and 25% for testing). A comparative study was elaborated between the developed models and published ones in terms of correlation coefficient, root mean square error, and mean absolute percent error. The adopted models gave a good statistical performance.Abbreviations: C: Carbon; CC: Correlation coefficient; H: Hydrogen; HHV: Higher heating valueI; GT: Institute of gas technology; GP: Genetic programming; LHV: Lower heating value; MAPE: Mean absolute percent error; N: Nitrogen; O: Oxygen; RMSE: Root mean square error; S: sulfur; Wt: Weight percentage

Gas Technology Institute introduces a new biofuel production technology

Gas Technology Institute introduces a new biofuel production technology

Pressure Changes While Fracturing Add to Marcellus Well Production

Marcellus Well Production When it comes to hydraulic fracturing, steadiness may not be a virtue. That was the conclusion of a test to see if rapid pump rate variations would lead to greater production than conventionally fractured stages when the pressure was held steady. The stages in which rapid pump variations were used to create pressure pulses produced an average of 18% more gas than the ones with steady pumping pressure, said Jordan Ciezobka, manager of research and development for the Gas Technology Institute (GTI), which did the test in the Marcellus with WPX Energy. The project was funded by the Research Partnership to Secure Energy for America (RPSEA). Based on early results, this simple method may “increase production with no change in the water or sand pumped,” he said during a presentation at the recent SPE Hydraulic Fracturing Technology Conference. Since then, a version of the method with “more aggressive rate changes engineered specifically to accommodate the completion design in the Permian Basin” has been tested at a site where it was monitored using microseismic, production logging, and radioactive tracers. Ciezobka said results from that test are expected soon. The idea grew out of previous well monitoring research work in which microseismic testing detected a surge in seismic activity—an indication of more fracturing—whenever the pump speed had to be adjusted for operational reasons. Where that happened during fracturing, the well’s output was greater, Ciezobka said. So the thinking was, “Why not redesign the frac pump rate to get higher microseismic activity and get more production?,” he said. To test the theory, GTI set up a test where it used a variable pumping rate on 14 odd-numbered stages, and a steady rate on 13 even ones. The pump rate variations were done during the pad period, prior to pumping proppant. In a future test they plan to also vary the pressure while pumping proppant. Other than the rapid pump rate changes, which required some practice by the crew to get it right, the odd- and even-numbered stages showed no differences. But on average, the stages where the pumping rate varied produced 65.4 Mscf/D of gas, compared with 55.5 Mscf/D when the rate was constant, the paper said. The six highest production rates resulted from stages in which the pressure was varied. When production from the test well was compared to a nearby well that had been conventionally fractured with 50% more proppant, the variable rate well’s production had declined at a lesser rate. Another difference was surface treating pressure, which is an indication of the force required to pump fluid into the formation, which was lower when the pump pressure was varied. Analysis of the pressure decline rate after the pumps were shut down (water hammer diagnostic) indicated variable rate stages created, broader, more complex fractures, he said. JPT

Characterization of Marcellus Shale Flowback Water

Abstract Flowback water is the solution that returns to the surface following completion of the hydraulic fracturing process during natural gas extraction. This study examines and analyzes the constituents that make up flowback waters collected from various drilling sites in Marcellus shale formation in the states of Pennsylvania, New York, and West Virginia. Flowback sampling data were collected from four different sources (the Environmental Protection Agency, Gas Technology Institute; Pennsylvania Department of Environmental Protection; Bureau of Oil and Gas Management; and the New York Department of Environmental Conservation) and compiled into one database with a total of 35,000 entries. Descriptive statistical analysis revealed high concentrations of chlorinated solvents, disinfectants, dissolved metals, organic compounds, radionuclides, and total dissolved solids. A one-way ANOVA test revealed that over 60% of the constituents tested displayed significant differences (significance level=0.05) in mea...

Development of net energy ratio and emission factor for quad-generation pathways

The conversion of biomass to four different outputs via gasification is a renewable technology that could reduce the use of fossil fuels and greenhouse gas (GHG) emissions. This study investigates the energy aspects for a new concept of biomass based quad-generation plant producing power, heat, methanol and methane. Circulating fluidized bed gasifier and the gas technology institute (GTI) gasifier technologies are used for this quad-generation process. Two different biomass feedstocks are considered in this study. The net energy ratio for six different pathways having the range of between 1.3 and 7.2. The lowest limit corresponds to the wood chips-based power, heat, methanol and methane production pathway using GTI technology. Since more efficient alternatives exist for the generation of heat and electricity from biomass, it is argued that syngas is best used for methanol production. The aim of this study was to evaluate the energy performance, reduce GHG and acid rain precursor emission, and use of biomass for different outputs based on demand. Finally, a sensitivity analysis and a comparative study ar conducted for expected technological improvements and factors that could increase the energy performance.

Direct production of gasoline and diesel fuels from biomass via integrated hydropyrolysis and hydroconversion process—A techno‐economic analysis

A techno‐economic analysis (TEA) is performed to investigate the production of gasoline and diesel range hydrocarbon fuels by conversion of woody biomass via Gas Technology Institute (GTI)'s integrated hydropyrolysis plus hydroconversion (IH2) process. The processing capacity is 2000 dry metric tonnes (2205 dry US tons) of woody biomass per day. Major process areas include catalytic hydropyrolysis, catalytic hydroconversion, on‐site hydrogen production, feedstock handling and storage, hydrocarbon absorber, sour water stripper, hydrogen sulfide scrubber, distillation tower, and all other operations support utilities. The TEA incorporates applicable commercial technologies, process modeling using Aspen HYSYS software, equipment cost estimation, and discounted cash flow analysis. The resulting minimum fuel selling price is $1.64 per gallon (or $1.68 per gallon of gasoline equivalent) in 2007 US dollars. The process yields 79 gallons of liquid fuels per dry US ton of woody biomass feedstock, for an annual fuel production rate of 61 million gallons at 96% on‐stream time. The estimated total capital investment for an nth‐plant is $264 million. A sensitivity analysis captures uncertainties in costs and plant performance. Results from this TEA can serve as the baseline for future comparison and as a basis for comparing this process to other biomass‐to‐liquid fuel pathways. © 2013 American Institute of Chemical Engineers Environ Prog, 33: 609–617, 2014

Economic Evaluation of the UCSRP-HP Process in IGCC Applications

With financial assistance from the US Department of Energy and the Illinois Clean Coal Institute, Gas Technology Institute (GTI) has been working with the University of California, Berkeley, for further development of their UCSRP-HP (University of California Sulfur Recovery Process-High Pressure) technology. The key focus of the UCSRP-HP technology is integrated multi-contaminant removal of hydrogen sulfide (H2S), carbonyl sulfide (COS), ammonia (NH3), chlorides and heavy metals present in coal-derived syngas. The process has two major components: 1) removal of various trace components with a solvent (e.g., diethylene glycol or water) using a high-pressure scrubbing unit and 2) removal of H2S as sulfur via reaction with SO2 (in the presence of a solvent mixed a small quantity of a homogeneous catalyst) at 120?C to 150?C and at any syngas pressure. During this research, data critical to developing and evaluating UCSRP-HP technology for multi-contaminant removal from syngas derived from Illinois #6 coal were obtained. In this paper, we have presented key economic evaluations of the UCSRP-HP process, including potential integrations with other technology options for CO2 and hydrogen separations, for a nominal Illinois #6-coal-based 550-MWe Integrated Coal Gasification Combined Cycle (IGCC) facility with CO2 capture and sequestration. GTI is exploring various options to demonstrate this technology in a pilot plant using actual syngas from a coal gasifier.

Demonstrating Fuel Flexibility in Commercial Operation

Synthesis Energy Systems Inc. (SES) enables its customers to advance gasification projects through commercial scale feedstock testing at its commercial scale coal to syngas facility in Zhao Zhuang City (ZZ Plant), Shandong Province, China. These tests help customers affirm individual project economic viability and reduce technology risk. Included in these test campaigns have been one and two-week long continuous operations at varying loads and on widely-varying feedstock such as Chinese Inner Mongolian lignite, Chinese sub-bituminous high ash (and high friable) coal, and Aus- tralian Queensland high ash sub-bituminous coal. Through these campaigns, SES has progressed one project into the detailed engineering and construction phase and one project into the feasibility study phase. SES believes that the abi- lity to perform these commercial scale campaigns without interruption of operation is unique to SES. The ZZ Plant, which sells clean syngas to a neighboring methanol facility, has been in operation since early 2008 on a design coal of high ash middlings (washery wastes) from ROM bituminous coal (30% - 40% wt ash). SES has made significant im-provements to the design, operation, and efficiency of the ZZ Plant and U-GAS technology that is licensed from Gas Technology Institute (GTI). Included in these is the Fines Management System (FMS), which has demonstrated overall carbon conversion of greater than 98%. The ZZ Plant consistently demonstrates fuel flexibility and greater than 98% availability, 98% carbon conversion, and 80% cold gas efficiency.

A comparison of prairie cordgrass and switchgrass as a biomass for syngas production

A computational simulation of the gasification of prairie cordgrass (PCG) and switchgrass is conducted to assess their suitability as gasifying fuels in the production of syngas. An Institute of Gas Technology (IGT) bubbling fluidized gasifier is modeled using a commercial code that previously has been documented to simulate this particular reactor exceptionally well. Despite the similarities in the ultimate analyses of the PCG and switchgrass with regards to the amounts of carbon, hydrogen, and oxygen, the composition of the syngas is found to differ notably between the two grasses. The gasification of switchgrass results in significantly higher H2 than that of PCG. The syngas produced from switchgrass also has greater amounts of CO than PCG, but results in very small amounts of methane when compared to PCG. The H2/CO molar ratio of the syngas produced, which is a very important design parameter in the Fischer–Tropsch process, is greater for switchgrass than prairie cordgrass.

Submerged Combustion Melting of Glass

Advances in tank melter, refractory, controls, and heat source technology have paralleled progress in glass chemistry, quality, and production scale for decades. These same advances have also led to a revival of the 75‐year‐old concept of bottom heating for glass melting. To create high‐intensity heat transfer and rapid melt homogenization, bottom heating, or submerged combustion melting, uses forced convection and direct contact heat transfer. The work of European, American, and Ukranian scientists has demonstrated that bottom heating offers energy savings, emissions reductions, and cost savings relative to conventional melting. Recent work by the Gas Technology Institute of the United States, in partnership with a consortium of glass companies, has advanced the bottom heating technology for a number of glass products to the brink of commercialization. With ongoing work a practical, rapid refining process could be developed to enable bottom melting as an alternative melting approach for a broad range of commercial glasses.

Screening Method To Select Horizontal-Well Refracturing Candidates in Shale-Gas Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144032, ’A Novel Screening Method for Selection of Horizontal- Refracturing Candidates in Shale-Gas Reservoirs,’ by Shekhar Sinha, SPE, and Hariharan Ramakrishnan, SPE, Schlumberger, prepared for the 2011 SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 14-16 June. The paper has not been peer reviewed. A method was developed to screen potential horizontal-well-refracturing candidates rapidly by use of production performance and completion-data analysis. Integration of initial hydraulic-fracture-completion details augments the process and helps screen understimulated wells in different production classes. To accomplish this screening, an index called a “completion index” was defined after analysis of the completion parameters, production behavior, and their interrelationship. Introduction Restimulation of existing wells represents a vast unexploited resource in tight formations. In 1996, the Gas Research Institute, now the Gas Technology Institute (GTI), investigated the potential for natural-gas-production enhancement by use of restimulation in the USA (onshore, lower 48 states). The report indicated that the potential was substantial (more than 1 Tcf of reserves in 5 years), particularly in the tight gas sands of the Rocky Mountain, midcontinent, and south Texas regions. The study also stated that 85% of the restimulation potential for a field exists in 15% of the wells. Hence, the key to any successful restimulation program is being able to identify that 15 to 20% of the total well population that represents high potential for restimulation success. However, it also was determined that industry’s current experience with restimulation is mixed, and that considerable effort is required in candidate selection, problem diagnosis, and treatment design/implementation for a program to be successful. The GTI study investigated three main classes of candidate-selection methods: production-performance comparisons, pattern-recognition-technology/virtual-intelligence methods, and production-type-curve matching. The study concluded that although virtual-intelligence methods were relatively better compared to production type curves, no universal method exists that enables selecting restimulation candidates across different geologic settings. Use of production statistics alone was the least-effective process.

Development of net energy ratio and emission factor for biohydrogen production pathways

This study investigates the energy and environmental aspects of producing biohydrogen for bitumen upgrading from a life cycle perspective. Three technologies are studied for biohydrogen production; these include the Battelle Columbus Laboratory (BCL) gasifier, the Gas Technology Institute (GTI) gasifier, and fast pyrolysis. Three different biomass feedstocks are considered including forest residue (FR), whole forest (WF), and agricultural residue (AR). The fast pyrolysis pathway includes two cases: truck transport of bio-oil and pipeline transport of bio-oil. The net energy ratios (NERs) for nine biohydrogen pathways lie in the range of 1.3–9.3. The maximum NER (9.3) is for the FR-based pathway using GTI technology. The GHG emissions lie in the range of 1.20–8.1kgCO2eq/kg H2. The lowest limit corresponds to the FR-based biohydrogen production pathway using GTI technology. This study also analyzes the intensities for acid rain precursor and ground level ozone precursor.

Contributors

Contributors

Evaluation of thermal characteristics of oscillating combustion

In view of the economy and environmental impacts of the energy utilization, most of the heat transfer industries such as steel mills, glass plants and forging shops, foundry process and furnaces are focusing on energy efficient strategies and implementing new technologies. Gas Technology Institute (GTI) and Air Liquide Chicago Research Centre (ALCRC) have applied Oscillating Combustion Technology (OCT) on high temperature forged furnaces and reheat furnace for melting steel. The oscillating combustion requires a new hardware to incorporate on the fuel flow ahead of the burner. Solid State Proportionate (SSP) valves were used to create oscillations in the fuel flow. Natural gas was used as fuel and the technology was applied with air-gas, oxygen-gas, and excess level of air during the oscillating combustion. The present work deals with the implementation of OCT on liquid fuels at ambient conditions for melting aluminum metal in a fuel-fired crucible furnace which is of importance to foundry. Also, carrying out a study over the enhanced performance characteristics of oscillating combustion and comparing its thermal effects with those of the conventional combustion mode. The oscillating device, developed by the author, unlike other oscillating valves used earlier is a cam operated electro mechanical valve cause oscillations on the fuel flow. Experiments were conducted at varying air-fuel ratio, aluminum stocks, frequency and amplitude of the oscillating valve. The results when compared to the conventional combustion led to low fuel and specific energy consumption, enhanced heat transfer rate, increased furnace efficiency with visibly low volumes of flue gases with reduced emissions. The increased heat transfer rate and furnace efficiency was found to be in agreement with the results of GTI and ALCRC experiments. The reasons for such improvements in performance characteristics were verified by conducting experiments in the furnace by measuring the temperature distribution at designated point and calculating the heat transfer rate both for conventional and oscillating combustion mode. The analyses presented in this paper are for two levels of air-fuel ratios above and below the stoichiometric ratio, three different loads at 100 & 200amplitude and 5 & 10Hz frequency of oscillating valve. Key words: Furnace efficiency, fuel fired furnace, heat transfer, oscillating combustion, specific energy consumption

PRISE Validates Resource Triangle Concept

Summary As conventional gas (CG) resources are depleted, unconventional gas (UG) resources (gas from tight sands, coalbeds, and shale) are becoming increasingly important to US and world energy supply. The volume of UG resources is generally unknown in most basins outside North America. However, in many mature North American basins, UG resources have been produced for decades, and resources and reserves are well characterized. The objective of this work was to determine the quantitative relations between known conventional and unconventional hydrocarbon resources in mature North American basins, with the ultimate goal of using these relations to estimate UG resources in frontier basins outside North America. We used assessments by the US Geological Survey (USGS), Potential Gas Committee (PGC), Energy Information Administration (EIA), National Petroleum Council (NPC), and Gas Technology Institute (GTI) to evaluate relations among hydrocarbon-resource types in the Appalachian, Black Warrior, Greater Green River, Illinois, San Juan, Uinta-Piceance, and Wind River basins. We chose these seven basins for initial analysis of relations between CG and UG resources because they are mature basins for both conventional and unconventional oil and gas production. To conduct this analysis, we wrote a computer program that we call Petroleum Resources Investigation Summary and Evaluation (PRISE). Input data for PRISE, obtained from published data sources and resource assessments, were values of technically recoverable resources, consisting of the following resource categories: (1) cumulative production, (2) proved reserves, (3) probable and possible reserves and contingent resources (PPC), and (4) prospective resources. We then analyzed these data in each of the seven basins to assess the relationship between conventional- and unconventional-resource volumes. For the seven basins studied, we found that approximately 10-20% of the total recoverable hydrocarbon resources are conventional oil (CO) and CG, whereas 80-90% of the recoverable hydrocarbons are UG resources. We suggest that the results of this study may be used to estimate recoverable resources from UG reservoirs in frontier basins worldwide, where CO and CG resources are known but UG resources have not been evaluated.