Energy Evaluation and Techno-economic Analysis of Low-Rank Coal

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Energy Evaluation and Techno-economic Analysis of Low-Rank Coal (Victorian Brown Coal) Utilization for the Production of Multi-Products in a Drying - Pyrolysis Process Tahereh Hosseini, Anthony De Girolamo, and Lian Zhang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03840 • Publication Date (Web): 29 Jan 2018 Downloaded from http://pubs.acs.org on February 3, 2018

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Energy & Fuels

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Energy Evaluation and Techno-economic Analysis

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of Low-Rank Coal (Victorian Brown Coal)

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Utilization for the Production of Multi-Products in

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a Drying - Pyrolysis Process

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Tahereh Hosseini, Anthony De Girolamo and Lian Zhang*

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Department of Chemical Engineering, Monash University, Clayton, GPO Box 36, Victoria 3800, Australia

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* Corresponding author: Email: [email protected]

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Tel: +61-3-9905-2592, Fax: +61-3-9905-5686

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KEYWORDS

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Victorian brown coal utilization, Pyrolysis, Flow-sheeting and Process simulation, Energy Evaluation, Techno-economic Analysis

ACS Paragon Plus Environment

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ABSTRACT

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In this paper, utilization of Victorian brown coal in a drying - pyrolysis process to make

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products is techno-economically assessed. The pyrolysis process is coupled with the drying

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and briquette making processes in order to improve the overall efficiency and quality of the

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products. The pyrolysis process led to the production of char, liquid oil and hydrogen-rich

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non-condensable gases. A steady-state Aspen Plus simulation model was developed that

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provides estimated mass and energy balances for the overall system. The effect of a change in

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the heating mode and heating medium of the dryer on the overall energy and overall product

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yields was examined. Additionally, the effect of a change in the pyrolysis gas composition

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and coal initial moisture were studied. Results revealed that, the rotary drum dryer with hot

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flue gas as a heating medium showed the best performance in terms of the final yields of the

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pyrolysis products and CO2 emission rate. In the best case scenario, using hot flue gas

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directly in a rotary drum dryer, approximately 55% of the total gas produced from the

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pyrolysis process is needed to burn in a separate boiler to provide heat for the whole system.

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The shorter residence time in the pyrolysis reactor results in a lower calorific value gas with

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less hydrogen but more CO2 produced, which in turn increases the consumption of gas to be

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burnt to provide heat for the whole system. The wet coal initial moisture is another important

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factor affecting the energy required for the dryer and hence the total energy consumption. A

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coal with a higher moisture content needs more coal gas to be burnt and releases more CO2.

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The cash flow analysis indicated the net present value (NPV) of $52.8 million for a plant with

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a capacity of 70.6 t/h raw coal based on the first quarter of 2015 pricing, with a internal rate

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of return of 25% and the payback period of 5.1 years under the best case scenario.

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Energy & Fuels

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1. INTRODUCTION

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Nowadays with the depletion of black coal reserves, the low-rank brown coal, or lignite can

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be considered as a substitute to meet the ever-growing demand for energy 1. Victorian brown

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coal is the single largest energy source in the state of Victoria, contributing to over 85% of

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the state’s electricity supply 2. While abundant, this coal is of low grade and its high moisture

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content (~65%) makes it a poor competitor with black coal. The high moisture content needs

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a larger size boiler and as a consequence, the capital, operating and maintenance costs of

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brown coal boilers are much higher than black coal boilers 3. Additionally, brown coal is not

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suitable for long-term storage or the export market because of its high moisture content and

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tendency for spontaneous combustion. Brown coal is mainly used to produce energy for the

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local electricity market via the combustion in a coal-fired power plant that is close to the coal

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mine, exhibiting low-efficiency and high greenhouse gas emissions 4.

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Brown coal upgrading techniques including drying, liquefaction and gasification have

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attracted attention as alternative ways to produce value-added products

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which technology to be used, an efficient pre-drying is critical to the reduction of the

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greenhouse gas emissions from brown coal. Wang et al. showed that reducing moisture in

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Illinois coal from 40 to 25% resulted in a saving of the auxiliary powers such as fans and

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milling by 3.8% 7. Domazetis et al. reported a 30% relative reduction in CO2/MWh when the

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moisture content of the coal was reduced from 60 to 40% 8. A 30% decrease in greenhouse

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gas emission is anticipated by the implementation of efficient drying technologies in

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Victorian brown coal power stations 9. However, the level of moisture to be achieved after

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drying mainly depends on the end application. It varies from as low as nil for the

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hydrogenation process to 15% for briquetting and gasification processes 9.

25 3


5-6

. Regardless of

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To date, various low-rank coal drying techniques have been proposed and developed, with

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some being fully established while others are still emerging technologies10. The crucial

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factors to be considered are the source of energy, heating medium type and its contact mode

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with coal. A safe and efficient drying process from cost and energy perspectives can result in

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an improvement in overall efficiency and consequently a reduced cost of the whole poly-

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generation process 11.

7 8

Technologies based on pyrolysis made their way to utilize brown coal as an alternative to

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direct combustion. This process not only converts coal into clean fuels but also to chemicals,

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all of which excluding tar are stable and have the potential to be transported over a long

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distance 12. The liquid tar also can be upgraded into liquid fuels and chemicals. Additionally,

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coal pyrolysis can be coupled with other technologies such as gasification to produce

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chemicals and fuels

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properties of the coal feedstock but also by the pyrolysis temperature and the reaction

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residence time

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mainly on improving the product yields and upgrading the quality of products 15-18. However,

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products from different processes show significant variations in physical properties and

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chemical composition and consequently present unique technical and economic challenges 19.

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More importantly, to date, a study on the integration of low-rank coal pre-drying and

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pyrolysis is still missing in the literature, in contrary to the plenty of studies on the integration

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of drying and combustion or gasification.

13

. The product yields and composition are determined not only by the

12, 14

. Low-rank coal pyrolysis has been studied extensively with the focus

22 23

A simulation tool is needed to combine the drying and pyrolysis process in order to assess the

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overall system performance and energy requirement. It can also determine the most efficient

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combination through sensitivity analysis. The majority of published modeling works on low4


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Energy & Fuels

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rank coal pyrolysis have been focused on kinetic modeling and in particular the reactor

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modeling using different tools such as computational fluid dynamics (CFD) or using the

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chemical percolation devolatilization (CPD) model

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publications on the simulation of the coal gasification process

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publications are available for the simulation of low-rank coal pyrolysis. Yan and Zhang

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simulated a Loy Yang coal fast pyrolysis process integrated to a boiler using Aspen Plus as a

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simulation tool. They used an experimental data in the literature to build the model 3.

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Integration of drying, pyrolysis and entrained bed gasification to utilise Victorian brown coal

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was introduced by Dai et al. 1. They used Aspen Plus to simulate the process, and exergy

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analysis was conducted to prove the advantages of the proposed process against the

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conventional drying-gasification combination 1. Cai et al. established a process flowsheet to

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investigate the performance of a lignite coal-fired circulating fluidized bed boiler integrated

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with a dryer and pyrolysis reactor. They used a lab-scale experimental data to validate their

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model 28. In addition, there is a noticeable lack of energy and carbon footprint evaluations as

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well as techno-economic analysis studies that can determine the most efficient process for a

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low-rank coal drying process combined with pyrolysis.

20-23

. There is also a number of 24-27

but only a few

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This research aims to develop an Aspen Plus flowsheet model for the integration of pre-

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drying and pyrolysis of Victorian brown coal based on pilot-plant test results. Much research

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effort is being put into the development of this model to make the flowsheet model as close

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as possible to the industrial scale plant. This model can be used to explore the most efficient

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process together with the ability to predict the process response to a change in operating

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parameters. More importantly, the techno-economic analysis would be able to evaluate the

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profitability of this process if it has to be scaled up to a relatively large scale. The total CO2

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emissions from this technology are also calculated to assess the impact of this process on the

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environment, as well as compared with other coal utilization technologies. As far as the

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authors are aware, such a study has yet to be conducted in the past.

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2. METHODOLOGY

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2.1 Process Description

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The overall process of Victorian brown coal pyrolysis is divided into five sections described

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in Figure 1. In the pre-treatment stage (A-100), wet coal firstly undergoes crushing to reduce

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its size down to approximately 6 mm and less. Secondly, the moisture content in coal is

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decreased to about 15 wt% in a dryer to meet the requirement for the production of briquettes

10

29

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moisture - bearing gas which is separated by a baghouse filter. The secondary crusher is

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designed to further reduce the size of the dried coal to less than 2 mm before pelletizing.

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Subsequently, the crushed coal is passed on to a ram extrusion press to convert it into

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cylindrical briquettes with a dimension of ~50 mm and a height of ~20 mm

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assumed that 7.5% of fine coal particles will be disintegrated from the coal briquette due to

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the mechanical abrasion, forming coal grus that is sent to the combustion chamber (A-500).

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Regarding the pyrolysis step (A-200), a vertical fixed/moving-bed furnace with the use of

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indirect heating is employed, which is the cheapest and simplest option

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process is supplied from the partial burning of coal gas, tar and/or fine char particles within

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the furnace 32. After around 5 hours, the hot solid char was collected from the bottom of the

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pyrolysis reactor and the hot vapour exited the top of the reactor was sent to the post-

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separation unit (A-300). Hot char was quenched quickly by spraying water on it to avoid self-

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ignition. 10% of the total char, namely “char grus” and composed of fine particles with size

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less than 2 mm were separated from the cold char product which is mostly in the same form

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as the briquette feedstock.

. About 2.5% of the total coal particles hereafter, namely “dryer dust”, are entrained in the

6


30

. Here, it is

31

. Heat for the

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Energy & Fuels

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Condensable and non-condensable gases are separated after passing through bundles of

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coolers and two-phase separators. The majority of ammonia in the non-condensable gas

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mixture is removed by sulfuric acid and the resulting ammonia sulfate is separated from the

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clean gas and wastewater by a three-phase separator. The liquid mixture of water and tar is

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transferred to a decanter to separate the tar from wastewater. Later, the tar is further upgraded

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into light oil and heavy bottom fraction in a distillation column (A-400). To reiterate, the

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energy required for the process can be generated by burning either coal gas or dried coal or

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combination of other fuels produced in this process (A-500).

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2.2 Model Development

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The pyrolysis process is implemented in Aspen Plus V 9.0 to establish material balances as

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well as energy and utility requirements. The wet Victorian brown coal with a moisture

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content of ~65 wt% and a flow rate of 70.6 tonnes/h was used as a feedstock for this process.

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The proximate and ultimate analysis of dried Victorian brown coal and the particle size

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distribution input into the model is presented in Tables 1 and 2, respectively. Peng-Robinson

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equation of state with Boston-Mathis modification (PR-BM) was used to predict the

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thermodynamic properties of the model

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generation unit, STEAM-TA was chosen since this thermodynamic model uses steam table

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data

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ash. This model includes a number of empirical correlations for the heat of combustion,

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standard heat of formation and heat capacity. The chemical reactions that occur in the

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pyrolysis reactor are very complex and are not easily identified as many components are

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involved 1. In this study, we used a simplified approach to represent the reaction sets since

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kinetics and reaction mechanisms for pyrolysis of Victorian brown coal are poorly

33-34

. For the steam turbine cycle and steam

35

. The HCOALGEN model was used to characterize the enthalpies of coal, char and

7


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understood and would be accompanied by a certain degree of unreliability. The RYield

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reactor was used for pyrolysis, where the yield compositions are derived from experimental

3

data and the pyrolysis temperature was set at 800°C. Such an approach is reliable, given the

4

fact that a number of researchers have used the RYield reactor to simulate the pyrolysis and

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gasification technologies1, 4, 36.

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A list of the blocks used in the simulation along with a short function of each unit operation is

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summarized in Table 3. The detailed modelling approaches and the function of the other

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equipment used in the simulation are explained in the supporting information (SI). The

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following assumptions were deliberated in the model:

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•

Steady state process

12

•

The major components of tar are phenol, naphthalene, cresol and N-octadecane 37.

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•

The major components of coal gas are H2, CO, CO2, CH4 and C2H6

14

•

The change in dried coal properties upon using different drying methods is negligible

15

•

The wastewater treatment is out of the boundary in the simulation here.

16 17

2.3 Sensitivity Analysis

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Two criteria used in the evaluation include the overall product yields and the CO2 emission

19

rate 38. The overall product yields also reflect the energy efficiency since the energy required

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for the process is supplied by the combustion of the product itself. The second performance

21

indicator provides a measure of the preference of one scenario over another scenario in terms

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of CO2 emissions. The two major equipment in the process, the dryer and pyrolysis reactor

23

were deliberated for the sensitivity analysis since they are the two largest energy consumers

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in the overall process. In this study, the effects of dryer heating medium, as well as contact-

25

mode and the variation in coal gas compositions upon a change in pyrolysis operating 8


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Energy & Fuels

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condition were considered. Since the initial moisture content in the coal gas affects the drying

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energy requirement, the initial moisture content was further varied to examine the variations

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in the product yields and CO2 emission.

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2.3.1 Coal Drying Scenarios

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The material sensitivity, drying fluid and type of the dryer are the key components that need

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to be considered in the design of a drying process 39. Drying technologies for low-rank coal

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have been divided into two general categories of evaporative and non-evaporative depending

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on whether the water in coal will be vaporized or not

40

. Many researchers reported that

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rotary dryers have a higher energy efficiency and lower cost per unit mass of dried coal

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compared to the other drying technologies such as fluidized bed dryers

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difficulties associated with drying of low-rank coal are safety issues, especially spontaneous

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combustion and moisture re-adsorption. In order to minimize the risk of self-ignition, the

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drying medium should either contain a low oxygen content or should be in indirect contact

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with the coal 42. Heat used for the dryer could be provided from burning a product itself or

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can be recovered from waste heat in the process. The wet coal is brought into contact with the

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heat source, either directly (via hot gas) or indirectly (through a heated wall). The increase in

18

temperature increases the vapor pressure of the moisture inside the coal and once it becomes

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higher than the partial pressure of the heating gas or carrier gas, the water evaporates and is

20

carried away in the gas stream

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simulated with the principles of a rotary dryer, with the use of either steam or hot flue gas

22

generated from the combustion step.

9, 41

. The main

43

. According to the above considerations, the dryer was

23 24

Based on the heating fluid and contact mode, four scenarios were modelled and listed below.

25

The first two scenarios were proposed to examine the effect of using steam as a heating fluid 9


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1

in an indirect and direct contact mode with wet coal particles while the last two scenarios

2

examined the use of hot-flue gas in indirect and direct contact modes. For all of the four

3

scenarios proposed here, the composition and properties of dried coal remain constant and

4

only the energy consumption was evaluated.

5 6

Scenario 1: Indirect drying of coal using superheated steam in a rotary tube dryer

7

Scenario 2: Direct drying of coal using superheated steam in a rotary drum dryer;

8

Scenario 3: Indirect drying of coal using hot flue-gas in a rotary tube dryer

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Scenario 4: Direct drying of coal using hot flue-gas in a rotary drum dryer

10 11

The operating parameters employed for the design of the dryers in these four scenarios are

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mostly based on existing plants 42, 44, as summarized in Table 4. For indirect drying scenarios

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1 and 3, the steam and flue gas were defined as a utility in the dryer block. For the indirect

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steam drying scenario 1, a heat transfer coefficient of 75 W/m2.k, reported by Hatzilyberis et

15

al. 29 was added to the model. Due to the lack of experimental data from an existing plant in

16

the case of the indirect flue gas drying, the heat transfer coefficient was estimated by Aspen

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Plus, based on the physical properties of the flue gas tabulated in Table 4.

18 19

Scenario 1 refers to the use of superheated steam to dry the coal in a rotary tube dryer. The

20

superheated steam is generated in a boiler (A-500 combustion in Figure 1) which exchanges

21

heat from the combustion hot flue gas. In a rotary tube dryer, tubes are arranged

22

concentrically in the drum and the heating medium enters the tubes whereas coal particles

23

stay outside the tubes

24

dirty air went through a bag filter to remove the coal dust. To minimize energy consumption

43

. Air was used as a moisture carrier medium and the resultant wet

10


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Energy & Fuels

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during the drying process, the recovery of energy in the exhaust is essential. The superheated

2

steam is condensed at the tube outlet so as to recover the latent heat of the drying. The

3

resultant water condensate is pumped back to the boiler to generate the superheated steam.

4 5

Scenario 2 investigates the effect of using direct contact superheated steam in a rotary drum

6

dryer to dry the coal. In this type of dryer, superheated steam is mixed with coal inside the

7

dryer drum and the water is removed by convective heat transfer. The produced steam

8

together with the dirty outlet steam passes through a bag filter to remove the coal dust. Most

9

of the direct-contact superheated drying is usually integrated with other processes to fully

10

utilize the sensible and latent heat of the steam. GEA reported an energy consumption of 750

11

kWh/ton of evaporated water without heat recovery techniques. It was also reported that

12

about 70-90% of this energy can be recovered using the generated steam in other processes 45.

13

Since the energy in the exhaust cannot be used elsewhere in this plant, using WTA

14

(Wirbelschicht-Trocknung mit interner Abwärmenutzung) technology or condensation-

15

reproduction are the two possible options. WTA technology uses a compressor to recompress

16

the exhaust steam back to the inlet condition to recover the waste heat

17

required for the compressor was supplied from a turbine that is driven by the superheated

18

steam generated from the combustion step.

46

. The electricity

19 20

Scenario 3 was designed to examine the use of indirect-contact hot flue gas as a heating

21

medium in a rotary tube dryer on the overall process energy requirement. Using hot flue gas

22

to dry the low-rank coal is a mature technology and has been widely used 42. The hot flue gas

23

produced from combusting a portion of the coal gas at a temperature of ~1350°C enters the

24

tubes of a rotary tube dryer. The heat is transferred through the wall into the wet coal inside

25

the dryer. The moisture is carried away by air and the cold flue gas exited the dryer. 11


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Scenario 4 aims to further investigate the influence of using hot flue gas inside a drum dryer

3

to dry the coal. Flue gas at 1350°C and with an oxygen content of ~5% was used for coal

4

drying. Its outlet temperature drops to ~ 88°C, and the dirty wet flue gas passes through a

5

baghouse filter to capture the dust particles.

6 7

2.3.2 Different Coal Gas Composition

8

Considering that the gas derived from pyrolysis and its combustion is the major heat source

9

for the overall process, the effort was further made to assess the sensitivity related to the gas

10

compositions. For such a purpose, the results for a shorter residence time (~2 h) pyrolysis

11

reaction at the same temperature of 800°C was implemented 37 and its results were compared

12

with the longer residence time (~5 h) pyrolysis 47. Table 5 shows the composition of coal gas

13

from two different conditions, long residence time and short residence time, hereinafter

14

named H2 - rich and H2 - lean cases respectively. From the experimental results, a significant

15

decline in the amount of hydrogen produced was observed upon the decrease in the residence

16

time. The H2 - lean case observed in the lab - scale experiment is deemed as the worst - case

17

scenario to be encountered in a brown coal pyrolysis process.

18 19

2.3.3 Different initial moisture in the wet coal

20

A large limitation of the application of lignite in the coal-fired power plants is its high

21

moisture content, which varies from 30% to 70%

22

increases the energy required for the drying stage. A sensitivity analysis was thus performed

23

to identify the effect of change in the initial coal moisture on the amount of coal gas required,

24

the remaining product yields and CO2 emissions. To keep the product yields and pyrolysis

25

duty constant, the flow rate of the dried coal transferred to the pyrolysis was kept constant

48

. In practice, the high moisture content

12


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Energy & Fuels

1

and the initial moisture content in the coal was varied from 30 to 70%. The results for both

2

long and short residence time should be investigated to identify the worst and best case

3

scenario which may happen in the drying and consequently pyrolysis of Victorian brown

4

coal. It is also reasonable to assume that the properties of the dried coal and the total product

5

yields from pyrolysis remains unchanged upon variation of the wet coal initial moisture

6

content.

7 8

2.4 Cost Estimation Methodology

9

Aspen Process Economic Analyzer (APEA) V9.0 and an in-house cost estimation

10

methodology developed by the Commonwealth Scientific and Industrial Research

11

Organization (CSIRO) were employed to establish a techno-economic model 49. APEA maps

12

unit operations from Aspen Plus flowsheet to estimate the equipment size and consequently

13

purchased equipment costs

14

simulation results and through a combination of vendor quotes in APEA together with cost

15

estimation from online websites when it was necessary. The hypothetical plant is located in

16

Victoria, Australia hence the material cost is adjusted based on Australian context with the

17

currency conversion rate of 0.8 between the Australian Dollar and US dollar. All the

18

calculations were based on the 2015 first quarter pricing. The capital expenditure items were

19

calculated as a percentage of the equipment purchase cost (EPC) and direct equipment cost

20

(DEC)

21

including raw material costs, utilities, total fixed charges, depreciation and capital

22

Victorian brown coal price was assumed to be purchased at $3.5/t

23

98% sulfuric acid solution and ethanol were obtained online

24

washing and cleaning of the tar condensers. The electricity and natural gas unit prices were

25

assumed to be $0.1/kWh and $5/GJ respectively

49

33

. The purchased equipment cost was estimated based on

. Total operating cost was estimated based on the summation of operating items

53

51

50

. The

and the price of bulk

52

. Ethanol is required for the

. The amount of natural gas required for

13


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1

the plant start-up was estimated from the amount of energy required for the dryer and

2

pyrolysis reactor to work on the first day in a 24-hour shift. When the pyrolysis gas is

3

produced in the first cycle, the system could switch to the burning of the coal gas instead. The

4

total cost of cooling water was calculated based on the total cooling energies required in the

5

condensers with the unit price of $0.76/MWh as estimated by APEA. The labour cost was

6

estimated based on an assumption of $25 per tonne of products and other items in the total

7

fixed charges and depreciation & capital were calculated as a percentage of capital cost 53.

8 9

In terms of process revenue, char is expected to be sold as a substitute for pulverized coal

10

injection (PCI) coal in a blast furnace. The major steel making industries who use char are

11

located in the Fareast Asia region so the briquette char could be transported to these

12

destinations. It can also be utilized as a high-quality source of concentrated carbon in the

13

ferrochrome industry or upgraded to activated carbon for use in wastewater or gas

14

purification application. The price of char at the highest extreme was considered at $230/t as

15

an average selling price of semi-coke in online websites after conversion to the Australian

16

dollar

17

quality hydrocarbon fuels

18

generation applications. It also can be used to produce a range of commodities and chemicals

19

such as phenol and its derivatives 55. The price of oil was assumed to be the selling price of

20

the lowest quality component in the oil which is heating oil in the mixture. The price of

21

heating oil is $465/t after conversion from the unit price per gallon of heating oil in Australia

22

56

52

. Pyrolysis oil can be readily stored or transported or further upgraded into high54

. It can be a substitute for fuel oil in heating or electricity

.

23 24

Coal gas, if not used for hydrogen production, could replace natural gas in industrial

25

applications. The average heating value of Australian natural gas is 38.5 MJ/Nm3 while the 14


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1

heating value of the H2 - rich and H2 - lean coal gas are estimated 17.8 MJ/Nm3 and 16.1

2

MJ/Nm3 respectively by Aspen Plus model. To estimate the selling price of the coal gas, the

3

selling price of natural gas which is $5/GJ was used as a reference and the selling price of

4

both cases coal gas were estimated relatively. The selling price of H2 - rich and H2 - lean coal

5

gases were estimated $90/t and $20/t respectively. The worst case scenario selling prices

6

were considered for cash flow analysis in order to accommodate the future changes in the

7

composition and fluctuation in prices and to ensure the economic viability of the process. A

8

sensitivity analysis is further conducted if the selling price of product changes in future.

9 10 11

3. Results and Discussions 3.1 Material and energy balance for the base case scenario

12

The results from the mass and energy balances of the overall system with the assumption of

13

the provision of energies from the external sources are summarized in Tables 6 and 7

14

respectively. The total flow rate together with the mass compositions of main input and

15

output streams are listed in Table 6. COLDCHAR, CL-GAS, AMMONSUL, TAR, and OIL

16

are the main products, while WASTWATR, CHARGRUS and GRUS are the main wastes

17

and by-products leaving the process. The input streams, shown as WETCOAL and

18

SULFACID are also presented. The thermal and electrical energy consumption for each

19

functional unit within the pyrolysis plant is presented in Table 7. The char cooler and multi-

20

stage condensers are utilized to separate oil from the non-condensable gases are the main

21

cooling utility consumers. The pyrolysis reactor with a 37.86 MW thermal energy

22

consumption is the largest heating utility consumer in the plant, followed by the dryer which

23

consumes 32.27 MW of heating energy. It was also found that approximately 2.29 MW of

24

electricity is required to cover the electricity required for crushers, briquette machine, rotary

25

dryer motor and conveyors. Extra electricity may be required in the case of using the carrier 15


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

1

gas in the dryer to circulate it through the dryer using a blower. The electricity required for

2

the rotary dryer motor was scaled up from the assumption of 7.5 hp electricity required for a

3

dryer with a capacity of 200 t/day with the rotation rate of 3 ½ rpm 57.

4 5

3.2 Different Drying Scenarios

6

3.2.1 Comparison of product yields in different drying scenarios

7

The process flowsheets for all of the four scenarios are illustrated in Figure S1 (see the

8

supporting information). Table 8 presents the yields for individual products from each

9

scenario. Scenario 4 for a direct drying of coal using flue gas shows the highest annual

10

product rate, due to the use of the least amount of pyrolysis gas (55%). With respect to the

11

other scenarios, the product yields and the amount of the flue gas required for energy

12

production do not differ between the Scenarios 1 and 3, with an identical amount (58%) of

13

gas to be consumed. The reason is that an identical amount of energy required for the dryer

14

which could be supplied by either steam or another heating medium such as flue gas in an

15

indirect heat exchanger. However, scenario 2 requires the use of all the pyrolysis gas to be

16

burnt together with 35% of tar, due to the loss of the latent heat from the condensation of

17

steam when it is in direct contact with coal.

18 19

3.2.2 Energy consumption and CO2 emissions analysis

20

The detailed breakdown of electricity consumption for the four drying scenarios is

21

summarized in Table 9. The differences in the electricity consumption are mostly caused by

22

the electricity required for the dryer blowers. The dryers with indirect heating contact

23

consume more electricity since they need a large volume of air to be circulated through the

24

dryer. The electricity required for the air blowers in indirect dryers with both steam and flue

25

gas as heating mediums are identical, accounting for ~0.21 MW of electricity to circulate the 16


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Energy & Fuels

1

carrier air inside the dryer drum. The dryers with the use of flue gas do not need a separate

2

blower and boiler in comparison to superheated steam needing to be raised in the boiler. The

3

amount of electricity required for the rotary dryer motor is slightly higher for the case of

4

rotary drum dryers since the inlet wet coal capacity of the indirect mode contact dryers on the

5

market is smaller. Therefore, the number of the parallel dryers required to handle the inlet

6

wet coal is increased 57.

7 8

The CO2 emission rates from all four drying scenarios are tabulated in Table 10. The scope of

9

the analysis included: coal mining, transport of coal to the pyrolysis plant, mechanical

10

processing, drying, as well as pyrolysis, tar upgrading and combustion to provide the energy

11

for the pyrolysis reactor and dryer. The further impact on CO2 emissions from the application

12

of products as fuel in different industries or upgrading them in a separate process is out of the

13

scope of this analysis. The total CO2 emissions calculated according to the Life Cycle

14

Assessment (LCA) methodology is the sum of direct CO2 emissions and indirect emissions 58.

15

Direct CO2 emission from the overall process originates from the combustion stage as well as

16

CO2 in the coal gas product. The indirect CO2 emission is the sum of CO2 emission from coal

17

preparation i.e. coal mining and transportation as well as the corresponding emissions from

18

the power plant to produce required electricity for the process. The CO2 emission from coal

19

mining and transportation was calculated based on the total CO2 emission of 3.59 kg CO2 per

20

GJ of lignite coal 59. To convert it to kg CO2 per kg coal, the average heating value of wet

21

Victorian brown coal (8.65 MJ/kg) was used 60. Since the electricity required for mechanical

22

equipment, blowers and rotary dryer motor is purchased from external sources in the state of

23

Victoria, the emission factor of 1.17 was used to calculate the kg of CO2 released per kWh of

24

electricity 61.

25

17


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

1

Among the drying scenarios, scenario 4 consumes the least electricity and coal gas to supply

2

the energy required for the process, therefore, the CO2 emission rate from this process is the

3

lowest. Scenario 3 is the second best case in terms of CO2 emission rate, due to the slightly

4

lower electricity consumption for this scenario compared to scenario 1 (See Table 9).

5

Scenario 2 with a total release of 288.26 kt/a of CO2 to the atmosphere is the largest CO2

6

emitter between all of the four scenarios, due to the consumption of more heating energy and

7

electricity for the compression of unrecoverable steam.

8 9

3.3 Different Coal gas composition

10

Table 11 further compares the amount of coal gas required as well as the production rates for

11

the H2 – lean case against the best case scenario of H2 – rich (Scenario 4). It is obvious that

12

the pyrolysis gas composition is a critical factor affecting the process energy requirement

13

significantly. In the case of applying a shorter residence time in the pyrolysis reactor,

14

approximately 87% of the gas produced from pyrolysis has to be burnt, relative to 55% for

15

the H2 - rich case requiring a relatively long residence time. This is mainly attributed to a

16

lower yield for hydrogen produced in a short residence time, as evident by a production rate

17

of 0.013 t/h (144.6 m3/h) and 0.44 t/h (4895.4 m3/h) hydrogen for the H2 - lean and H2 - rich

18

case, respectively. However, the product yields for solid char and C1-C2 hydrocarbons are

19

slightly increased, due to the fact that less of these two species were consumed for the

20

production of hydrogen via partial gasification. Similar to the coal gas yield, tar yield shows a

21

consistent trend of diminishing from 2.73 t/h to 2.06 t/h if the residence time is shortened .

22

Due to the consumption of more coal gas for the energy production in the case of a short

23

residence time, the flow rate of total products declined from 16.84 t/h to 13.96 t/h.

24

18


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Energy & Fuels

1

A break-down of the CO2 emissions from the H2 - rich and H2 – lean scenarios is further

2

tabulated in Table 12. It was found a ~13% increase in the total CO2 emission rate could

3

occur for the H2 - lean case when compared to the best case scenario of H2 – rich case

4

(scenario 4). The total amount of ~226 kt/a of CO2 is thus released to the environment which

5

is higher than ~199 kt/a in the H2 - rich case. Obviously, the CO2 emissions from the flue gas

6

are larger in the case of the H2 - lean case due to the requirement of a larger portion of the

7

coal gas to be combusted. The CO2 emissions from the gas product are slightly higher in the

8

second case since the coal gas is rich in CO2 rather than the first case which is mostly H2 -

9

rich. However, the indirect CO2 emissions related to upstream coal preparation remains quite

10

similar.

11 12

3.4 Comparison of CO2 emissions with other coal utilization technologies

13

Figure 2 compares CO2 emissions for the best (Scenario 4) and worst case scenario (Scenario

14

2) determined in the present study to results from several previous LCAs of coal utilization

15

technologies

16

technologies is the same as our analysis boundary which considers the CO2 emission from

17

coal mining to the delivered products. The coal conversion technologies are mostly based on

18

gasification technology, followed by purification and separation to produce chemicals and

19

hydrocarbons. The amount of CO2 released by these technologies is mostly in the range of

20

~1-2 t CO2/t of coal while the current process shows much lower CO2 emissions. The major

21

reason can be attributed to the larger gasification temperature compared to the pyrolysis

22

results in more CO2 emissions from the energy production cycle. The total CO2 emissions

23

from these technologies are mainly dependent on the process complexity and the number of

24

separation and purification technologies. As an example, the coal pathway to hydrogen is

25

releasing more CO2, because the process is more complex and includes extra purification

62

. The boundary of CO2 emissions analysis for other coal utilization

19


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1

steps. There have been a lot of efforts to decrease the amount of CO2 emissions from the coal

2

utilization technologies through gasification. These approaches are mostly focused on

3

improving the process and catalyst efficiency, developing coal poly-generation technologies

4

and capture and utilization of CO2 63-64.

5

3.5 Different coal initial moisture content

6

The wet coal initial moisture is a crucial factor affecting the dryer duty and hence the overall

7

process energy requirement. Upon the increase in the initial moisture of the coal, the energy

8

required for the whole system increases hence more coal gas needed to be burnt to provide

9

energy for the system. The CO2 emissions and the amount of coal gas left as a product from

10

H2 – rich and H2 – lean case for the initial moisture content of 30% to 70% is summarized in

11

the Figure 3a and b respectively. As shown in panel a, the CO2 emissions increase

12

dramatically upon the increase in the coal initial moisture for both of the H2 – rich and H2 -

13

lean cases. The increase is more significant in the case of lower hydrogen content coal gas

14

due to the lower calorific value and hence the requirement of more coal gas for energy

15

production purpose. The CO2 emissions from the H2 – lean case can reach up to 200 kt/a

16

while at the other end of the line, the CO2 emission decreases to 135 kt/a when the moisture

17

content decreases to 30%. The same trend but with the lower slope was observed for the H2 –

18

rich case. The CO2 emissions from the flue gas varies between 126 to 163 kt/a upon an

19

increase in the coal initial moisture content. From this graph, it could be concluded that the

20

CO2 emission from this process always locates on the two extremes or the area between two

21

lines. The total coal gas left as a product decreases from 6 t/h to 3.4 t/h when the moisture

22

content increases from 30% to 70% for the case of longer residence time as evident in panel b

23

of Figure 3. The total coal gas left as a product for the case of shorter residence time declined

24

from 1.5 t/h to only 0.6 t/h when the moisture content increased to 70%. Again, these two

20


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1

lines show the two coal gas flow rate extremes that may occur in the process, when the coal

2

gas composition and moisture content varies.

3 4

3.6 Economic analysis

5

3.6.1 Capital and operating costs

6

The total capital investment for the 70.6 t/h Victorian brown coal pyrolysis is estimated to be

7

$41 million. The detailed breakdown of the capital cost items is summarized in Table 13. The

8

equipment purchase cost (EPC) is the largest contributor to the capital cost with $8.6 million.

9

Engineering supervision is the second largest with $4.7 million followed by equipment

10

installation with the total cost of $4.3 million. The percentage of contribution to the EPC

11

from the five main sub-processes including pre-treatment, pyrolysis, post-treatment-

12

combustion and tar upgrading together with miscellaneous items is presented in Figure 4. The

13

results indicate that the pyrolysis process accounts for 51.52% of EPC at $21 million, while

14

the pre-treatment and combustion account for 22.16% and 14.07% respectively.

15

Miscellaneous items, post-treatment and tar upgrading sub-processes are found to be 12.26%

16

of the total EPC. The most expensive constitutes of the pyrolysis sub-process are the

17

pyrolysis reactors. To accommodate the inlet flow rate and the long residence time, ten

18

parallel reactors are needed which increased the EPC significantly.

19 20

The Dieffenbacher Group reported €2.8 million as the capital cost of a lignite drying process

21

in a typical rotary drum dryer with the production rate of 15t/h of the dried coal in Germany

22

based on 2011 cost index 42. To compare the cost of this process with the drying part of our

23

process, the capital cost of this plant was converted to Australian dollars and it was updated

24

with the 2015 cost index. Then the location factor estimated for Australia and Germany was

25

used to make the cost estimations comparable. The method used for this conversion is 21


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1

described in detail in Peters & Timmerhaus 65. The cost index for 2011 and 2015 was found

2

to be 191.2 and 206.2 based on the year 1993 as a reference 66. Also, the location factor of 1.2

3

for Australia and 1.1 for Germany was applied 67. The escalation factor with coefficient 0.6 67

4

was used to scale up the process from 15 t/h to 28.3 t/h of dried coal. The results indicated the

5

capital cost of $7.6 million, while the drying part capital cost resulting from the current

6

process is estimated $8.8 million. The results are comparable and the relative error coming

7

from the differences in scale, location, year of estimation and currency and even the variation

8

in the process and heating medium is not very large.

9 10

The operating cost items are calculated for the base case scenario as indicated in Table 14.

11

The total operating cost was calculated to be ~$16 million while the total fixed charges are

12

the largest contributors to the operating cost. The total cost of purchasing the raw coal was

13

estimated at $2 million, while $0.5 million and $0.1 million are required to purchase ethanol

14

and sulfuric acid respectively. A total of $2.4 million is needed to purchase the utilities for

15

the process including electricity, cooling water and natural gas. The total fixed charges and

16

the depreciation & capital were estimated $7 million and $4 million respectively.

17 18

3.6.2 Effect of a change in coal gas composition

19

Figure 5 shows the impact of the change in the residence time and consequently change in the

20

coal gas composition on the different sub-processes equipment purchased cost. A decline in

21

the EPC related to the pyrolysis step was observed, due to the decrease in the residence time

22

of coal in the pyrolysis reactors. Contrary to the pyrolysis step, the purchase cost of

23

equipment in the combustion area was increased due to the larger size requirement for the air

24

blower and combustion furnace in the H2 – lean case. The post-treatment sub-section

25

purchased equipment cost was slightly decreased because of the decrease in the produced gas 22


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Energy & Fuels

1

phase flowrate leaving the pyrolysis reactors. The equipment purchase cost in the other sub-

2

sections remained unchanged.

3 4

Figure 6 shows the operating cost items for both the H2 – rich and H2 – lean case. While the

5

raw material costs remain unchanged, the utilities cost slightly increased compared to the H2 -

6

rich case. To reiterate, the increase in the utility cost results from the larger air blower

7

followed by the increase in the electricity requirement. Total fixed charges and depreciation

8

& capital were decreased in the lower H2 - content coal gas. The reason could be the lower

9

capital cost associated with the second scenario. The total operating and capital cost for both

10

scenarios are compared in Figure 7. The operating cost was decreased from ~$16 million to

11

~$15 million upon a decrease in the H2 composition in the coal gas. The same trend was

12

observed for the total capital cost with the decrease from ~$41 million to ~$36million.

13 14

3.6.3 Cash Flow Analysis and sensitivity analysis – The effect of major variables on NPV,

15

IRR and Payback Period

16

The annual cash flow, with all the revenues and expenditures, was made considering the

17

income from the selling of products. Some assumptions were made in the analysis: (1) the

18

lifetime of the plant was assumed to be 20 years; (2) the plant was assumed to operate 8000 h

19

per year; (3) rate of taxation was set as 30%; (4) The interest rate and depreciation were 10%

20

and 5% per year respectively and (5) working capital was estimated as 6.7% of the fixed

21

capital cost.

22 23

Figure 8 shows the variation of the cumulative non-discounted and discounted cash flow over

24

the lifetime of the plant for the two process alternatives. At the beginning, the cash flow for

23


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Page 24 of 46

1

both of the cases are negative but the cash flow becomes positive after getting revenue from

2

selling the products. At the start of the project, both of the discounted and non-discounted

3

cash flow for the case of H2 – lean gas is slightly higher than the H2 – rich case because the

4

initial investment is lower. However, the H2 –rich gas case ends up with a higher cash flow

5

over the lifetime of the plant. The net present value (NPV), internal rate of return (IRR) and

6

payback period for both of the scenarios are summarized in Table 15. Clearly, the H2 - rich

7

case demonstrates a better economic performance, considering the larger NPV and IRR and

8

the shortest payback period. The NPV and IRR for the first scenario can reach as high as

9

$52.8 million and 25% respectively and the payback period is 5.1 years. For H2 - lean case,

10

the cumulative cash flow becomes positive within 5.5 years and NPV and IRR reached to

11

$42.9 million and 23.9% respectively.

12 68

13

Since the market price of products, particularly char shows variation over a year

, a

14

sensitivity analysis on the best case scenario was performed to assess the sensitivity of the

15

NPV, IRR and payback period to the variation in input parameters. The parameters under

16

investigation include the selling price of the product, production cost and capital cost. The

17

input parameters were varied ±50% for the best case scenario to calculate the NPV, IRR and

18

payback period values, and the results are presented in Figure 9 a, b and c.

19 20

As evident in panel a, the NPV is most sensitive to the variation in the selling price of

21

products. By 50% increase in the selling price of products, caused by further refining the

22

products or rise in the market price of char, heating oil or natural gas, the NPV increased

23

around three folds compared to the base case values. However, the NPV became negative for

24

dropping the selling price to 70% of the original price. This may be caused by the decrease in

25

the world’s market price of these fuels or decrease in the heating values of produced fuels 24


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Energy & Fuels

1

resulting from the inefficient operation. Production cost is the second most sensitive

2

economic parameters, doubled the NPV when the production cost decreased by 50%. Further

3

increase in the production cost decreased NPV to ~$7 million. Capital cost has the lowest

4

impact on NPV, according to the least steep slope for variation of NPV upon a change in

5

capital cost. Around ±35% deviation in NPV was observed when the capital cost decreased or

6

increased by 50% respectively.

7 8

With respect to the IRR, a change in selling price exerts a remarkable impact as evident in

9

panel b. Decrease in the selling price by ~42% results in an IRR value close to 0 and by

10

further decreasing it to -50%, it became negative while an increase in the selling price by

11

50% doubled the IRR. A change in IRR upon a decrease in the capital cost by 50% is more

12

significant compared to the increase in the capital cost by 50%. A decrease in the capital cost

13

by 50% results in an IRR value as high as 47.7% (~91% increase from base case value),

14

while an increase in capital cost by 50% dropped the IRR to 16.8% (~33% decrease from

15

base case value). Variation of production cost by +50%, decreased the IRR to 12.2%. IRR

16

increased from 25% to 36.7% when the production cost decreased by 50%.

17 18

As shown in Figure 9 c, the selling price has the highest impact on the payback period. A -

19

30% variation in the selling price could increase the payback period from 5.1 to 12.4 years. A

20

further decrease in the selling price results in the project being non-profitable due to the

21

payback period even longer than the lifetime of the project. Conversely, an increase in the

22

selling price of the products by 50% could shorten the payback period to only 1.2 years. A

23

50% increase in the production cost and capital cost could not make the project unprofitable

24

since the payback period will be in the 10 years range. A decrease in production cost and

25

capital cost by 50% could shorten the payback period to 3.4 and 2.5 years respectively. 25


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

1 2

CONCLUSIONS

3

This paper examined the technical and economic feasibility of Victorian brown coal

4

utilization in a drying-pyrolysis process. Four different drying scenarios were examined to

5

study the effect of a change in the drying medium and heating contact mode in a rotary dryer

6

on the product yields and energy consumption. Also, the effect of a change in the pyrolysis

7

reactor residence time, as well as coal initial moisture on the energy provision for the process

8

was evaluated. Major conclusions drawn from this study are as follows:

9

1- The rotary drum dryer with direct flue gas as a heating medium was found to be most

10

effective in the case of energy consumption, CO2 emissions and product yields. The

11

dryer with direct superheated steam as a heating medium showed the worst results,

12

due to the requirement of a large energy for heat recovery in the outlet steam. The

13

total CO2 emissions from this process are between 0.35 to 0.51 tonne CO2 per tonne

14

of raw coal which is much lower than other coal utilization technologies.

15

2- The pyrolysis residence time was found influential on the overall energy consumption

16

of the system. The energy balance showed that more coal gas is required to provide

17

sufficient energy for both the pyrolysis reactor and dryer in the case of a shorter

18

residence time.

19

3- The total capital investment of this process for a flow rate of 70.6 t/h of wet coal is

20

$40.8 million, with the equipment purchase cost makes the largest contribution to the

21

capital cost. The operating cost for the best case scenario is $15.88 million while the

22

fixed charges have the largest share. The cash flow analysis for the best case scenario

26


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Energy & Fuels

1

showed the NPV, IRR and payback period of $52.8 million, 25% and 5.1 years

2

respectively.

3

4- The overall energy consumption for the process is increased upon an increase in the

4

coal initial moisture, due to the intensified drying requirement. The remaining coal

5

gas declines from 6 t/h to 3.4 t/h when the moisture content varies from 30 wt% to 70

6

wt% in the H2 – rich case. In the H2- lean case, the increase in the coal initial

7

moisture to 70% could decrease the remaining gas flow rate down to only 0.6 t/h.

8 9 10

ASSOCIATED CONTENT •

Supporting information

11

The details of the modeling approach is available in the supporting information.

12

AUTHOR INFORMATION

13

•

Corresponding Author

14

*Telephone: +61-3-9905-2592. Fax: +61-3-9905-5686. E-mail: [email protected].

15

ACKNOWLEDGMENT

16

The authors gratefully acknowledge the financial support for this work by Coal Energy

17

Australia Limited (CEA), Brown Coal Innovation Australia (BCIA), the ARC Industrial

18

Research Training Hub (15010006) and the ARC Linkage Project (LP160101228).

19 20

27


Energy & Fuels

1

Solid Liquid Gas

A-400 Tar Upgrading

Tar

Tar

Wastewater

A-500 Combustion

Air

Coal Grus

Dryer Dust Wet Coal

NCG

A-100 Pre-treatment

A-300 Post-Separation

AmmoniaSulfate

Gas-Phase Mixture

Char Grus

Briquette

Oil

A-200 Pyrolysis Char

Moisture 2 3

Figure 1 Proposed block flow diagram for Victorian brown coal pyrolysis

4 3

2.5

2

tCO2/t coal

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 28 of 46

1.5

1

0.5

0 Coal to Methanol

Coal to DME

Direct coal Indirect coal liquefaction liquefaction

Coal to natural gas

Coal to hydrogen

Coal to olefin Our process (coal to multiproducts)

5 6 7

Figure 2 Comparison of t CO2/t coal emitted from different coal utilization processes with the current process ranging from worst and best case scenario

28


Page 29 of 46

8 9

CO2 emission from flue gas (kt/a)

a) 220 H2 - rich

200

H2 - lean 180

160

140

120

100 30%

40%

50%

60%

70%

Moisture content

10

b) Total coal gas left as product (t/h)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

7 H2- rich

6

H2 - lean 5 4 3 2 1 0 30%

11 12 13

40%

50%

60%

70%

Moisture content

Figure 3 The effect of initial moisture on a) CO2 emission from the flue gas and b) remained gas product yields for both H2 – rich and H2 – lean cases


Energy & Fuels

Miscellaneous , 8.63%

Tar upgrading, 1.14%

Pre-treatment, 22.16%

Combustion, 14.07%

Posttreatment, 2.49%

Pyrolysis , 51.52%

14 Figure 4 Proportion of five different stages in a purchased equipment cost

$Millions

15

5 4.5 4

Equipment purchase cost (EPC)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 30 of 46

3.5 3 2.5 2 1.5 1 0.5 0 Pre-treatment

Pyrolysis

Post-treatment Tar upgrading

H2- rich

H2- lean

16 30


Combustion

Miscellaneous

Page 31 of 46

17

Figure 5 Effect of H2 composition on the equipment purchased cost of different sub-sections

18 8 H2 - rich H2 - lean

7 6 5

Cost (M$)

4 3 2 1 0 Raw materials

Utilities

Total fixed charges

Operating cost items

19

Depreciation & Capital

Figure 6 Effect of H2 composition on the operating cost items

20 21 22

45 41 40

36

H2 - rich 35

H2 - lean

30

Cost ($M)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

25 20 16

15

15 10 5 0 Total operating cost

Total capital cost

23 24

Figure 7 Effect of H2 composition on the total operating cost and capital cost

25 31


Energy & Fuels

26 27 28

a)

Non-discounted Cash Flow

200

150 H2 - rich 100 M$

H2 - lean 50

0

-50 0

2

4

b)

6

8

10 12 Life time (year)

14

16

18

20

14

16

18

20

Discounted Cash Flow

70 50 H2 - rich 30 M$

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 32 of 46

H2 - lean

10 -10 -30 -50 0

29 30 31

2

4

6

8

10 12 Life time (year)

Figure 8 Cumulative (a) non-discounted and (b) discounted cash flow diagrams of rich in H2 and lean in H2 case over the lifetime of the plant

32

32


Page 33 of 46

200

a)

50

Internal Rate of Return (IRR) (%)

-60

Production cost 100

50

0 -40

-20

Selling price of products Capital cost

60

b)

Selling price of products 150 Capital cost

Net present value (NPV) ($M)

Production cost 40 30 20 10 0

-60

0

20

40

60

-40

-20

0

20

40

-10

-50

-20

Percentage deviation from base case values

Percentage deviation from base case values 25

c)

Selling price of products Capital cost

20

Payback period (years)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Production cost 15

10

5

0

33 34 35 36

-60

-40

-20

0

20

Percentage deviation from base case values

40

60

Figure 9 Sensitivity analysis on the effects of the production cost, selling price of the product and capital cost on the a) NPV; b) IRR; and c) Payback period for the best case scenario

37

33


60

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

38

Page 34 of 46

Table 1 Ultimate and Proximate Analysis of the coal sample Proximate Analysis (db*) Moisture 0 FC* 46.82 VM* 50.57 ASH 2.61

Ultimate Analysis Ash Carbon Hydrogen Nitrogen Chlorine Sulfur Oxygen

0.91 65.4 4.4 0.6 0 0.3 29.3

*

39

FC: Fixed Carbon, VM: Volatile Matter, db: Dry basis

40 41 42

Table 2 Wet Victorian brown coal particle size distribution interval 1 2 3 4 5 6 7

lower limit (µm) 0 106 300 600 1000 4000 8000

upper limit (µm) 106 300 600 1000 4000 8000 20000

Weight fraction

cumulative weight fraction

0.085 0.228 0.202 0.02 0.167 0.137 0.161

0.085 0.313 0.515 0.535 0.702 0.839 1

43 44

34


Page 35 of 46 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

45

Table 3 A summary of process description and assumptions for each sub-section of the process

Process Section Pre-treatment (A-100)

Pyrolysis (A-200) PostSeparation (A-300)

Tar Upgrading (A-400) Energy production (A-500)

Coal Pre-Crushing

Blocked used in Aspen Plus CRUSHER

Coal Drying

FLASH2

Coal Crushing

CRUSHER

Coal Briquetting

GRANULATOR

Solid Conveyer

PUMP

Coal Pre-heating

HEX

Coal Pyrolysis Char and Gas Separation Char and Grus Separation Tar and NCG Separation

RYIELD

The coal was crushed to less than 6 mm in a rotary shear crusher The coal was dried in presence of a heating medium and moisture content was reduced to 15% The coal was crushed to less than 2 mm in an impact mill crusher The coal was briquetted under 120 MPa and 70 °C press pressure and temperature respectively The pressure drop in equipment was compensated using pump The coal was preheated using the outlet vapor of the pyrolysis reactor The yield of each product was defined based on pilot-plant test results

CYCLONE

The char was separated from gas phase using a cyclone

CLASSIFIER

The fine particles of char was separated from char product in a classifier

HEX and FLASH2

Ammonia Removal

RSTOIC

Tar Water Removal

DECANTER

Oil Upgrading

RADFRAC

Combustor

RGIBBS

A couple of HEX and Flash separators were used to condense the tar and separate it from non-condensable gases (NCG) A stoichiometric amount of sulfuric acid was added to precipitate ammonia as ammonia sulfate A decanter was used to separate the water from tar A distillation column was used to separate the light (tar) and heavy hydrocarbons (oil) A Gibbs reactor was used to calculate the heat of combustion

Boiler

HEX

A HEX was used to simulate creating steam using hot-flue gas

Function

Process Description and Assumptions

46 47

Table 4 The operating parameters implemented into the model for different drying scenarios Inlet steam/flue gas temperature (°C) Inlet steam /flue gas pressure (MPa) Outlet steam/flue gas temperature (°C) Outlet steam/flue gas pressure (MPa) Overall heat transfer coefficient (W/m2.k) Viscosity (Cp) Conductivity (W/m.K) Density (kg/m3)

Scenario 1 180 0.4 134.4 0.3 75 -

Scenario 2 280 0.3 113 0.15 -

Scenario 3 1350 0.11 232 0.1 0.039 0.089 0.283

Scenario 4 1350 0.11 88 0.1 -

48 49 50

Table 5 Gas composition of long residence time (H2 – rich) and short residence time (H2 – lean) cases

H2 - rich H2 - lean

H2

C1,C2

57 20

28 34

Gas composition (Vol%) CO CO2 6.5 17 35


2 29

N2

O2

4 0

0.5 0

Energy & Fuels 1 2 3 4 5 Table 6 Mass Balance of the overall system with the assumption of energy production from external sources 51 6 AMMONSUL CHARGRUS CL-GAS COLDCHAR GRUS OIL SULFACID TAR WASTWATR 7 8 Mass Flows (kg/h) 2256 20 470 3466 26 1100 9130 10001 2845 9 Composition (wt%) 10 COAL 0 0 0 0 0 87.6 0 0 0 11 WATER 2 7.4E-02 0 3.6E-01 0 12.1 Trace 2.0 99.3 12 H2 0 13 Trace 0 12.0 0 0 Trace 1.4E-03 Trace 14 N2 0 Trace 0 11.7 0 1.74E-01 Trace 2.3E-03 Trace 15 O2 0 Trace 0 1.7 0 1.57E-03 Trace 6.2E-04 Trace 16 CO 0 1.3E-04 0 16.8 0 0 Trace 3.6E-03 Trace 17 CO 0 4.4E-03 0 9.3 0 4.31E-02 Trace 3.4E-02 Trace 2 18 CH4 0 1.5E-03 0 39.2 0 0 Trace 2.5E-02 Trace 19 C2H6 0 20 2.5E-03 0 8.0 0 0 Trace 3.1E-02 Trace 21 S2O 0 0 0 0 0 2.21E-04 0 0 0 22 CHAR 0 0 100 0 100 0 0 0 3.8E-04 23 C6H6O 0 13.9 0 2.3E-01 0 0 2.9 75.6 6.6E-01 24 H S 0 1.2E-03 0 6.4E-01 0 0 Trace 6.3E-03 1.1E-04 2 25 NH3 0 0 0 0 0 Trace Trace Trace 1.7E-04 26 27 Naphthalene 0 2.6 0 4.5E-02 0 0 8.2 8.8E-01 Trace 28 H2SO4 98 Trace 0 4.8E-02 0 0 0 0 0 29 (NH4)2SO4 0 78.2 0 0 0 0 0 0 0 30 O-Cresol 0 5.3 0 2.7E-02 0 0 13.3 13.1 3.0E-02 31 N-OCT-01 0 1.5E-04 0 4.4E-04 0 0 75.5 8.3 0 32 ASH 0 0 0 0 0 6.10E-02 0 0 0 33 34 52 *Trace: Mass fractions smaller than 1E-05 35 36 37 38 39 40 41 42 43 44 ACS Paragon Plus Environment 45 46 47

Page 36 of 46

WETCOAL 70600 35 65 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Page 37 of 46 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

53 54

Table 7 Energy Balance of the overall system with the assumption of energy production from external sources Cooling Utilities

Energy (MW)

Briquette cooler Char Cooler Condenser 1 Condenser 2 Condenser 3 Oil Upgrading column condenser Total Cooling Utilities

-0.67 -3.95 -10.88 -1.18 -1.01 -0.09 -17.78

Heating Utilities

Energy (MW)

Pyrolysis Reactor Dryer Oil Upgrading column Reboiler Total Heating Utilities

37.86 32.27 0.5 70.63

Electricity

Energy (MW) 0.027 0.022 1.95 0.05 0.03 0.006 0.21 2.29

First Crusher Second Crusher Briquetting Rotary dryer motor Electric hoist Conveyor Belt Conveyors Dryer Air Blower Total Electricity 55 56


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 38 of 46

57 58

Table 8 Production rate and amount of coal gas and oil required to be burnt for energy production

Scenario 1 Scenario 2 Scenario 3 Scenario 4 59 60

Dryer type

Amount of coal gas required

Amount of tar and oil required

Indirect steam Direct steam Indirect flue gas Direct flue gas

58% 100% 58% 55%

35% -

Production Rate (t/h) Char

H2

9.95 0.41 9.91 0 9.95 0.41 10.00 0.44

C1, C2

Other gases

Oil & Tar

1.81 0 1.81 1.94

1.61 0 1.61 1.73

2.55 1.75 2.55 2.73

Total mass flow rates of products 16.3 11.7 16.3 16.8

Table 9 Comparison of the electricity consumption for the four drying scenarios Electricity consumption (MW)

Equipment First Crusher Second Crusher Briquetting Rotary dryer motor Electric hoist Conveyor Belt Conveyors Dryer Air Blower Boiler - Pyrolysis Air Blower Boiler - Dryer Air Blower Total Electricity required

Scenario 1

Scenario 2

Scenario 3

Scenario 4

0.027 0.022 1.95 0.067 0.03 0.006 0.205 0.562 0.379 3.25

0.027 0.022 1.95 0.05 0.03 0.006 0.539 1.418 4.04

0.027 0.022 1.95 0.067 0.03 0.006 0.205

0.027 0.022 1.95 0.05 0.03 0.006 -

0.701

0.620

3.01

2.71

61

38


Annual Product rate (kt/a) 131 93 131 135

Page 39 of 46 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 10 Comparison of CO2 emission from the process for different drying scenarios

62

Scenario 1

Scenario 2

Scenario 3

Scenario 4

161.60 2.84

232.89 0.00

161.60 2.84

153.24 3.04

30.39

37.83

28.15

25.32

17.54

17.54

17.54

17.54

212.37

288.26

210.13

199.14

Direct CO2 emissions CO2 emission from the flue gas (kt/a) CO2 emission from the gas product (kt/a) Indirect CO2 emissions CO2 emission from the electricity production (kt/a) CO2 emissions from coal mining and transportation (kt/a) Total CO2 emissions (kt/a) 63 64 65

Table 11 The amount of coal gas burnt and the production rate for two different coal gas composition Production rate (t/h)

H2 -rich H2 - lean 66

Amount of coal gas burnt 55% 87%

Char

H2

10.00 0.44 11.12 0.013

C1, C2

Other gases

Oil & Tar

Total mass flow rates of products

1.94 0.17

1.73 0.6

2.73 2.06

16.84 13.96

67 68

Table 12 CO2 emissions from the two processes with two different coal gas compositions

H2 - rich case

H2 - lean case

153.24

180.28

3.04

4.3

25.32

23.72

17.54

17.54

199.14

225.84

Direct CO2 emissions CO2 emission from the flue gas (kt/a) CO2 emission from the gas product (kt/a) Indirect CO2 emissions CO2 emission from the electricity production (kt/a) CO2 emissions from coal mining and transportation (kt/a) Total CO2 Emissions (kt/a) 69 70

39


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

71

Page 40 of 46

Table 13 Capital cost of base case scenario with the breakdown to its constitutes Capital cost items

Basis

Cost ($M ex. GST)

Direct Plant Costs Equipment Purchase Freight Direct equipment cost (DEC) Installation Instrumentation Minor piping Structural Electrical Buildings Yard Improvements Service Facilities HSE Functions

EPCa 10 % of EPC EPC + Freight 45 % of DECb 25 % of DEC 16 % of EPC 15% of EPC 25 % of DEC 25 % of EPC 15 % of EPC 40 % of EPC 10 % of EPC

8.6 0.9 9.5 4.3 2.4 1.4 1.3 2.4 2.2 1.3 3.4 0.9

Total Indirect Costs Engineering Supervision Legal Expenses Construction Expenses

50 % of DEC 4 % of DEC 40 % of DEC

4.7 0.4 3.8

8% of Direct plant cost + Total indirect costs

3.0

Working Capital Working Capital

41

Total Capital (ex GST)

72 73

a

: EPC: Equipment purchased cost, b: DEC: Direct equipment cost, c: Equipment purchase cost is derived from APEA

Table 14 Operating cost of base case scenario with the breakdown to its constitutes Item Raw Materials Coal Sulfuric acid (98%) Ethanol

Total cost ($M)

Assumptions

Price per unit

2.0 0.1 0.5

$3.5/t $313/t $813/t

Utilities Electricity Natural Gas Cooling water Air

2.2 0.1 0.1 0

$0.1/ kWh $5 /GJ $0.76/MWh Free

Total fixed charges Labor Maintenance and repairs Operating supplies Taxes (property) Insurance

3.4 2.0 0.4 0.8 0.4

5% of the total capital cost 1% of the total capital cost 2% of the total capital cost 1% of the total capital cost

Price per unit $25/t product NA NA NA NA

Depreciation & Capital Fixed Capital Depreciation Interest on capital Total Product Cost

2.0 2.0 16

5% of the total capital cost 5% of the total capital cost

NA NA

74 40


Page 41 of 46 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

75

Table 15 Financial indices calculated using the cash flow analysis for H2 – rich and H2 - lean cases

Net present value (NPV) $M Internal rate of return (IRR) % Payback period (Year)

H2 - rich

H2 - lean

52.8 25 5.1

42.9 23.9 5.5

76

41


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77 78 79

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Energy Evaluation and Techno-economic Analysis of Low-Rank Coal

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