Reduction in Natural Gas Consumption in Sulfur Recovery Units

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Reduction in natural gas consumption in sulfur recovery units through kinetic simulation using a detailed reaction mechanism Ramees K Rahman, Abhijeet Raj, Salisu Ibrahim, Ibrahim Khan M., and Nasser Omair Al Muhairi Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.7b04667 • Publication Date (Web): 16 Jan 2018 Downloaded from http://pubs.acs.org on January 16, 2018

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Industrial & Engineering Chemistry Research

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Reduction in natural gas consumption in sulfur recovery units through

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kinetic simulation using a detailed reaction mechanism

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Ramees K. Rahman1, Abhijeet Raj1,*, Salisu Ibrahim1, Ibrahim Khan M2, Nasser Omair Al

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Muhairi3 1

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Department of Chemical Engineering, The Petroleum Institute, Khalifa University of Science and Technology, P.O. Box 2533, Abu Dhabi, UAE

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Standards & Technology Division, Abu Dhabi Gas Industry Limited, ADNOC Gas Processing, P.O. Box 665, Abu Dhabi, UAE

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Operations Department, Abu Dhabi Gas Industry Limited, ADNOC Gas Processing, P.O. Box 665, Abu Dhabi, UAE

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Abstract

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H2S, a toxic gas present in raw natural gas and in oil fields, is converted to sulfur using the Claus

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process in sulfur recovery units. The low and fluctuating demand and sales price of sulfur and its

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increasing production due to the discovery of new sour fields have mandated optimization

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studies to reduce the production cost. Natural gas (mainly methane) is continuously co-fired with

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acid gas (H2S and CO2) in the Claus furnace to maintain temperatures above 1050°C, which adds

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to the operating cost. This study aims at reducing the usage of natural gas in sulfur recovery units

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using a detailed reaction mechanism for Claus feed combustion, while maintaining the desired

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furnace temperature. An optimal combination of feed-preheating using natural gas and its co-

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firing in the furnace is determined through furnace and fired heater simulations. A model for the

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feed pre-heater is developed using plant measurements. Through simulation studies by varying

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natural gas flow rates into the Claus furnace and to the air preheater, it is observed that (a) a

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considerable amount of natural gas can be saved to maintain the required furnace temperature, if

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air is preheated to a higher temperature rather than natural gas co-firing (also validated in an

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operational sulfur recovery plant), (b) a reduction in natural gas to the furnace improves the

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sulfur recovery efficiency, and (c) the destruction of aromatic contaminants (that are harmful for

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the catalysts present downstream) in the furnace is enhanced with decreasing natural gas co-

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firing and increasing feed temperature. The rate-of-production analysis is also presented to

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understand the chemical effects of natural gas in the furnace.

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Keywords: Natural gas; Claus process; SRU; Reaction mechanism; Process simulations.

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*

Corresponding author. E-mail address: [email protected]. Phone: +971-2-6075738

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1. Introduction

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H2S and CO2, collectively known as acid gas, are the main components of the byproduct streams

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from sour natural gas and oil fields 1. H2S is extremely toxic for living beings. An exposure to

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750 ppm of H2S is fatal for humans 2, and its maximum exposure limit is set to 10 3ppm. The

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strict environmental regulations in many countries on the emissions of H2S and sulfurous

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compounds to atmosphere have led to research activities to explore ways for its safe and

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economic disposal or utilization 4.

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One of the most widely used methods for converting H2S to economically valuable sulfur

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is the Claus process 5. Recent increases in the supply coupled with no substantial increase in the

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demand for sulfur have resulted in highly fluctuating (from $150/ton to $70/ton) and low sales

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prices for sulfur 6, which is expected to continue in the near future with the development of new 2 ACS Paragon Plus Environment

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sour gas fields. Thus, careful planning and cost management is required to address the present

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economics related to sulfur production. This demands the necessity to reduce the operating cost

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for sulfur production.

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Several innovative technologies have been proposed on H2S utilization to produce

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hydrogen and syngas along with sulfur. These include a recently proposed AG2S technology 7,

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the simultaneous recovery of sulfur and syngas from acid gas 8, the enhanced production of

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hydrogen from acid gas by process modifications 9 and by chemical and photochemical methods

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, and the catalytic conversion of SO2 to sulfur using carbon beds

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. However, Claus process remains to be the most widely used method for sulfur production.

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and Sn-Zr based catalysts

The Claus process in sulfur recovery units (SRUs) consists of a thermal section and a

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13

. The thermal section has a Claus furnace and a waste heat boiler (WHB)

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catalytic section

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Here, one-third of the H2S in the acid gas is converted to SO2 and water, as shown by reaction

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R1. This reaction is highly exothermic. As a result, the temperature in the Claus furnace rises to

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about 754-1027 °C. Sulfur is produced in this section by H2S pyrolysis

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reaction of SO2 with unreacted H2S, as shown by reaction R2

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highly equilibrium-limited, and the presence of water in acid gas feed decreases sulfur yield in

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sulfur recovery units17.

16

15

.

and through the

. The reactions, R1 and R2 are

H2S + 1.5O2 = SO2 + H2O

R1

2H2S + SO2 = 3/x Sx + 2H2O

R2

The WHB is a shell and tube heat exchanger used to recover heat from the combusted gas

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18

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temperature of the process gas inside the WHB reduces to 227-327 °C after heat transfer. The

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stream from the WHB mainly contains H2S, SO2, and sulfur. Sulfur is condensed and separated

to produce steam (at 40-60 barg), which can be used to preheat the acid gas stream. The



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in a condenser, where low pressure steam is generated. In the catalytic section, reaction R2 takes

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place in the presence of alumina-based catalysts at lower temperatures 19. The catalytic reactors

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are arranged in series to collectively enhance the sulfur recovery efficiency of the process to 94–

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97%20.

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Small amounts of hydrocarbons, COS, CO2, CS2, H2O, and monocyclic aromatics such as

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benzene, toluene, ethylbenzene and xylene (BTEX) are the major contaminants in the H2S feed

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stream to the Claus process. The aromatics are a major concern for the Claus catalytic units, as

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incomplete combustion tends to form soot particles 21 that clog the catalytic pores and deactivate

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them22, thus reducing the efficiency of the process23. Some of the BTEX

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CS2 25 are formed inside the furnace at Claus conditions, if hydrocarbons are present in the feed.

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as well as COS and

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To protect the downstream Claus catalysts, these contaminants must be destroyed inside

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the Claus furnace. This can be achieved by maintaining high reaction furnace temperatures. It

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has been established that, at 1050 °C, almost all benzene gets destructed while other monocyclic

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aromatics are destroyed at lower temperatures 26. This has necessitated many commercial SRUs

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to operate at temperatures above 1050°C. Several methods are proposed in the literature to

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increase the furnace temperature 27. Our previous work has shown that oxygen enrichment, feed

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preheating, and natural gas spiking can improve furnace temperature

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oxygen enrichment technique, an oxygen generation plant is required to enhance the oxygen

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content of air

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achieved through the use of a fired heater to preheat the feed streams using combusted gas or

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steam30. The limitation on feed preheating temperature is dictated by the material of construction

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of equipment and piping used in the SRU. For carbon steel piping, the maximum allowable

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working temperature is below 400°C based on the pipeline pressure

29

28

. To implement the

, which makes it impractical in most scenarios. Feed preheating can be easily


31

. Often acid gas is

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preheated using the steam recovered from the WHB1, while air is preheated in fired heaters

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The heat exchanger for preheating the acid gas stream is optimally designed in most commercial

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SRUs. Since the steam temperature from the WHB depends on its pressure, increasing the

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temperature of the acid gas stream beyond a limit is difficult, and requires modifications in the

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existing heat exchanger in the SRU. In contrast, air preheating in fired heaters provides

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operational flexibility, where the air temperature can be easily varied by varying the flow rate of

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the natural gas to the fired heater. A simplified schematic diagram showing the Claus furnace

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and the air preheater is shown in Figure 1.

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27

.

Many commercial SRUs use a natural gas stream (containing above 90% methane, and 32

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popularly referred to as fuel gas) along with acid gas

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1050°C to ensure BTEX destruction

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sudden fluctuations in the composition of acid gas. For example, when H2S concentrations dips

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to a low value, additional natural gas is supplied to sustain combustion in the furnace (and avoid

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any possible flame blow-off due to a low concentration of the reactants). However, a continuous

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usage of natural gas in the furnace only to maintain a high flame temperature increases the

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operational cost of the SRUs, and presents an opportunity, where the optimized process

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parameters could lead to cost reduction for sulfur production.

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to maintain furnace temperature above

. It is also required in many instances to deal with the

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Several studies are reported in the literature related to sulfur recovery process

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simulations17, optimization33, and data reconciliation34. Manenti35 published a study on the

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kinetic modeling of SRU using a detailed reaction mechanism consisting of 40 species and 150

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reactions for H2S coupled with a mechanism for pyrolysis and oxidation of light hydrocarbons.

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Nabikandi and Fatemi36 compared the performance of kinetic- and equilibrium- based models for

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Claus furnace simulations to predict species composition in the effluent gas from the furnace. 5 ACS Paragon Plus Environment


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The kinetic-based model predicted H2S to SO2 ratio with 0.2% deviation, while the equilibrium-

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based models showed a deviation of 3%. Many kinetic models in the literature utilize global

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reaction mechanisms with very few reactions that have fitted rate parameters obtained by

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comparing experimental data to the simulation results37. While such models provide good

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predictions in those cases that are close to the experimental conditions used for the reduced

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model development, they may not be suitable for (a) process optimization studies, where

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conditions may be varied significantly to achieve a target38, and (b) the prediction of chemical

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species in the furnace such as aromatics, whose production and destruction are kinetically

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controlled. Thus, reaction mechanisms with accurate kinetics, possibly obtained from first-

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principles, is desired. In our previous work 28, a detailed reaction mechanism was developed by

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considering combustion mechanism of each Claus feed component that did not have fitted

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parameters. It was validated using experimental data from several conditions such as reactors,

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premixed flame environments, and SRU plant data. Such models could be used for assessing the

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process parameters to determine the suitable conditions to reduce the operating cost of the SRUs.

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The objective of this study is to use a detailed reaction mechanism to minimize the

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consumption of natural gas in the furnace that is used to achieve sufficient furnace temperature

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for complete BTEX destruction in the Claus process. This will be achieved through an optimal

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distribution of natural gas to an air preheater and to the reaction furnace to achieve the desired

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flame temperature with a net saving of natural gas. The results from the successful

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implementation of this method in an SRU plant in United Arab Emirates will be presented. The

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reasons for the reduced requirement of the natural gas with the proposed method will also be

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discussed.

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2. Reaction Mechanism and Model Development 6 ACS Paragon Plus Environment

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A reliable reaction mechanism and a model are required for predicting the temperature and

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species concentrations in the Claus furnace with accuracy. Similarly, a robust model is required

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to predict the amount of natural gas consumed in preheating the air in the fired heater. The

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details on the mechanism and the models are provided below.

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2.1 Claus reaction furnace

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To model the reactions of the complex mixture of Claus feed inside the Claus furnace, a

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comprehensive reaction mechanism is required. The premixed feed includes various species such

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as H2S, BTEX, CH4, C2H6, C3H8, CO, CO2, H2, H2O, N2, and Ar. In our previous study

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detailed reaction mechanism, which included the combustion reactions of the feed components,

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was developed. This mechanism has three main components: (a) H2S pyrolysis and oxidation

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reactions, (b) the combustion reactions of aliphatic (C1-C4) and aromatic (BTEX) hydrocarbons,

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and (c) the formation and oxidation of PAHs up to coronene (C24H10) to account for the growth

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of aromatics in the anoxic regions of the furnace. The organosulfur species formed from the

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crosslinking of hydrocarbons and sulfurous compounds such as COS and CS2 were also

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included. In total, this mechanism had 314 species and 1984 reversible reactions. To ensure its

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reliability, it was extensively validated using different sets of experimental data from the

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premixed flames of benzene 39, toluene 40, ethylbenzene 41, xylene 42, methane 43 and H2S 44. The

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same mechanism is used for this study. The furnace and the WHB simulations were carried out

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using CHEMKIN PRO

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simulated as a plug flow reactor with adiabatic conditions46, and b) the WHB is modelled as a

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heat exchanger with overall heat transfer coefficient of 33 W/m2.K. Due to high Reynolds

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number, Peclet number and longer residence times (>1s), the fluid flow in the Claus furnace can

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be assumed to be fully developed and the molecular diffusion can be neglected. This partly

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28

,a

software with the following assumptions: a) the Claus furnace was



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justifies the assumption of simulating Claus furnace as a plug flow reactor, as stated by

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Manenti46. Since the furnace is protected by refractory lining, heat loss is assumed to be minimal,

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and it justifies the adiabatic plug flow reactor assumption46. The temperature in the furnace

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changes with distance, and after reaching its maximum value, the drop in its value in the latter

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part of the furnace is about 50 °C, mainly occurring due to the endothermic sulfur formation

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reactions.

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justification are provided in References 46 and 47, respectively.

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2.2 Fired heater (air preheater)

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In order to determine the amount of natural gas consumed for preheating the air, a satisfactory

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model is developed for the arbor-type fired heater using the plant data for about two years, as

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there are no well-established models or correlations for such fired heaters

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method of Lobo and Evans 49 predicts the fired heater performance with a maximum deviation of

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16%

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neglected

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is the molar flow rate of air, is the specific heat of air, and

and are the outlet

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and inlet air temperatures, respectively.

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Further details on these assumption for the furnace and the WHB, and their

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. The elaborate

. Since the heat transfer in fired heater is dominated by radiation, convection can be 50

. The rate of heat energy, qt, gained by the cold fluid (air), is given by Eq.1, where

=

−

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1

For the rate of heat transfer through radiation, Stephan-Boltzmann equation (Eq. 2) is used.

=

2

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Here, = (with emissivity, , Stephen-Boltzmann constant, , and effective surface area for

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radiation, A being constants for a given body at temperature, T). Considering a homogenous

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temperature in the fired heater at steady state, i.e., refractory walls being at flue gas exit 8 ACS Paragon Plus Environment

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, the rate of radiative heat transfer ( ) from the refractories to the tubes in the

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temperature

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radiant zone is found by Eq.3, where is the exiting flue gas temperature, and is the

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average temperature of the tubes.

= [ − ]

3

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At steady state, heat absorbed by the cold fluid is equal to heat radiated by the hot fluid. Thus,

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the value of c can be obtained using the plant data and Eq. 4.

=

−

4

[ − ]

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The average value of c ( ), obtained over the period of two years, is then used to find the flue

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gas exit temperature using Eq. 5.

&

−

=# + %

5

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Inside the air preheater, the heat generated by natural gas combustion is utilized for increasing

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the temperature of the cold fluid as well as the flue gas. Thus, an energy balance gives Eq. 7.

∆()* =

− + −

6

Here, is the molar flow rate of the natural gas, ∆()* is the heat of combustion for

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the natural gas, is molar flow rate of the flue gas generated from natural gas combustion,

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the natural gas to the fired heater. For the fired heater model, natural gas is considered to be

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composed of CH4 only, as it is the major component of natural gas. The complete combustion of

is the specific heat of the flue gas, and (= 45° or 318 K) is the inlet temperature of



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each mole of methane (CH4) requires 9.52 moles of air (since 2 moles of O2 will be present in

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9.52 moles of air, assuming that air has 21% O2), as shown by reaction R3 below. CH4+ 2(O2 + 3.76 N2) → CO2 + 2H2O+7.52N2

R3

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This reaction also gives us a relationship between the molar flow rates of the natural gas and the

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flue gas. In order to ensure complete combustion, 15 percent excess air is supplied to the fired

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heater, which results in Eq. 7 (where the factor, 11.948 comes from (1 + 0.15) × 9.52 moles of

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air + 1 mole of methane).

= 11.948

7

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Using Eqs. 6 and 7, a relationship between the molar flow rate of natural gas to the heater and

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the exiting flue gas temperature is obtained, as shown by Eq.8. After the successful validation of

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this model, it will be used to predict the natural gas flow rate required to reach a defined air

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temperature at the exit of the preheater.

=

−

5∆()* − 11.948 − 6

8

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3. Results and Discussion

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This section includes the validations of the reaction mechanism and the fired heater model

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developed in the previous section with the plant data, and the simulation studies conducted to

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reduce natural gas consumption in Claus process.

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3.1 Mechanism validation

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Since methane is the most dominant component of natural gas, and its combustion (along with

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other feed components) is particularly important for this study, the validation of the reaction

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mechanism in methane flames is necessary. However, it has already been carried out extensively 10 ACS Paragon Plus Environment

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in our previous works28, and therefore, further validation is not included in this paper. Since the

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optimization studies are to be carried out using the inlet condition of a SRU in Abu Dhabi, it is

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important to validate the mechanism against the plant data from an operating SRU. The

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dimensions of the SRU thermal section, simulated in this study, are provided in Table 1. Tables 2

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and 3 present the comparison of the simulated results using our reaction mechanism and the plant

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data for two cases, whose input conditions are detailed in Table S1. The plant data were available

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only at the WHB exit for case 1, whereas for case 2, plant data were available at the furnace exit

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as well as at the WHB exit. The assembly of the SRU plant does not allow online sensors to be

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inserted at different locations inside the furnace or the WHB. For both the cases, the results show

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that the model and the mechanism, used for Claus furnace and the WHB, can predict the species

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and the temperature profiles with reasonable accuracy. The temperature in the furnace rose to its

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maximum value near the burner due to H2S combustion, and was nearly uniform thereafter with

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only a slight reduction in it due to the endothermic reactions between H2S and SO2 to form

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sulfur. The sudden decrease in temperature in the WHB occurs due to heat exchange, which

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triggers the reaction between H2 and S2 to form H2S, and the conversion of sulfur allotropes (S1-

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S7) to their most stable form, S8. The S8 concentration was nearly zero in the furnace, as at high

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temperatures, S2 is the most stable form of sulfur

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diluents, but CO2 dissociation at high temperatures in the furnace to form CO (that led to a

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reduction in its concentration) cannot be ignored, as it leads to COS formation that reduces sulfur

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yield and burdens the tail gas treatment units 47.

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3.2 Fired heater model validation

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Figure 2 presents the comparison of exiting flue gas temperatures and natural gas flow rates

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measured in the plant over a period of two years with their computed values, and the calculated

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. The species, CO2 and N2 mostly act as



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values of the model parameter, c, obtained using Eq. 4 (and required in Eq. 5). The model

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parameter, c showed a near constant value over a time period of two years, and its average value

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shown by the orange line, was used in the model. Flue gas temperatures, predicted using Eq. 5

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for 2 years, showed a good match with their observed values in the plant, with a maximum error

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of 5.87%. Similarly, natural gas flow rate predicted by the model (Eq. 8) also shows a good

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congruence with their observed values over the same time period with a maximum error of

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4.47%. After validating the model with the plant data, further simulation studies were conducted

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to reduce the consumption of natural gas. Note that, the fitted model was validated over a flue

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gas temperature range of about 627-727°C, and a natural gas flow rate range of about 30-60

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kmol/h, and thus, its applicability is also limited by these ranges.

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3.3 Reduction in natural gas consumption

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The SRU considered in this study uses natural gas co-firing with acid gas (Figure 1) to reach the

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furnace temperature to the licensor-specified value of 1050°C. It is also equipped with an acid

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gas preheater and an air preheater to raise the feed inlet temperature. Acid gas preheater operates

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at its maximum possible capacity, as the temperature of steam (used as the hot fluid in the

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preheater) is limited by its pressure. Hence, there is no option to increase the acid gas

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temperature to affect the flame temperature in the furnace. However, the air preheater, which can

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preheat air to a maximum temperature of 380°C using natural gas for combustion, normally

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provides air at 330°C. Thus, it is possible to increase furnace temperature by varying air preheat

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temperature and study its effect on natural gas consumption. Note that the above-mentioned

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maximum temperature of 380°C is a metallurgical constraint due to the use of carbon steel pipes

253

(with a maximum design temperature of 400°C). The working temperature is kept 5% below the

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design temperature (i.e., at 380°C). 12 ACS Paragon Plus Environment

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The important points related to the optimization study are outlined below: •

A base case for simulations is chosen from the feed data from the SRU plant, and the feed

257

stream compositions for it are given in Table S2. The results from all the modification in

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the process parameters will be compared against this base case to analyze the potential

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for natural gas savings.

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•

In all the simulations, the H2S:SO2 ratio at WHB exit of the base case is maintained for

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the proper functioning of the catalytic units. This will also ensure that the same amount of

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H2S is oxidized in all cases and the temperature change is solely due to the change in the

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natural gas flow rate.

264

•

When natural gas, fed into the Claus furnace, is reduced to maintain the same H2S:SO2

265

ratio as the base case, air flow rate to the furnace is also reduced. This will bring down

266

the Claus furnace temperature. To reach the same furnace temperature as the base case,

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air is preheated to a higher temperature inside the air preheater. This will require

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increasing the natural gas flow rate into the air preheater.

269 270

•

The total amount of natural gas consumed in the base case and in the modified cases are compared to report the net natural gas savings.

271

Table S3 provides the flow rates of the feed streams (consisting of acid gas, air, and natural gas)

272

and their temperatures before they enter the furnace burner for four cases (a base case and three

273

additional cases with varying natural gas flow rate to the furnace). The additional cases are

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named as FG0 (no natural gas flow to the Claus furnace), FG90 (natural gas flow rate to the

275

furnace reduced to 90 % of natural gas flow rate in the base case), and FG75 (natural gas flow

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rate to the furnace reduced to 75% of natural gas flow rate in the base case). The reduced air flow

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rate requirement with the reduction in natural gas flow rate to the furnace can be noticed. 13 ACS Paragon Plus Environment


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Figure 3 provides the profiles of furnace temperature for the base case. It can be seen that

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the maximum flame temperature is about 1075 °C (~1348 K) inside the furnace, which is above

280

the minimum temperature of 1050 °C (~1323 K) required to destruct BTEX, as stated by Klint

281

26

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the air flow rate). The sulfur yield and the amount of BTEX at the WHB exit for this case will be

283

discussed later. Table S4 provides the natural gas consumption in the furnace and in the air

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preheater for different cases. For the base case, the total natural gas consumption is 1910 kg/h.

. The H2S to SO2 ratio is 2.9 (which will be maintained in other cases of Table S3 by adjusting

285

When the natural gas supply to the furnace is put to zero without changing any other

286

process parameters (FG0 case), it can be seen in Figure 3 that the temperature in most part of the

287

furnace dropped down below the recommended value of 1050 °C (~1323 K). This shows the

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important role of natural gas in maintaining the desired reaction furnace temperature. The

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temperature difference between the base case and FG0 was about 40 °C. Besides increasing the

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furnace temperature above the optimal BTEX destruction temperature, natural gas also helps in

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retaining the flame during process upsets (like intermittent lean H2S feed conditions). Thus,

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completely cutting off the natural gas supply to the furnace may not be a viable solution in some

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SRUs with fluctuating feed compositions. Moreover, after removing the natural gas supply to

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the furnace, even if the air preheat temperature is increased to 380 °C (i.e., the maximum value

295

from the preheater, as mentioned before), the maximum furnace temperature attainable would be

296

1047 °C (~1320 K) (which is below the temperature of 1050°C required for BTEX destruction).

297

In the view of the above arguments, for further cases, some natural gas supply to the furnace was

298

maintained.

299

In FG90 case (with natural gas flow rate to the furnace reduced to 90% of the base case),

300

to achieve a similar furnace temperature as the base case (as shown in Figure 3), air was 14 ACS Paragon Plus Environment

Page 14 of 36

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301

preheated to a higher temperature, which required additional natural gas injection to the air

302

preheater. Table S4 provides a comparison of natural gas consumption and air preheat

303

temperature requirement in the base case and in FG90 case. To maintain the furnace temperature

304

of the base case, FG90 case required air to be preheated to 345°C (instead of 325°C, required for

305

the base case). For this, the natural gas flow rate to the fired heater was increased from 577 to

306

629 kg/h. Thus, while the reduction in the natural gas flow rate to the furnace was 133 kg/h, only

307

52 kg/h of extra natural gas was added to the fired heater. This implies a natural gas saving of 81

308

kg/h.

309

In the same way, in FG75 case (with natural gas flow rate to the furnace reduced by 25%

310

from the base case), to achieve similar furnace temperatures as the base case (as shown in Figure

311

3), the air preheat temperature had to be increased to 360 °C, for which an increased natural gas

312

flow rate to the fired heater of 655 kg/h was required. Thus, while natural gas flow to the furnace

313

was reduced by 333 kg/h, only 78 kg/h of additional natural gas was injected to the fired heater.

314

This implies a natural gas saving of 255 kg/h.

315

Figure 4 shows the profiles of important species inside Claus furnace and WHB. The H2S

316

and SO2 profiles almost match in all cases. This ensures that same amount of H2S is oxidized in

317

all cases. It is evident that more amount of S2 is formed when no natural gas is fed into furnace

318

(FG0), which gets converted to S8 at a later stage in the WHB. Figure 5 shows the profiles of

319

CH4, H2, CO2, CO, COS and CS2. It can be seen that when the amount of natural gas fed into the

320

Claus furnace is reduced, the amount of CO, CS2 and COS formed reduces. The CO2 profile in

321

Figure 5 shows a high value for FG0 case. This is because a reduction in the flow rate of air into

322

the furnace for FG0 feed (to maintain H2S:SO2 ratio) increased the mole fraction of CO2 in the

323

feed mixture. 15 ACS Paragon Plus Environment


324

Along with natural gas savings, the process modifications discussed above had additional

325

advantages. Figure 6 presents the sulfur yield in the furnace (found as the ratio of mass of Sx (S1

326

to S8) species at the WHB exit to the mass of S in H2S at the inlet) and the mass of BTEX at the

327

exit of the WHB. Clearly, with decreasing amount of natural gas to the furnace, the sulfur yield

328

in the furnace improved, and the amount of BTEX escaping the thermal section of the SRU

329

reduced. The base case had a sulfur yield of about 52%, which increased to 56% in the absence

330

of the natural gas supply to the furnace. The mass of BTEX at exit of the WHB increased to 900

331

ppb from 500 ppb in the absence of natural gas in the furnace. The rate-of-production analysis

332

using the Chemkin software was conducted to determine the possible reasons for the observed

333

trends. Figure 7 presents the reaction pathways through which CH4 present in natural gas could

334

indulge in reactions with sulfurous compounds to form organosulfur species such as CS2 and

335

COS. Similar increase in COS formation is reported in an experimental study, where benzene

336

was added to H2S/O2 flame under Claus condition

337

hydrocarbon species to form COS and CS2 would lead to a reduction in sulfur yield or sulfur

338

recovery efficiency in the furnace. This explains the lower sulfur yield in FG90 and FG75 cases

339

in comparison to FG0 case. The unburnt CH4 molecules can also undergo pyrolysis reactions in

340

the high temperature environment of the Claus furnace to form larger hydrocarbons such as C2H2

341

and C3H3, which can form aromatic hydrocarbons such as BTEX 47. This explains the rise in the

342

amount of BTEX escaping the WHB to reach the catalytic units. The increased sulfur yield and

343

BTEX destruction with reduced natural gas to the furnace and increased natural gas to the air

344

preheater indicates that it is a better and economical solution for increasing furnace temperature

345

than natural gas co-firing alone.

52

. Such consumption of sulfur by

346


Page 16 of 36

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347

3.4 SRU plant testing

348

To confirm the above-predicted natural gas savings with the suggested process modification, an

349

SRU plant in UAE conducted a one-day test, which was repeated six times. Figure 8 presents the

350

plant data from six different runs, where the fluctuations in the Claus feed over different runs

351

triggered some variations in the observed data on furnace temperature and natural gas

352

requirements in the furnace and the air preheater. The feed stream composition, flow rates, and

353

temperatures are provided in Tables S5 and S6. The average values of the results, shown in

354

Figure 8, are discussed here. The Claus furnace temperature was maintained near 1100 °C by

355

increasing the air preheat temperature from 330 to 360 °C, which required increasing the natural

356

gas flow to the air preheater from 643 to 683 kg/h, and decreasing the natural gas flow rate to the

357

furnace from 1043 to 803 kg/h. Thus, an average natural gas saving of 200 kg/h was observed,

358

which validates our findings through simulations. Note that the amount of natural gas savings

359

varies with the perturbations in the feed conditions. The natural gas saving can be increased, if

360

air preheating beyond 360 °C is allowed by making necessary equipment modifications. An

361

operating cost saving of $0.6 million per year was estimated with these changes. As a further

362

validation of the model used in this work, Figure 9 presents a comparison of the natural gas

363

consumption predicted by the model with the actual consumption data from the plant for the

364

normal and the modified processes. It can be seen that the natural gas savings predicted through

365

simulation are in close agreement with the plant test results.

366

3.5 Analysis of natural gas saving

367

When natural gas is fed to the furnace, the heat energy released by its combustion is transferred

368

directly to the rest of the gas in the furnace, as they are in direct contact with each other (i.e., an

369

achievable efficiency of 100% in heat transfer). However, when the natural gas is burnt in an air 17 ACS Paragon Plus Environment


Page 18 of 36

370

preheater, its heat energy is indirectly transferred to air (across pipes) with an efficiency of about

371

70%. Thus, the observed natural gas savings in the previous section may appear counter-

372

intuitive. However, it should be noted that heat transfer is directly proportional to the

373

temperature difference between the hot and the cold fluid. A simple explanation is given below

374

on why less natural gas is used in the modified method, suggested in this work, for increasing

375

furnace temperature.

376

Assume that the same amount of natural gas is burnt in the furnace as well as in the fired heater

377

that would produce amount of flue gas. The amount of heat energy transferred by this flue

378

gas to the cold fluid can be estimated as (7 − ), where 7 is the adiabatic flame

379

temperature of the natural gas (methane), and is the exit temperature of the flue gas. The

380

adiabatic flame temperature of methane is 1827 °C (~2100 K)53. In the base case, the gas mixture

381

exits the furnace at 1075 °C (~1348 K). Thus, the energy transferred by the combusted natural

382

gas to the remaining gas mixture in the furnace is (2100-1348) = (792).

383

When the same amount of natural gas combusts in the air preheater, the flue gas exits the

384

preheater at 652 °C (~925 K). Thus, the energy lost by the combusted natural gas is

385

(2100-925). With 70% efficiency for the transfer of this heat energy to the cold fluid in

386

the tubes, the energy transferred to the air stream is 0.7 × (2100-925) =

387

(822.5). This shows that more amount of heat energy is transferred to the process stream, when

388

natural gas is supplied to the air preheater as compared to the furnace, and this would lead to a

389

higher temperature in the furnace.

390

In addition, the combustion of natural gas in the main reaction furnace takes place in the

391

presence of H2S. Thus, both H2S and CH4 in the natural gas compete for the available oxygen


Page 19 of 36 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


392

molecules. Since H2S is more reactive towards oxygen than methane, its combustion is preferred.

393

This leads to a partial combustion of natural gas when fed directly into the Claus furnace, and as

394

reported above, the pyrolysis of the remaining natural gas leads to the formation of larger

395

hydrocarbons/aromatics and organosulfur species in the furnace. Such competition for oxygen

396

among fuel molecules is not there in the air preheater, where only natural gas is burnt in excess

397

air.

398

4. Conclusion

399

A detailed Claus reaction mechanism, validated against plant data, was used to simulate an SRU

400

plant located in Abu Dhabi, UAE to improve the process conditions to reduce natural gas

401

(mainly methane) consumption in the unit. The plant used natural gas for co-firing in the furnace

402

to maintain the furnace temperature above the optimal temperature for BTEX destruction and in

403

the air preheater to raise the temperature of the inlet air stream. In this work, a modification is

404

suggested to increase the furnace temperature to a desired value with reduced consumption of

405

natural gas. The results show that a considerable amount of natural gas can be saved by

406

preheating air to a higher temperature rather than feeding natural gas directly into the reaction

407

furnace. A plant test, carried out in an operating SRU in Abu Dhabi, UAE, also shows a

408

considerable amount of natural gas savings that amount to a saving in the operating cost of about

409

$0.6 million per year. Additionally, with the suggested operational changes, an increase in the

410

sulfur yield and BTEX destruction in the furnace is observed due to less amount of hydrocarbons

411

in the furnace. This work illustrates the use of a detailed reaction mechanism for accurately

412

predicting Claus furnace parameters in commercial SRUs and for optimizing the process

413

parameters to save energy and operating costs.

414 19 ACS Paragon Plus Environment


415

Acknowledgments

416

This work has been financially supported by the Petroleum Institute Gas Processing and

417

Materials Science Research Center (GRC), Abu Dhabi, UAE.

418

Supporting Information

419

Tables S1-S6 showing the feed stream compositions, flow rates, physical parameters of the

420

furnace and the waste heat boiler, and the experimental data for model validation are provided in

421

the supporting information file.

422 423

References

424 425 426 427 428 429 430 431 432 433 434 435 436 437 438 439 440 441 442 443 444 445 446 447 448 449

1. Bahadori, A., Natural Gas Processing: Technology and Engineering Design Gulf Professional Publishing: 2014. 2. Milby, T. H.; Baselt, R. C., Hydrogen sulfide poisoning: clarification of some controversial issues. Am. J. Ind. Med. 1999, 35 (2), 192-195. 3. "Oil And Gas Well Drilling And Servicing Etool | General Safety And Health - H2S Special Precautions | Occupational Safety And Health Administration." Osha.gov. N.p., 2017. Web. 13 Aug. 2017. https://www.osha.gov/SLTC/etools/oilandgas/general_safety/h2s_precautions.html#low_hazard_area. 4. Guidotti, T. L., Occupational exposure to hydrogen sulfide in the sour gas industry: some unresolved issues. Int. Arch. Occup. Environ. Health 1994, 66 (3), 153-160. 5. Elsner, M. P.; Menge, M.; Müller, C.; Agar, D. W., The Claus process: teaching an old dog new tricks. Catal. Today 2003, 79–80, 487-494. 6. "World Sulphur Outlook To 2030 - Argus Media". Argusmedia.com. N.p., 2017. Web. 10 May 2017. 7. Bassani, A.; Pirola, C.; Maggio, E.; Pettinau, A.; Frau, C.; Bozzano, G.; Pierucci, S.; Ranzi, E.; Manenti, F., Acid Gas to Syngas (AG2S™) technology applied to solid fuel gasification: Cutting H2S and CO2 emissions by improving syngas production. Appl. Energy 2016, 184, 1284-1291. 8. Ibrahim, S.; Raj, A., Kinetic Simulation of Acid Gas (H2S and CO2) Destruction for Simultaneous Syngas and Sulfur Recovery. Ind. Eng. Chem. Res. 2016, 55 (24), 6743-6752. 9. Ravikumar, A.; Raj, A.; Ibrahim, S.; Rahman, R. K.; Al Shoaibi, A., Kinetic Simulations of H2 Production from H2S Pyrolysis in Sulfur Recovery Units Using a Detailed Reaction Mechanism. Energy Fuels 2016, 30 (12), 10823-10834. 10. Reverberi, A. P.; Klemeš, J. J.; Varbanov, P. S.; Fabiano, B., A review on hydrogen production from hydrogen sulphide by chemical and photochemical methods. J. Cleaner Prod. 2016, 136, 72-80. 11. Feng, T.; Huo, M.; Zhao, X.; Wang, T.; Xia, X.; Ma, C., Reduction of SO2 to elemental sulfur with H2 and mixed H2/CO gas in an activated carbon bed. Chem. Eng. Res. Des. 2017, 121, 191-199.


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12. Han, G. B.; Park, N.-K.; Yoon, S. H.; Lee, T. J.; Han, G. Y., Direct Reduction of Sulfur Dioxide to Elemental Sulfur with Hydrogen over Sn−Zr-Based Catalysts. Ind. Eng. Chem. Res. 2008, 47 (14), 46584664. 13. Butwell, K. F.; Dolan, W. B.; Kuznicki, S. M., Claus feed gas hydrocarbon removal. Google Patents: 2002. 14. Rameshni, M. In Dealing with impurities in sour gas field developments, Sulfur 2010 International Conference, Prague, 2010. 15. Binoist, M.; Labégorre, B.; Monnet, F.; Clark, P. D.; Dowling, N. I.; Huang, M.; Archambault, D.; Plasari, E.; Marquaire, P.-M., Kinetic Study of the Pyrolysis of H2S. Ind. Eng. Chem. Res. 2003, 42 (17), 3943-3951. 16. Jensen, A. B.; Webb, C., Treatment of H2S-containing gases: A review of microbiological alternatives. Enzyme Microb. Technol. 1995, 17 (1), 2-10. 17. Ibrahim, S.; Rahman, R. K.; Raj, A., Effects of H2O in the Feed of Sulfur Recovery Unit on Sulfur Production and Aromatics Emission from Claus Furnace. Ind. Eng. Chem. Res. 2017, 56 (41), 1171311725. 18. Nasato, L. V.; Karan, K.; Mehrotra, A. K.; Behie, L. A., Modeling reaction quench times in the waste heat boiler of a Claus plant. Ind. Eng. Chem. Res. 1994, 33 (1), 7-13. 19. PiÉPlu, A.; Saur, O.; Lavalley, J.-C.; Legendre, O.; NÉDez, C., Claus Catalysis and H2S Selective Oxidation. Cat. Rev. - Sci. Eng. 1998, 40 (4), 409-450. 20. Sassi, M.; Gupta, A. K., Sulfur recovery from acid gas using the Claus process and high temperature air combustion (HiTAC) technology. Am. J. Environ. Sci. 2008, 4 (5), 502. 21. Mak, J.; Nielsen, R. B.; Chow, T. K.; Morgan, O.; Wong, V. W., Methods and configurations for acid gas enrichment. Google Patents: 2009. 22. Crevier, P., Dowling, N., Clark, P., Huang, M. In Quantifying the Effect of Individual Aromatic Contaminants on Claus Catalyst, LRGCC Conf. Proc., February; 2001. 23. Crevier, P.; Dowling, N.; Clark, P.; Huang, M. In Performance of Commercial Titania and Titania Hybrid Catalysts in the Presence of Aromatic Contaminants, LRGCC Conf. Proc., 2005; p 145. 24. Mohammed, S.; Raj, A.; Al Shoaibi, A.; Sivashanmugam, P., Formation of polycyclic aromatic hydrocarbons in Claus process from contaminants in H2S feed gas. Chem. Eng. Sci. 2015, 137, 91-105. 25. Clark, P. D.; Dowling, N. I.; Huang, M.; Svrcek, W. Y.; Monnery, W. D., Mechanisms of CO and COS Formation in the Claus Furnace. Ind. Eng. Chem. Res. 2001, 40 (2), 497-508. 26. Klint, B. In Hydrocarbon Destruction in the Claus SRU Reaction Furnace, LRGCC Conf. Proc., 2000. 27. ZareNezhad, B.; Hosseinpour, N., Evaluation of different alternatives for increasing the reaction furnace temperature of Claus SRU by chemical equilibrium calculations. Appl. Therm. Eng. 2008, 28 (7), 738-744. 28. Rahman, R. K.; Ibrahim, S.; Raj, A., Oxidative destruction of monocyclic and polycyclic aromatic hydrocarbon (PAH) contaminants in sulfur recovery units. Chem. Eng. Sci. 2016, 155, 348-365. 29. Oxygen Based Claus Process for Recovery of Sulfur from H2S Gases. J. Environ. Eng. 1993, 119 (6), 1233-1251. 30. Kohl, A. L.; Nielsen, R., Gas purification Gulf Professional Publishing: 1997. 31. ASME B31.3: Process piping. New York : American Society of Mechanical Engineering: 2016. 32. Santo, S.; Rameshni, M., The challenges of designing grass root sulphur recovery units with a wide range of H2S concentration from natural gas. J. Nat. Gas Sci. Eng. 2014, 18, 137-148. 33. Manenti, F.; Papasidero, D.; Bozzano, G.; Ranzi, E., Model-based optimization of sulfur recovery units. Comput. Chem. Eng. 2014, 66, 244-251. 34. Signor, S.; Manenti, F.; Grottoli, M. G.; Fabbri, P.; Pierucci, S., Sulfur Recovery Units: Adaptive Simulation and Model Validation on an Industrial Plant. Ind. Eng. Chem. Res. 2010, 49 (12), 5714-5724.



497 498 499 500 501 502 503 504 505 506 507 508 509 510 511 512 513 514 515 516 517 518 519 520 521 522 523 524 525 526 527 528 529 530 531 532 533 534 535 536 537

35. Manenti, F.; Papasidero, D.; Frassoldati, A.; Bozzano, G.; Pierucci, S.; Ranzi, E., Multi-scale modeling of Claus thermal furnace and waste heat boiler using detailed kinetics. Comput. Chem. Eng. 2013, 59, 219-225. 36. Nabikandi, N. J.; Fatemi, S., Kinetic modelling of a commercial sulfur recovery unit based on Claus straight through process: Comparison with equilibrium model. J. Ind. Eng. Chem. 2015, 30, 50-63. 37. Zarei, S.; Ganji, H.; Sadi, M.; Rashidzadeh, M., Kinetic modeling and optimization of Claus reaction furnace. J. Nat. Gas Sci. Eng. 2016, 31, 747-757. 38. Gupta, A. K.; Ibrahim, S.; Al Shoaibi, A., Advances in sulfur chemistry for treatment of acid gases. Prog. Energy Combust. Sci. 2016, 54 (Supplement C), 65-92. 39. Yang, J.; Zhao, L.; Yuan, W.; Qi, F.; Li, Y., Experimental and kinetic modeling investigation on laminar premixed benzene flames with various equivalence ratios. Proc. Combust. Inst. 2015, 35 (1), 855-862. 40. Detilleux, V.; Vandooren, J., Experimental and Kinetic Modeling Evidences of a C7H6 Pathway in a Rich Toluene Flame. J. Phys. Chem. A 2009, 113 (41), 10913-10922. 41. Li, Y.; Cai, J.; Zhang, L.; Yang, J.; Wang, Z.; Qi, F., Experimental and modeling investigation on premixed ethylbenzene flames at low pressure. Proc. Combust. Inst. 2011, 33 (1), 617-624. 42. Zhao, L.; Cheng, Z.; Ye, L.; Zhang, F.; Zhang, L.; Qi, F.; Li, Y., Experimental and kinetic modeling study of premixed o-xylene flames. Proc. Combust. Inst. 2015, 35 (2), 1745-1752. 43. Pauwels, J.; Carlier, M.; Devolder, P.; Sochet, L., The influence of hydrogen sulfide on the combustion of methanol in a stoichiometric premixed flame. Experimental and numerical studies. Combust. Sci. Technol. 1992, 86 (1-6), 237-252. 44. Levy, A.; Merryman, E., The microstructure of hydrogen sulphide flames. Combust. Flame 1965, 9 (3), 229-240. 45. R. Design, "Chemkin-Pro Release 15142," Reaction Design, San Diego, CA, 2013. 46. Manenti, G.; Papasidero, D.; Manenti, F.; Bozzano, G.; Pierucci, S., Design of SRU Thermal Reactor and Waste Heat Boiler Considering Recombination Reactions. Procedia Engineering 2012, 42 (Supplement C), 376-383. 47. Mohammed, S.; Raj, A.; Al Shoaibi, A., Effects of fuel gas addition to Claus furnace on the formation of soot precursors. Combust. Flame 2016, 168, 240-254. 48. Couper, J. R.; Penney, W. R.; Fair, J. R., Chemical process equipment revised 2E: selection and design. Gulf Professional Publishing: 2009. 49. Lobo, W. E.; Evans, J., Heat transfer in the radiant section of petroleum heaters. Trans. Am. Inst. Chem. Engrs 1939, 35, 748-778. 50. Jegla, Z.; Vondál, J.; Hájek, J., Standards for fired heater design: An assessment based on computational modelling. Appl. Therm. Eng. 2015, 89, 1068-1078. 51. Meyer, B., Elemental sulfur. Chem. Rev. 1976, 76 (3), 367-388. 52. Ibrahim, S.; Al Shoaibi, A.; Gupta, A. K., Effect of benzene on product evolution in a H2S/O2 flame under Claus condition. Appl. Energy 2015, 145 (Supplement C), 21-26. 53. Lilley, D., Adiabatic Flame Temperature Calculation: A Simple Approach for General CHONS Fuels. In 42nd AIAA Aerospace Sciences Meeting and Exhibit American Institute of Aeronautics and Astronautics: 2004.

538 539


Page 22 of 36

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540


List of figures:

NATURAL GAS

NATURAL GAS

541 542

Figure 1. A schematic diagram showing Claus thermal section and air preheater in sulfur

543

recovery units (SRUs). The locations of natural gas injection in the SRU (i.e., in the fired heater

544

and in the furnace) are also shown.

545 546 547 548 549 550



0.06

C value (J/h-K4)

(a)

0.04

0.02 C value C average 0 1/1/2015

5/31/2015

10/28/2015

3/26/2016

8/23/2016

Date

(b) Flue gas temperature (K)

1200 1100 1000 900 800 700 600 1/1/2015

Sim

Plant data

5/31/2015

10/28/2015

3/26/2016

8/23/2016

Date

(c)

80

Natural gas flow rate (Kmol/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

Page 24 of 36

70 60 50 40 30 20 10 0 1/1/2015

Sim Plant data 7/20/2015

2/5/2016

8/23/2016

Date

551

Figure 2. (a) Calculated values of the model parameter, c, along with its average value used in

552

the model. (b and c) Comparison of the calculated and the observed values of flue gas

553

temperatures and natural gas flow rates for a time period of about 2 years.


Page 25 of 36

1400

1200

Temperature (K)

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


1000

Furnace

WHB

Base case FG0 FG75 FG90 BTEX Optimal

800

600 0

500

1000

1500

2000

Distance (cm)

554

555

Figure 3. Temperature profiles for different cases. The red line denoted by “BTEX optimal”

556

shows the minimum temperature required in the furnace for BTEX destruction.

557 558 559 560 561 562 563 564 565



0.10

0.40

Mole fraction

0.30 0.25 0.20

Furnace

Base case FG0 FG75 FG90

WHB

0.15

0.08

0.10

0.07 0.06


0.05

Furnace

0.04

WHB

0.03 0.02

0.05

0.01

0.00

0.00 0

1000

Distance (cm)

0

2000

0.10

1000

Distance (cm)

2000

0.05

S2

0.09

S8

0.08

0.04

0.07 0.06 0.05

WHB

Furnace

0.04


0.03 0.02 0.01

Mole fraction

Mole fraction

SO2

0.09

Mole fraction

H2 S

0.35

0.03

Furnace

0.02

WHB


0.01

0.00

0.00 0

1000

2000

0

Distance (cm)

1000

2000

Distance (cm)

0.10

0.30

O2

0.09

0.06 0.05

Furnace

0.03


0.02 0.01

WHB

Mole fraction

0.07

0.04

H2 O

0.25

0.08

Mole fraction

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 26 of 36

0.20 0.15

Furnace 0.10


0.05

0.00

WHB

0.00 0

1000

2000

0

Distance (cm)

1000

2000

Distance (cm)

566

Figure 4. Comparison of important species profiles inside the furnace and the WHB for different

567

cases (listed in Table S3).


Page 27 of 36

0.3

0.025

Mole fraction

0.015

Furnace


WHB

0.01

CO2

0.25

Mole fraction

CH4 0.02

0.2

0.15

0.005

Furnace 0.1

0 0

1000

2000

WHB


0.05

0

0

1000

Distance (cm)

2000

Distance (cm)

0.05

0.010

Mole fraction

0.03

Furnace

0.02


WHB

CS2 0.008

Mole fraction

CO 0.04

0.01

0.006 0.004

Furnace


WHB

0.002

0.00

0.000 0

1000

2000

0

Distance (cm)

1000

2000

Distance (cm)

0.10

0.010 0.008 0.006

Furnace

0.004


WHB

H2

0.09 0.08

Mole fraction

COS Mole fraction

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


0.07 0.06


0.05

Furnace

0.04

WHB

0.03 0.02

0.002

0.01 0.00

0.000 0

1000

Distance (cm)

0

2000


1000

Distance (cm)

2000


568

Figure 5. Profiles of methane and related species inside the furnace and the WHB for different

569

cases (listed in Table S3).

Mass of BTEX

Sulfur yield

900 800 700 600 500 400 300 200 100 0

57 56

Sulfur yield (%)

Mass of BTEX (PPB/hr)

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 36

55 54 53 52 51

Base Case

FG0

FG90

50

FG75

Base Case

Case

FG0

FG90

FG75

Case

570

Figure 6. Mass of BTEX exiting the thermal section of the SRU and sulfur yield for different

571

cases.

572 573 574 575 576 577 578 579 28 ACS Paragon Plus Environment

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580 581 582

583 584

Figure 7. A reaction flow diagram showing the reaction of CH4 and its radicals with S-

585

containing species to form CS2 and COS that reduce sulfur yield. 29 ACS Paragon Plus Environment


586 587 588

Temperature at furnace exit (K)

1400 1380 1360 Modified process

1340

Normal process

1320 1300 0

1

2

3

4

5

6

Run number

589 Modified process

1750

300

Normal process

1700

Fuel gas saving

250

1650 1600

200

1550 150 1500 1450

100

1400 50

Natural (fuel) gas saving (kg/h)

Total natural gas flow rate to preheater+furnace (kg/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

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1350 1300

0 1

2

3

4

5

6

Run number

590 591

Figure 8. SRU plant data (furnace temperature and total natural gas flow rate to the air

592

preheater and furnace) for the modified process (by modifying natural gas flow rates to the


Page 31 of 36

593

furnace and preheater) and with the normal process. Natural gas saving with the modified

594

process in different runs is shown.

595 596

2000

Plant data vs simulation

1900

Total natural gas flow rate to preheater+furnace (kg/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


1800 1700 1600 1500 1400 Normal process - Plant data

1300

Normal process - Sim 1200

Modified process - Plant data

1100

Modified process - Sim

1000 1

2

3

4

Run number


5

6


300 Plant data

Sim

250

Natural gas saving (kg/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

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200

150

100

50

0 1

2

3

4

5

6

Run number

597

Figure 9. Comparison of the model-predicted and experimentally observed total natural gas flow

598

rate required in the SRU and the natural gas savings in different test runs.


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599

List of tables

600

Table 1. Claus furnace and waste heat boiler (WHB) geometry details. Description

Value

Furnace data (cylindrical furnace with burner on the wall) Length

12.75 m

Diameter

6.66 m

Waste heat boiler data (shell and tube type heat exchanger with single tube pass) Length of tubes

9.25 m

Number of tubes

2500

Tube outer diameter

0.0635 m

Tube thickness

0.0045 m

601

602 603 604 605 606 607 608 609 610



611

Table 2. Validation for temperature and species mole fraction at WHB exit for validation case 1.

612

The inlet conditions are provided in Table S1 (Validation 1). Description Plant data Simulation Temperature (K) 593 540 Species mole fractions H2S 0.033 0.045 SO2 0.022 0.027 CO2 0.202 0.217 CO 0.021 0.022 H2 0.014 0.012 N2 0.421 0.413 AR 0.005 0.005 S2 0.000 0.000 S8 0.014 0.015 CS2 0.004 0.005 COS 0.007 0.002 H2O 0.252 0.234

613

614 615 616 617 618 619 620 621 622 623 624


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Page 35 of 36 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


625

Table 3. Validation for temperature and species mole fraction for validation case 2. The inlet

626

conditions are provided in Table S1 (Validation 2). Temperature and species mole fraction validation at furnace exit Plant Description data Simulation Temperature (K) 1400 1406 Species mole fractions H2S 0.031 0.033 SO2 0.032 0.034 CO2 0.160 0.166 CO 0.025 0.027 H2 0.018 0.018 N2 0.408 0.411 AR 0.005 0.005 S2 0.046 0.057 S8 0.000 0.000 CS2 0.015 0.000 COS 0.002 0.002 H2O 0.257 0.243

Temperature and species mole fraction validation at WHB exit Plant data

Description Simulation Temperature (K) 588 600 Species mole fractions H2S 0.033 0.041 SO2 0.029 0.036 CO2 0.170 0.174 CO 0.022 0.028 H2 0.014 0.013 N2 0.423 0.430 AR 0.005 0.005 S2 0.000 0.000 S8 0.008 0.014 CS2 0.016 0.000 COS 0.002 0.003 H2O 0.272 0.255

627

628



629

TOC Graphic

630

631


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Reduction in Natural Gas Consumption in Sulfur Recovery Units

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