<p>The process used by the Norwegian company Hydro for making Vinyl Chloride Monomer (VCM) from natural gas and sodium chloride has been studied. A three dimensional CFD model representing the firebox of the EDC cracker has been developed using the commercial CFD tool Fluent. Heat to the cracker is delivered by means of combustion of a fuel gas consisting of methane and hydrogen. In the developed CFD model used in this work, the combustion reaction itself is omitted, and heat is delivered by hot flue gas. With the combustion reaction left out, the only means of tuning the CFD model is through the flue gas inlet temperature. With the flue gas inlet temperature near the adiabatic flame temperature, the general temperature level of the EDC cracker was reported to be too high. The outer surface temperature of the coil was reported to be 3-400 K higher than what was expected. By increasing the mass flow of flue gas and decreasing the temperature, the net delivered heat to the firebox was maintained at the same level as the first case, but the temperature on the coil was reduced by 100-150 K. Further reductions in the flue gas inlet temperature and modifications in the mass flow of flue gas at the different burner rows, eventually gave temperature distributions along the reaction coil, and flue gas and refractory temperatures, that resemble those in the actual cracker. The one-dimensional reactor model for the cracking reaction represents the actual cracker in a satsifactorily manner. The cracking reaction was simulated using a simple, global reaction mechanism, thus only the main components of the process fluid, EDC, VCM and HCl, can be studied. The model is written in a way suitable for implementation of more detailed chemical reaction mechanisms. The largest deviation in temperature between measured and simulated data are about 5%. At the outlet the temperature of the process fluid is equal to the measured data. The conversion of EDC out of the firebox is assumed to be 50 wt-%, this value is met exactly by the model.</p>

<p>This master thesis describes a quadratic programming model used to calculate the spot prices in an efficient multi-area power market. The model has been adapted to Northern Europe, with focus on Denmark West and the integration of large quantities of wind power. In the model, demand and supply of electricity are equated, at an hourly time resolution, to find the spot price in each area. Historical load values are used to represent demand which is assumed to be completely inelastic. Supply is modeled according to the type of generation: Thermal generators are represented by piecewise linear, upward sloping, marginal cost curves. Historical wind generation data is used to model the fluctuating wind power output, and wind power is considered to have zero marginal cost. Hydro power is modeled by one aggregate reservoir for Norway and one for Sweden; the marginal cost of hydro power is set as a function of the difference between the reservoir level and the historical median reservoir level. Additionally, decentral combined heat and power plants in Denmark are considered to operate irrespective of the market. Six separate price areas constitute the model: Denmark West, Denmark East, Norway, Sweden/Finland, Germany, and Central Europe. The areas are modeled as having no internal bottlenecks and are connected by tie-lines constrained by active power limits. This report quantifies the impact the installed wind power capacity has on the power price in Denmark West by scaling up the wind power output in the model. Because wind power has a marginal cost close to zero, it will force prices down. The effect will be most prominent during high wind speed hours in a power system with substantial amounts of wind power. Results show that the impact is modest; average power prices fall by only 10% if the installed wind power capacity is doubled, and thermal generation will set the power price in all hours until wind energy exceeds 50% of domestic demand in Denmark. Since prices fall the most during hours with high wind power output, income to wind turbine owners will decline quickly as the installed capacity becomes large. The effect is most pronounced at wind energy shares above 40%, thereafter the income -- per MWh sold -- falls rapidly. In absence of government subventions, this effect will limit the economically viable level of installed wind power capacity. Expansion of the cross-border transmission capacity and higher thermal generation costs can both help offset the income reduction to wind turbine owners from higher wind power penetration. Alone, a 30% increase in thermal generation costs can allow 50% of wind energy and still retain todays income to wind turbine owners. Use of the Norwegian hydro reservoirs to balance out fluctuations in wind power output is found to stabilize and reduce the price. This benefits both consumers and wind turbine owners in Denmark. Expansion of transmission capacity to Norway will further stabilize the price; a new 1000MW cable lets the Danish market easily accomodate 50% wind energy. With lower and more volatile prices as a result of high wind power penetration, a load can profit by being flexible. Water electrolysis is one such load; it uses electricity to produce hydrogen, and production can quickly be ramped up and down in accordance with the power price. Presently, steam methane reforming is the least expensive method of producing hydrogen, but with higher wind power penetration, electrolysis might become competitive. Using a previously developed model to assess the cost of electrolysis, in combination with the power market model developed here, this report finds that wind energy must exceed 85% of domestic demand in Denmark, combined with higher natural gas prices, for electrolysis to break even with steam methane reforming.</p>

<p>Nordel is the organisation for the Nordel synchronous system, held by the Nordic Transmission System Operators. In their work to harmonise the Nordic electricity markets they have agreed upon harmonising the Nordic balance management. This will imply three large changes, firstly the settlement of the production balance will be done by a 2-price settlement, (instead of the 1-price settlement in Norway), and secondly there will be a new intraday market for settling the balances after 12- 36 hours and before operating time. Finally the Balance Responsible Parties will have to take their share of the costs for operating the reserves. Paying a penalty through paying more in the regulating market than in the spot market is meant as an incentive for the market to maintain their power balance. This will help the system operator reduce their need to contract and use reserve power and consequently reducing total costs. These new regulations will reduce the net income from producers of wind and other power plants that cannot control their production, like run of river hydro power plants. The market for electricity is currently divided into three consecutive markets. Nord Pool fixes the price the day ahead of operation, followed by the intra-day market Elbas (not in Norway), where power is traded up to one hour before operation, and lastly, the balancing market which helps maintain the balance in the operational hour and settles the costs afterwards. The costs of balancing wind power production in the balancing market (1- price and 2-price) are analysed. Wind series from three Norwegian wind parks have been nominated to the spot market and the deviation settled in the balancing market, by the 1-price settlement as reference and the 2-price settlement. The nominations have been done to three different years; 2004, 2005 and 2006 in Norway, and park A is nominated to 2006 in Sweden and Denmark. It is assumed that the wind power production and the spot and regulating prices are independent of each-other. The resulting change in income with deviation compared to making no prediction error for a 100 MW wind farm is presented. The highest loss compared to making no prediction error is when making a common bid for park A and B (11 677 000 in 2006), followed by the common bid for park A+B with wind series from the second year(8 555 000 in 2006) and park A (7 733 000 in 2006) in Denmark. One of the best ways to integrate large amounts of wind energy is to improve the forecasting methods. In that way the production planning will go easier, and deviations and corresponding costs are reduced. The savings achieved by introducing a prediction tool equals 3 523 000, 4 122 000, 4 921 000 compared to the base case of the corresponding MAEs equal to 39%,30% and 18%. The smoothing effect emerges when nominating geographically spread parks in a group(Holtinnen, 2005). Three parks, that are separated by several 100 km, are nominated by a single BRP. The resulting costs compared to separate nominations are reduced by 31,5 %. This result requires that the wind farms is in the same price area, which they in this case does not. The result is interesting nevertheless as Nordel continuously seek to to invest in transmission capacity in order to create an efficient Nordic market for electricity. The Elbas market is mainly a market to reduce risks. If a deviation should occur it is likely that the best way for balancing it, will be in the regulating market. This is due to the principle of the merit order, which implies that the cheapest regulating power offered is used first. By comparing the data there were quite a few hours were the middle Elbas price was higher than the regulating price. In this sense it might have been wise to wait, although the lower regulating price may also have been a result of more energy being settled in the Elbas market, reducing the volume needed to be settled in the regulating market, and accordingly reducing the price.</p>

<p>A measurement of the hydraulic turbine efficiency at the Vessingfoss hydro power station by the thermodynamic method has been attempted, but has not given the desired results. Two problems have been encountered. The high pressure side temperature measurements show an abnormal scatter resulting in standard deviations of sy=0.05ºC. The reason for the scatter may be temperature layers in the reservoir lake Nesjø. This theory has been investigated, but needs further work. The other problem has been the mechanical strength of the low pressure side collector probes. Two different collectors have been tried, and both have broken down. The second attempt was made with a collector design based on wire rope, which failed because the turnbuckles were under-dimensioned. With proper dimensions, this solution is interesting in the future, as it was easy to install and may contribute to lose collector weight. The relative turbine efficiency has been calculated based on pressures and levels measured during the thermodynamic test. An uncertainty analysis of the result has been carried out. The head loss has been calculated based on technical drawings of the penstock and loss coefficients from the literature.</p>

<p>A multi-reactor, multi-temperature, waste-heat driven biomass thermochemical converter is proposed and simulated in the process simulation tool Aspen Plus™. The thermochemical converter is in Aspen Plus™ integrated with a gas turbine power cycle and a combined fuel cell/gas turbine power cycle. Both power cycles are recuperative, and supply the thermochemical converter with waste heat. For result comparison, the power cycles are also integrated with a reference conventional single-reactor thermochemical converter, utilizing partial oxidation to drive the conversion process. Exergy analysis is used for assessment of the simulation results. In stand-alone simulation, the proposed thermochemical shows high performance. Cold gas efficiency is 108.0% and syngas HHV is 14.5 MJ/kg on dry basis. When integrated with the gas turbine power cycle, the proposed converter fails to improve thermal efficiency of the integrated cycle significantly, compared to reference converter. Thermal efficiency is 41.8% and 40.7%, on a biomass HHV basis, with the proposed and the reference converter respectively. This is despite superior cold gas efficiency for the proposed converter, and the gas turbine cycle is found not to be able to properly take advantage of the high chemical energy in the syngas of the proposed converter. When integrated with the combined fuel cell/gas turbine power cycle, the proposed converter significantly improves the thermal efficiency of the integrated cycle, compared to the reference converter. Thermal efficiency is 56.0% and 51.2%, on a biomass HHV basis, with the proposed and the reference converter respectively. The fuel cell is found to be able to take advantage of the high chemical energy in the syngas of the proposed converter, which is the main cause of increase in thermal efficiency. Operation of the proposed thermochemical converter is found to be feasible at a wide range of operating conditions, although low operating temperatures in the converter may cause problems at very high carbon conversion ratios.</p>

<p>In this work, a 23-1 designed experiment has been performed to evaluate the effect of selected operating conditions on PEMFC performance and durability. Relative humidity, clamping pressure and back pressure were studied at two levels for Gore MEAs and GDLs. Two replicated experiments were performed. An ON/OFF test cycle was used to accelerate degradation. Total duration of the tests, after a break in procedure suggested by Gore, was ten days. In addition to sampling of voltage and current response and ohmic resistance, effluents were manually sampled from both electrodes every 24 hours and analyzed. Experiments with low humidification levels showed inferior durability. The combination of high relative humidity (100 %), high clamping pressure (10 barg) and high back pressure (1.5barg) result in the best performance and the lowest degradation rate. Results indicate that relative humidity is important both for performance and durability. Generally, fluoride emission rates (FER) showed an increasing trend with time. Higher rates were observed at the cathode. For the experiment with low relative humidity (25 %), low clamping pressure (5 barg) and high back pressure (1.5 barg) FER was significantly higher compared to the other experiments. For all tests the sulfur emission rates (SER) are initial high. Rates are higher at the anode. For the experiment with high relative humidity, low clamping pressure and no back pressure, the SER was significantly higher than for the other experiments. The sustained high levels of sulfur are probably a result of sulfuric acid residue from production of the MEA and/or GDL. High humidification of gases appears to more effectively wash out the sulfur.</p>

<p>Coal is the most common fossil resource for power production worldwide and generates 40% of the worlds total electricity production. Even though coal is considered a pollutive resource, the great amounts and the increasing power demand leads to extensive use even in new developed power plants. To cover the world's future energy demand and at the same time limit our effect on global warming, coal fired power plants with CO2 capture is probably a necessity. An Integrated Gasification Combined Cycle (IGCC) Power Plant is a utilization of coal which gives incentives for CO2 capture. Coal is partially combusted in a reaction with steam and pure oxygen. The oxygen is produced in an air separation process and the steam is generated in the Power Island. Out of the gasifier comes a mixture of mainly H2 and CO. In a shift reactor the CO and additional steam are converted to CO2 and more H2. Carbon dioxide is separated from the hydrogen in a physical absorption process and compressed for storage. Hydrogen diluted with nitrogen from the air separation process is used as fuel in a combined cycle similar to NGCC. A complete IGCC Power Plant is described in this report. The air separation unit is modeled as a Linde two column process. Ambient air is compressed and cooled to dew point before it is separated into oxygen and nitrogen in a cryogenic distillation process. Out of the island oxygen is at a purity level of 95.6% and the nitrogen has a purity of 99.6%. The production cost of oxygen is 0.238 kWh per kilogram of oxygen delivered at 25°C and 1.4bar. The oxygen is then compressed to a gasification pressure of 42bar. In the gasification unit the oxygen together with steam is used to gasify the coal. On molar basis the coal composition is 73.5% C, 22.8% H2, 3.1% O2, 0.3% N2 and 0.3% S. The gasification temperature is at 1571°C and out of the unit comes syngas consisting of 66.9% CO, 31.1% H2, 1.4% H2O, 0.3% N2, 0.2% H2S and 0.1% CO2. The syngas is cooled and fed to a water gas shift reactor. Here the carbon monoxide is reacted with steam forming carbon dioxide and additional hydrogen. The gas composition of the gas out of the shift reactor is on dry basis 58.2% H2, 39.0% CO2, 2.4% CO, 0.2% N2 and 0.1% H2S. Both the gasification process and shift reactor is exothermal and there is no need of external heating. This leads to an exothermal heat loss, but parts of this heat is recovered. The gasifier has a Cold Gas Efficiency (CGE) of 84.0%. With a partial pressure of CO2 at 15.7 bar the carbon dioxide is easily removed by physical absorption. After separation the solvent is regenerated by expansion and CO2 is pressurized to 110bar to be stored. This process is not modeled, but for the scrubbing part an energy consumption of 0.08kWh per kilogram CO2 removed is assumed. For the compression of CO2, it is calculated with an energy consumption of 0.11kWh per kilogram CO2 removed. Removal of H2S and other pollutive unwanted substances is also removed in the CO2 scrubber. Between the CO2 removal and the combustion chamber is the H2 rich fuel gas is diluted with nitrogen from the air separation unit. This is done to increase the mass flow through the turbine. The amount of nitrogen available is decided by the amount of oxygen produced to the gasification process. Almost all the nitrogen produced may be utilized as diluter except from a few percent used in the coal feeding procedure to the gasifier. The diluted fuel gas has a composition of 50.4% H2, 46.1% N2, 2.1% CO and 1.4% CO2. In the Power Island a combined cycle with a gas turbine able to handle large H2 amounts is used. The use of steam in the gasifier and shift reactor are integrated in the heat recovery steam generator (HRSG) in the steam cycle. The heat removed from the syngas cooler is also recovered in the HRSG. The overall efficiency of the IGCC plant modeled is 36.8%. This includes oxygen and nitrogen production and compression, production of high pressure steam used in the Gasification Island, coal feeding costs, CO2 removal and compression and pressure losses through the processes. Other losses are not implemented and will probably reduce the efficiency.</p>

<p>Sorption Enhanced Steam Methane Reforming (SE-SMR) is a novel way of reforming natural gas to high purity hydrogen gas with in-situ CO2 capture by the introduction of a CO2 sorbent. The process is carried out in two steps. In the first step, hydrogen is produced and CO2 is absorbed by the sorbent. In the second step, the sorbent is exposed to high temperature heat and the CO2 is released. For the reforming to run continuously, two bubbling fluidized beds(BFB), can be coupled, one working as a reformer and the other one as a regenerator of the CO2 sorbent. The reformer works at a temperature around 500˚C and the regenerator at around 900˚C. Once the reactions in the reformer are being carried out the reformer works at a near autothermal state due to the exothermic reaction between CO2 and the sorbent. The regenerator however needs to be continuously supplied with heat to maintain at least 900˚C and for the endothermic calcination reaction of the sorbent to be carried out. One of the ways of providing heat to the process is by internal heat exchanger tubes. The advantage of using heat exchanger tubes is that no extra gas is added to the gas already in the bed (used interchangeably with reactor), thus not disturbing the volumetric flow and gas composition of the bed. For sequestration purposes, if the gases within the bed are not disturbed by for example nitrogen, N2, they will be easier to separate and sequester. An analytical calculation of the energy balance of a calcination reactor with horizontal heat transfer tubes was carried out, and the necessary effect was found to be 14.02kW, which equates to a heat exchanger with 96 tubes in 8 rows, taking up 26cm height in the reactor. Transferring heat via exhaust gas through metal tubes does however not yield a high thermal efficiency. One way of improving the efficiency of the calcinator is burning fuel gas directly in the reactor. This will lead to a direct heat exchange between the exhaust gas and the sorbent. On the other hand will the direct burning with air as an oxidizer lead to high fractions of N2 in the reactor. Considering that the gas in question in this work is biogas, the release of CO2 from the combustion is technically carbon neutral. Calculations for the necessary heat exchanger surface area and combustion rate of methane for the in-reactor combustion alternative have been carried out analytically, and a model of the in-reactor combustion has been established. At first, a fully fluidized bed model with integrated methane combustion was planned. Due to limitations of the modeling program and conversations with experts on the scope of the work in relation to the time-frame of the thesis, which is more closely discussed in Appendix H, the problem was reduced to a fixed bed approximation with “black box” combustion of methane outside the reactor. A heat balance, dependent on the rate of calcination was applied in the finite element modeling program COMSOL Multiphysics, and the resulting temperatures in the reactor were examined on the basis of what kind of fuel gas was used. In the first case, upgraded biogas, or SNG(Sustainable Natural Gas) was used as fuel gas. SNG is ~100% CH4, and the biogas has a CH4 content of ~48%. From the model it was seen that the mean temperature of the bed with SNG was 1218K, or 945˚C, and with the biogas the temperature of the bed was 1248K, or 975˚C. The calcination rate was found to be from 72.5 to 86.3% of the optimum. The lower results might be due to the adiabatic flame temperature of the gas and/or the relatively low heat capacity of the gas.</p>

<p>In 2003 the European Commission introduced the Directive 2003/54/EC and Regulation 1228/2003/EC which increased the focus on the liberalization of the European electricity market. The international electricity trade has increased and created new challenges related to cross-border transmission and compensation mechanisms. The focus of the report has been to discuss the development of the electricity market in Europe, and the status of international exchange. The report also discusses the concept of cross-border trade and transit, and investigates a proposed ITC model and whether correct investment incentives are given. Price data from the main power exchanges in Europe indicate that the market is experiencing increasingly integration and efficiency. There has also been a trend towards market based congestion management methods. Regional markets have successfully developed in Spain and Portugal (the Iberian market) and between France, Belgium and The Netherlands (the Trilateral Market Coupling, TLC). Further plans for regional coupling are also underway (see chapter 5. The most common definition of transit is the one adopted by ETSO (Association of European Transmission System Operators), where transit is defined as the minimum between exports and imports. This definition could create opportunities for market participants to manipulate transit income (discussed in chapter 5.3). The Inter-TSO compensation (ITC) model used in this report is based on the With-and-Without transit algorithm. The model only focuses on costs and load flow, and do not include market incentives or evaluation of benefits. The model bases the compensation calculation on the transit term, which can lead to misguided identification of network responsibility. Two scenarios were compared with a base case scenario in order to identify possible investment incentives. The first scenario included a situation where one of the cross-border lines in the network was constrained. Results from this simulation indicate that the transmission system operators involved would experience increased ITC payment, and therefore not receive investment incentives. The TSOs involved would benefit from the bottleneck in form of increased revenue (assuming Cost-Of-Service regulation). In the second scenario an extra cross-border line was implemented, and the situation was compared to the base case. The results from this simulation show that the TSOs involved would receive a positive effect in form of reduced ITC cost. The ITC mechanism would in this case be in line with the European Commission’s Regulation 1228/2003/EC, and give the involved TSOs correct investment incentives. The lack of correlated results in these two cases indicates that the ITC mechanism (in this case modeled by the WWT algorithm) cannot be regarded as relevant from an investment incentive perspective (more information found in chapter 7.3).</p>

<p>Experimental studies as well as simulations have been performed on the Back-to-Back starting schemes low frequency-, partial frequency-, and soft -start-up. A Back-to-Back configuration of two synchronous machines has been established in the laboratory, upon which parameter estimation and start-up experiments have been performed. Extensive parameter estimation was conducted in order to replicate the laboratory machines in the simulation model as accurately as possible. This was done in order to verify the validity of the simulation model. Studies into the effects of inductance interconnecting the machines were made in the laboratory and in the simulation model. Effects of resistance and inertia were studied in the simulation model. It is concluded that the simulation model appears to be as reliable as is its input parameters. Discrepancies were found in line voltages, due to faulty implementation of field current replication. Full scale simulations using Motorformer parameters were performed in the simulation model, featuring low frequency- and soft -staring. The effects of an interconnecting cable were studied. It is concluded that low frequency starting appears to be most reliable and least violent starting method. However, it might be limited by the availability of a turbine. This is not the case for soft starting, which has a lower starting capability and is more violent to the motor damper- and field windings. Low frequency startig is the recommended starting method of the ones studied. Dynamic short circuit simulations were done on a fixed speed LNG-facility. The fixed speed alternative appears to be more stable when responding to a short circuit. This is because the motors contribute to upholding the voltage during a fault by delivering reactive power to the short circuit, and because the motors do not loose all torque as is the case for LCI drives when the voltage dip exceeds 20$%$. Further work is needed in up-scaling the experiments. A sophisticated simulation model should be established and its validity tested on the up-scaled experiments. Preliminary custom design of machines should be initiated depending on what starting scheme is chosen. Custom machine parameters should then be used in full scale simulation using the more sophisticated model.</p>