Current Natural Gas Prices Research Articles

Energetic, Exergetic, and Techno-Economic Analysis of A Bioenergy with Carbon Capture and Utilization Process via Integrated Torrefaction–CLC–Methanation

Bioenergy with carbon capture and storage (BECCS) or utilization (BECCU) allows net zero or negative carbon emissions and can be a breakthrough technology for climate change mitigation. This work consists of an energetic, exergetic, and economic analysis of an integrated process based on chemical looping combustion of solar-torrefied agro-industrial residues, followed by methanation of the concentrated CO2 stream with green H2. Four agro-industrial residues and four Italian site locations are considered. Depending on the considered biomass, the integrated plant processes about 18–93 kg h−1 of raw biomass and produces 55–70 t y−1 of synthetic methane. Global exergetic efficiencies ranged within 45–60% and 67–77% when neglecting and considering, respectively, the valorization of torgas. Sugar beet pulp and grape marc required a non-negligible input exergy flow for the torrefaction, due to the high moisture content of the raw biomasses. However, for these biomasses, the water released during drying/torrefaction and CO2 methanation could be recycled to the electrolyzer to eliminate external water consumption, thus allowing for a more sustainable use of water resources. For olive stones and hemp hurd, this water recycling brings, instead, a reduction of approximately 65% in water needs. A round-trip electric efficiency of 28% was estimated assuming an electric conversion efficiency of 40%. According to the economic analysis, the total plant costs ranged within 3–5 M€ depending on the biomass and site location considered. The levelized cost of methane (LCOM) ranged within 4.3–8.9 € kgCH4−1 but, if implementing strategies to avoid the use of a large temporary H2 storage vessel, can be decreased to 2.6–5.3 € kgCH4−1. Lower values are obtained when considering hemp hurd and grape marc as raw biomasses, and when locating the PV field in the south of Italy. Even in the best scenario, values of LCOM are out of the market if compared to current natural gas prices, but they might become competitive with the introduction of a carbon tax or through government incentives for the purchase of the PV field and/or electrolyzer.

Performance evaluation and economic feasibility of a PAFC-based multi-energy hub system in South Korea

In this study, a MW-scale fuel-cell-based multi-energy hub system is simulated to maximize microgrid flexibility. The system was designed to deliver electricity, heat, and H2 with a high energy efficiency, which can be realized through the integration of the exothermic phosphoric acid fuel cell and endothermic turboexpander generator modules. To extract additional useful work during the depressurization process in the natural gas supply chain, this multi-energy system is currently under construction on a pilot basis in South Korea. Based on a natural gas flow rate of 28,000kg/h, we analyze the performance of the system and its economic effects under different load demands and operating conditions. The system simulation results show that the total electrical power generated by the turboexpander generator and phosphoric acid fuel cell modules is approximately 3.395–3.539MWe, while the H2 yield is 19.94–40.00kg/h. In addition, an economic assessment of the multi-energy hub system is conducted based on the current natural gas, electricity, and H2 prices in South Korea. Assuming a life span of 20 years for the turboexpander generator and phosphoric acid fuel cell modules, the payback period is estimated to be between 7.09 and 10.05 years.

Designing residential energy systems considering prospective costs and life cycle GHG emissions

Novel energy technologies are typically associated with large investments and environmental impacts generated in the construction phase. In this work, we present a systematic approach to optimally design residential energy systems, considering (prospective) costs and life cycle greenhouse gas (GHG) emissions of a large set of low-carbon energy technologies and sources. To achieve this, an optimization problem has been formulated and is tested on several scenarios considering climate-specific heat and electricity demand as well as scenario-specific conditions, such as the flexibility of grid electricity tariffs and associated GHG intensities. With GHG-intensive grid electricity supply and flexible energy tariffs, we recommend to implement policy measures to encourage the investment in residential solar PV-coupled batteries and heat pumps, especially in the near future. The inclusion of environmental impacts generated from the production of energy technologies cannot be neglected; they should be considered during the design phase of residential energy systems. Current high electricity and natural gas prices result in the installation of low-carbon energy system components. This implies that battery systems are already an effective option to reduce the reliance on carbon-intensive and expensive energy supply. And lastly, the large-scale deployment of residential lithium-ion batteries might be limited by global lithium production. This implies that energy system designers should consider alternative electricity storage technologies in their energy technology portfolio.

Bottom-Up Estimates of the Cost of Supplying High-Temperature Industrial Process Heat from Intermittent Renewable Electricity and Thermal Energy Storage in Australia

We report the upper and lower bounds for the levelized cost of high-temperature industrial process heat, supplied from electricity generated with solar-photovoltaic (PV) and wind turbines in combination with either thermal or electric battery storage using hourly typical meteorological year (TMY) data, in systems sized to supply between 80% and 100% of continuous thermal demand at a site in the northern part of Western Australia. The system is chosen to supply high-temperature air as the heat transfer media at temperatures of 1000 °C, which is a typical temperature for an alumina or a lime calcination plant. A simplified model of the electrical energy plant has been developed using performance characteristics of real PV and wind systems and TMY data of renewable energy resources. This was used to simulate a large sample of possible system configurations and find the optimal combination of the renewable resources and storage systems, sized to provide renewable shares (RES) of between 80% and 100% of the yearly demand. This allowed the upper and lower bounds to be determined for the cost of heat based on two scenarios in which the excess energy is either dumped (upper bound) or exported to the electricity grid (lower bound) at the average generating cost. The lower bound of the levelized cost of energy (LCOEL), which occurs for the system employing thermal storage, was estimated to range from USD 10/GJ to USD 24/GJ for RES from 80 to 100%. The corresponding upper bound (LCOEU), also estimated for the system using thermal storage, are between USD 16/GJ and USD 31/GJ, for RES between 80% and 100%. The utilization of electric battery storage instead of thermal storage was found to increase the LCOE values by a factor of two to four depending on the share of renewable energy. Compared with current Australian natural gas cost, none of the systems assessed configurations is economical without either a cost for CO2 emissions or a premium for low-carbon products. The estimated cost for CO2 emission that is needed to reach parity with current natural gas prices in Australia is also presented.

Techno-economical modelling of a power-to-gas system for plant configuration evaluation in a local context

Decarbonisation of the European energy networks is critical to meet Commission targets in the coming decades. The presented study aims to contribute to this by analysing one of the proposed solutions: power-to-gas. A techno-economic model is created for the purposes of evaluating specific projects on their feasibility in terms of local constraints and opportunities, using a current project as a template for model generation and analysing different possible configurations in 8 operational scenarios. Five metrics were used for scenario analysis: levelized cost of methane, minimum selling price, operational hours, hydrogen tank size and capital cost. The results from the analysis indicate that, in terms of the stated project, synthetic natural gas production and grid injection along with on-site mobility applications provide the best economical result. However, selling prices of synthetic natural gas obtained are one magnitude higher than current natural gas prices, indicating government support is required for further development. Future projections of electrolyser efficiency and equipment capital costs will greatly reduce production costs, giving promise for feasible business cases in the coming years.

An Integrated Assisted History Matching and Embedded Discrete Fracture Model Workflow for Well Spacing Optimization in Shale Gas Reservoirs

Abstract Optimum well spacing is an essential element for the economic development of shale gas reservoirs. We present an integrated assisted history matching (AHM) and embedded discrete fracture model (EDFM) workflow for well spacing optimization by considering multiple uncertainty realizations and economic analysis. This workflow is applied in shale gas reservoirs of the Sichuan Basin in China. First, we applied the AHM to calibrate ten matrices and fracture uncertain parameters using a real shale gas well, including matrix permeability, matrix porosity, three relative permeability parameters, fracture height, fracture half-length, fracture width, fracture conductivity, and fracture water saturation. There are 71 history matching solutions obtained to quantify their posterior distributions. Integrating these uncertainty realizations with five-well spacing scenarios, which are 517 ft, 620 ft, 775 ft, 1030 ft, and 1550 ft, we generated 355 cases to perform production simulations using the EDFM method coupled with a reservoir simulator. Then, P10, P50, and P90 values of gas estimated ultimate recovery (EUR) for different well spacing scenarios were determined. In addition, the degradation of EUR with and without well interference was analyzed. Next, we calculated the NPVs of all simulation cases and trained the K-nearest neighbors (KNN) proxy, which describes the relationship between the net pressure value (NPV) and all uncertain matrix and fracture parameters and varying well spacing. After that, the KNN proxy was used to maximize the NPV under the current operation cost and natural gas price. Finally, the maximum NPV of 3 million USD with well spacing of 766 ft was determined.

H2 Economy: Hype, Horizon, or Here?

Clean-burning hydrogen (H2) - and scenarios for a future economy powered by it - is big news at the moment. This is no surprise, given the current environment of low demand for oil, growing unease over greenhouse gas emissions, and projections that post-pandemic stimulus measures could do for hydrogen what stimulus measures after the 2008 financial crisis did for solar power. Oil and gas majors have spent tens of millions of dollars on pilot projects, as have other industrial giants. Germany, which has allocated $10 billion to its nascent hydrogen industry, is one of a growing number of governments whose spending to satisfy climate commitments while restarting their economies could provide a major funding kickstart. But for the moment, most analysts agree that the future for a hydrogen economy is still uncertain and that the biggest obstacles to scaling will be costs, technology scaleup, and policy. H2 101 - From Feedstock to Fuel Hydrogen is the most abundant chemical substance in the universe, constituting roughly 75% of all mass. Today approximately 3% of global energy consumption is used to produce hydrogen, at a rate of more than 110 million tons per year, according to BloombergNEF (BNEF). So, hydrogen production is already a large and thriving industry. Yet, according to the Hydrogen Council, only 0.002% of currently produced hydrogen is used as fuel. Some 90% is used for ammonia production, petroleum refining, and methanol production. DNV GL, in a recent report on hydrogen as an energy carrier, describes hydrogen as a unique zero-emission energy carrier that can be converted to electrical energy in a fuel cell two to three times more efficiently than in a combustion engine. Hydrogen as an energy carrier can exist in a variety of forms and can be converted from one form to another, while energy sources such as oil and gas are the original resource from which the energy carrier is produced. Hydrogen can be used as fuel for mobility and heating in buildings; to decarbonize industrial processes; and as price support and storage for excess electricity during periods when production output from renewables alone exceeds demand. BNEF reports in its Hydrogen Economy Outlook that deploying clean hydrogen in the coming decades could reduce up to 34% of global greenhouse gas emissions from fossil fuels and industry at manageable cost. Renewable hydrogen could be produced for $0.70 to $1.60/kg in most parts of the world before 2050 - the equivalent of gas priced at $6-$12/MMBtu, making it competitive with current natural gas prices in Brazil, China, India, Germany, and Scandinavia on an energy-equivalent basis.

Offshore conversion of wind power to gaseous fuels: Feasibility study in a depleted gas field

A proof-of-concept study is presented of a Power-to-Gas system that is located fully offshore. This paper analyses how such a system would perform if based at the depleted Kinsale Gas Field in the Celtic Sea Basin off the south coast of Ireland. An offshore wind farm is proposed as the power source for the system. Several conversion technologies are examined in detail in terms of resource efficiency, technological maturity, and platform area footprint, the aim being to ascertain their overall applicability to an offshore Power-to-Gas system. The technologies include proton exchange membrane electrolysers for electrolysis of water to release H2. Bipolar membrane electro-dialysis and electronic cation exchange module processes are also considered for the extraction of CO2 from seawater. These technologies provide the feedstock for the Sabatier process for the production of CH4 from H2 and CO2. Simulations of the end-to-end systems were carried out using Simulink, and it was found that the conversion of offshore wind power to hydrogen or methane is a technically feasible option. Hydrogen production is much closer to market viability than methane production, but production costs are too high and conversion efficiencies too low in both cases with present-day technology to be competitive with current wholesale natural gas prices.

Techno‐economic performance of sustainable international bio‐SNG production and supply chains on short and longer term

AbstractSynthetic natural gas (SNG) derived from biomass gasification is a potential transport fuel and natural gas substitute. Using the Netherlands as a case study, this paper evaluates the most economic and environmentally optimal supply chain for the production of biomass based SNG (so‐called bio‐SNG) for different biomass production regions and location of final conversion facilities, with final delivery of compressed natural gas at refueling stations servicing the transport sector. At a scale of 100 MWth, in, delivered bioSNG costs range from 18.6 to 25.9$/GJdelivered CNGwhile energy efficiency ranges from 46.8–61.9%. If production capacities are scaled up to 1000 MWth, in, SNG costs decrease by about 30% to 12.6–17.4$ GJdelivered CNG−1. BioSNG production in Ukraine and transportation of the gas by pipeline to the Netherlands results in the lowest delivered cost in all cases and the highest energy efficiency pathway (61.9%). This is mainly due to low pipeline transport costs and energy losses compared to long‐distance Liquefied Natural Gas (LNG) transport. However, synthetic natural gas production from torrefied pellets (TOPs) results in the lowest GHG emissions (17 kg CO2e GJCNG−1) while the Ukraine routes results in 25 kg CO2e GJCNG−1. Production costs at 100 MWthare higher than the current natural gas price range, but lower than the oil prices and biodiesel prices. BioSNG costs could converge with natural gas market prices in the coming decades, estimated to be 18.2$ GJ−1. At 1000 MWth, bioSNG becomes competitive with natural gas (especially if attractive CO2prices are considered) and very competitive with oil and biodiesel. It is clear that scaling of SNG production to the GWthscale is key to cost reduction and could result in competitive SNG costs. For regions like Brazil, it is more cost‐effective to densify biomass into pellets or TOPS and undertake final conversion near the import harbor. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd

Financial viability of PCMs in countries with low energy cost: A case study of different climates in Iran

Properties of desirable weight, latent heat capacity, and energy storage capability of phase change materials (PCMs) have led to extensive use of these materials in the building industry as productive thermal mass. This study investigated the feasibility of the utilization of PCMs through numerical simulations in residential buildings located in different Iranian climates in Tehran, Tabriz, Yazd, and Bandar Abbas. In so doing, the optimal PCM for each city was selected based on its impact on annual energy consumption, and then its effects on the indoor temperature and thermal load of the model in the hottest and coldest months of the year were examined. The results showed that the use of PCMs does not lead to significant energy conservation in the hot and humid climate of Bandar Abbas compared with other climates. In the second part of the study, the economic feasibility of PCMs and the payback period of such investment were investigated based on the current local electricity and natural gas prices. It was found that although the use of PCMs leads to significant energy conservation in most of these climates, with the current prices of energy and PCMs in Iran, the use of these materials will not be cost-effective, as the return periods for such investment in Tehran, Tabriz, Yazd, and Bandar Abbas will be 42, 179, 102, and 114 years, respectively.

How much wind and solar are needed to realize emissions benefits from storage?

Environmental outcomes from energy storage depend on its usage patterns, the existing generation fleet, and fossil fuel prices. This work models the deployment of large, non-marginal quantities of energy storage and wind and solar power to determine their combined effects on grid system emissions. Two different grid environments are analyzed: a coal-heavy grid (Midcontinent ISO) and non-coal grid (New York ISO). An iterative dispatch model is used that operates storage to maximize income, considering that this operation can influence wholesale energy prices. With current low natural gas prices ($2.6 per MMBtu), adding storage slightly reduces carbon emissions in New York, while increasing them in the Midcontinent ISO (MISO). Storage increases carbon emissions when it enables a high emissions generator, such as a coal plant, to substitute for a cleaner plant, such as natural gas. We estimate that adding storage operated to maximize revenue in the MISO region will not be carbon neutral until wind or solar power reach around 18% of the generation capacity. Different operation patterns for storage could realize higher carbon reductions. For example, a carbon price on emissions from generators would shift operation to make energy storage carbon neutral even with current wind and solar capacities. Sensitivity analysis shows that a higher natural gas price ($5 per MMBtu) yields much higher storage-induced carbon emissions in both NYISO and MISO and storage in MISO will not be carbon neutral unless 35% of total generation capacity is from wind/solar. This illustrates that low cost, efficient natural gas generation is important to realize emissions reductions with storage under economic arbitrage.

Can the US shale revolution be duplicated in continental Europe? An economic analysis of European shale gas resources

Over the past decade, the rapid increase in shale gas and shale oil production in the United States has profoundly changed energy markets in North America, and has led to a significant decrease in American natural gas prices. The possible existence of large shale deposits in continental Europe, mainly in France, Denmark, the Netherlands and Germany, has fostered speculation on whether the U.S. shale revolution could be duplicated in Europe. However, a number of uncertainties, notably geological, technological, regulatory, and relating to public acceptance make this possibility unclear. We present a techno-economic model of shale gas production amenable to direct estimation on historical production data to analyze the main determinants of the profitability of shale wells and plays. We contribute an in-depth analysis of an extensive production dataset covering 40,000 wells and accounting for nearly 90% of shale gas production in the six main plays of the continental United States from 2004 to 2014. We combine this analysis with a discussion of the main differences between the American and European contexts to calibrate our model and conduct Monte-Carlo simulations. This enables us to estimate the distribution of breakeven prices for shale gas extraction in continental Europe. We find a median gross breakeven price before taxes and royalties of $10.1 per MMBtu. This would make extraction unprofitable in Europe in the current natural gas price environment, with <47% of the well distribution reaching breakeven at the mean 2011–2016 price. Sensitivity analysis reveals that the breakeven price is most sensitive to initial production rate, drilling and completion costs, and decline rates. We also find that the economic outlook would be slightly better if the productivity of European shale gas plays was comparable to that of U.S. plays of similar depth, but not significantly so. We conclude that under assumptions calibrated on existing shale gas production data, it is unlikely that the U.S. shale revolution can be duplicated in continental Europe.

Energy management and design optimization for a series-parallel PHEV city bus

Series-parallel PHEV city buses combine the advantages of series and parallel configurations and have been used in China. However, the design and energy management of series-parallel PHEV city buses based on Chinese driving conditions still need to be investigated. In this paper, an equivalent consumption minimization strategy is provided to optimize energy management for series-parallel PHEV city buses, and the process of the equivalent consumption minimization strategy for series-parallel is presented in this paper. Compared with the validated rule-based energy control strategy, ECMS shows a fuel economy improvement of 8.2 % in the CBCD (Chinese Bus Driving Cycle). Based on the optimal energy management, a design for a generator motor in the series-parallel configuration has been processed. The fuel consumption has been shown to decrease, with an increase in generator power, because the system with the higher generator power can work at a higher efficiency in the series mode and operate the engine in the high efficiency area in the parallel mode. Besides, in terms of costof- ownership for a PHEV bus for lifetime of 8 years, although the high generator power will lead to high purchase cost for series-parallel PHEV bus, a series-parallel PHEV city bus with a generator of 100 kW maximum power will still show small advantage in cost-of-ownership, based on current motor price and natural gas price.

Fear, Greed and Efficient Market- Evidence from News Sentiment Analytics

I analyze the relationship between natural gas prices and the news sentiment data obtained from the Thomson Reuters News Analytics system. I conduct studies on two different horizons: the daily basis study and the intraday basis study. For the daily study, our results show that any correlation we observed between the daily news sentiments and the daily returns of natural gas can be largely attributed to the news relevant to historical natural gas price movements, or “price-related news”. This discovery also emphasizes the failure of price-related news sentiment in predicting future natural gas returns, which in turn supports the weak form of the Efficient Market Hypothesis. For the intraday study, I label news items with high positive and negative sentiment scores as extreme positive news and extreme negative news. I then conduct event study to analyze the price-related extreme new items’ impact on natural gas prices. I found natural gas has two different types of price movement in reaction to price-related extreme negative news. I also show that these two types of abnormal return can serve as a signal for the investors’ sentiment. I made a connection between these investors’ sentiment signals and the S&P 500 index to show that these signals can be used to predict long term S&P 500 returns. The capability of these signals to predict the future S&P 500 index and the fact that the signals are derived solely from past price reactions and past price-related news items suggests that the current natural gas prices and equity market prices do not fully reflect all the information related to historical prices.

What Is All This Talk About Emissions?

Beyond the Headlines Emissions are in the air and in the headlines every day. Whether the discussion is on human health impacts of pollution, greenhouse gas (GHG) emissions and their impact on climate change, or the misleading performance of a diesel engine, the bottom line is there is a global focus on emissions. Emission discussions are also in the forefront of the oil and gas industry. In 2012, the US Environmental Protection Agency (EPA) mandated new emission rules for our industry dealing with volatile organic hydrocarbons (VOCs), hazardous air pollutants (HAPs), and, most recently, methane. On 18 August, the agency proposed additional measures (EPA 2015) that supplement the earlier regulations and that “together will help combat climate change, reduce air pollution that harms public health, and provide greater certainty about Clean Air Act permitting requirements for the oil and natural gas industry.” The rules have set limits on emissions. If they cannot be captured, the emissions must be combusted at a 95% destruction efficiency at a minimum. Destruction efficiency is not as extensive a measure of performance as combustion efficiency; however, the move to performance-based legislation is a positive one and will most certainly lead to improved air quality and a healthier relationship with communities in close proximity to oil and gas development. Within the US, various states have or are in the process of enacting legislation specific to their local situation, on the proviso that their requirements are not weaker than the federal rules. In Colorado, for example, much of the industry activity occurs in the vicinity of communities. The state regulator is moving toward mandating de vices that not only combust efficiently, but also fully enclose the combustion to eliminate the visibility of the flare. It is also spot inspecting facilities with special cameras that detect uncombusted hydrocarbons, which are a clear indicator of poor performance. Companies that are emitting uncombusted hydrocarbons will be subject to considerable fines. North Dakota has put a rule in place that the industry must find an acceptable method of using a significant, measurable portion of a well’s associated gas, or oil production from that well will be capped. There are other situations in which the new EPA requirements, combined with state rules, will result in improved operations. The existing 2012 EPA legislation covered natural gas wellsites, production gathering and boosting stations, natural gas processing plants, and natural gas compressor stations. The proposed EPA legislation requires the reductions of methane and VOC emissions from hydraulically fractured oil wells and extends the emission reduction targets downstream covering equipment in the natural gas transmission segment. In view of this regulation, two questions are central to the emissions issue. 1. Is there a technology that can deliver results cost-effectively and address the community concerns about emissions? 2. Is it possible to comply with the new rules in the current low oil and natural gas price environment?

Technology, Efficiency, and Midstream Growth Drive Long-Term Future for Marcellus, Utica

While the collapse in oil price is reshaping opinions about the North American shale revolution and the outlook for oil producers, natural gas producers in the United States are in a somewhat different position. They have contended with low prices since late 2008 and yet remain in a domestic market with substantial long-term growth potential while soon anticipating access to higher-priced global export markets as low-cost producers. No producing area is more invested in the future of US natural gas than the Marcellus Shale that stretches across much of the Appalachian Basin, with development activities concentrated in Pennsylvania and West Virginia. The Marcellus produces approximately 20% of US gas supplies. And beneath the formation lies the highly prospective Utica Shale, in which drilling and production, especially in eastern Ohio, are getting under way. The near-term outlook is anything but rosy at current natural gas prices ranging below USD 3/Mcf at the wellhead. However, the producers generally have plenty of experience with low prices. With a constant focus on technological innovation and increased efficiency, and the continuing expansion of the midstream network to create more marketing options, the gas industry in the Marcellus and Utica is laying the groundwork for a better future for many decades to come. “I think we’re just really in the beginning of realizing how much potential is actually in the Marcellus and the Utica,” said Jeffrey Daniels, director of the Utica Shale Energy and Environment Laboratory at Ohio State University. Daniels is a professor of Earth sciences at the university and a member of the Ohio Oil &amp; Gas Commission. According to the most recent estimate by the US Energy Information Administration, the Marcellus holds 354 Tcf of proved gas reserves. However, technically recoverable gas reserves, an assessment that does not consider gas prices, have been estimated at 480 Tcf by Terry Engelder, a geosciences professor at Pennsylvania State University.

The future of natural gas as a fuel in marine gas turbine for LNG carriers

This paper discusses the suitability of using natural gas as a fuel for marine gas turbine electric propulsion (DFGE), utilizing natural boil-off gas and forced boil-off gas, as well as investigating its economical and environmental benefits over other propulsion options. The benchmark ship chosen for this study has a capacity of 150,000 m3 and is powered by conventional steam propulsion. For this purpose a spreadsheet model was developed to determine the liquefied natural gas carrier operating costs for different propulsion options. This is in addition to a sensitivity analysis to study the effect of varying range, heavy fuel oil (HFO) and natural gas prices on ship operating cost. Recently, about 40% of the new orders shifted to slow speed diesel engines with re-liquefaction plant and dual fuel diesel electric propulsion. To date, marine gas turbines are not used in liquefied natural gas carriers. It was found that using natural gas as a fuel with the proposed marine gas turbine cycle at current HFO and natural gas prices provides the highest cost saving for a distance less than 4000 nautical miles (NM). With the expected changes in fuel prices, the proposed cycle achieves cost saving of 3% per round trip, and this saving is directly proportional to increasing fuel prices, compared to other options.

A decision support model for combined heat and power economic evaluation

Many European states support Combined Heat and Power (CHP) investments and provide better selling tariffs for the electricity produced. In this paper, a model was developed that can help energy planning and decision-making for CHP investments in an unstable energy market. The model uses as variables state subsidies, natural gas and electricity selling price. Five different scenarios from Greek economic reality had been used in order to evaluate their economic viability and the investment risk. Finally, a sensitivity analysis was carried out, having as variables the natural gas price and the State subsidy. The sensitivity analysis of the natural gas price showed that although profits decrease as natural gas price increases, the investment remains viable for almost twice the current natural gas price. This means that small fluctuations of natural gas price do not affect the investment to a crucial degree.

Shale Gas Equity Strategy in the US

Clients recently approach us for equity strategy related to the shale gas industry. On one hand, shale gas is viewed as “the biggest energy innovation of the decade” and can significantly expand the supply for the US and the whole world. One the other hand, the current depressed natural gas price and still uncertain or pessimistic economic recovery cast doubt into the demand and the profitability of shale gas producers. These two aspects at odd challenge many clients’ investment decision on equities. In this analysis we illustrate our views that the shale gas market is posed to grow, and that natural gas price is likely to hike although uncertainty and volatility still exist. Market still values shale gas producers, and currently weak natural gas price might provide an opportunity to long those shale gas equities.

Performance research of a micro-CCHP system with adsorption chiller

This paper describes a new micro-combined cooling, heating and power (CCHP) system, which is especially suitable for domestic and light commercial applications. It mainly consists of a natural gas-fired internal combustion engine, a silica gel-water adsorption chiller and other heat recovery units. In order to study the energy efficiency and economic feasibility, an experimental investigation has been carried out. The experimental system has a rated electricity power of 12 kW, a rated cooling capacity of 9 kW and a rated heating capacity of 28 kW. Evaluation and analysis of the system are discussed in detail. The testing results show that the energy efficiency of the overall system depends on different modes. The overall thermal and electrical efficiency is over 70%. Higher heat load supplied causes higher efficiency of the system. Economic evaluation shows that the micro-CCHP system enjoys a small capital cost and short payback period, which is easily accepted by customers. At current natural gas price of 1.9 RMB/m3 (nominal condition) and electric price of 0.754 RMB/(kW·h), the total capital cost is only 90 000 RMB with a payback period of 3.21 years.