A mesostructured Y zeolite as a superior FCC catalyst – from lab to refinery

CATEGORY: ZEOLITES
Chem. Commun., 2012,48, 11841-11843
A mesostructured Y zeolite as a superior FCC catalyst – from lab to refinery
Javier García-Martínez, Kunhao Li and Gautham Krishnaiah
Researchers prepared a mesostructured Y zeolite by a surfactant-templated process at commercial scale.  The zeolite was tested in a refinery, showing superior hydrothermal stability and catalytic cracking selectivity.
This demonstrates the promising future of mesoporous zeolites in large scale industrial applications.
Full Text Source (Subscription or Fee): http://pubs.rsc.org/en/content/articlelanding/2012/cc/c2cc35659g

Mobility Management in WSNs Using Fuzzy Logic: An Industrial Application Scenario

CATEGORY: WIRELESS NETWORKS
2012 IEEE 8th International Conference on Distributed Computing in Sensor Systems (DCOSS), 16-18 May 2012, Page: 284 - 286
Mobility Management in WSNs Using Fuzzy Logic: An Industrial Application Scenario
Zinonos, Z.
Chrysostomou, C. ;  Vassiliou, V.
Dept. of Comput. Sci., Univ. of Cyprus, Nicosia, Cyprus
Abstract
Mobility management in Wireless Sensor Networks is extremely impoertat for today's critical applications. Authors preset a soft mobility management solution in which mobility procedures are supported by fuzzy logic techniques.
They have designed and implemented a solution to support the movement of a mobile worker inside an oil refinery area. Results show that the proposed system provides high reliability and control over the handover actions.
Full Text Source (Subscription or Fee): http://ieeexplore.ieee.org/xpl/login.jsp?tp=&arnumber=6227753&url=http%3A%2F%2Fieeexplore.ieee.org%2Fxpls%2Fabs_all.jsp%3Farnumber%3D6227753

Applying Work Domain Analysis to Scope Micro- or Scaled World Simulator Design: A Petrochemical Domain Case Study

CATEGORY: SIMULATION
Proceedings of the Human Factors and Ergonomics Society Annual Meeting September 2012 vol. 56 no. 1 378-382
Applying Work Domain Analysis to Scope Micro- or Scaled World Simulator Design: A Petrochemical Domain Case Study
Antony Hilliard
University of Toronto, Toronto, Canada
Abstract
Interactive human-in-the-loop simulators are a cost-effective and safe way to train workers in challenging work situations, and to more tractably research human performance. However, because there are no systematic methods to guide simulator design, developing lower-fidelity microworld or scaled world simulators is difficult.
Authors describe how the modeling distinctions used in Work Domain Analysis (WDA) can be applied to support designers in making and explaining decisions on simulator scope. Three examples are demonstrated in a petrochemical case study.
Full Text Source (Subscription or Fee): http://pro.sagepub.com/content/56/1/378.short

Refining Structures Optimization

CATEGORY: REFINERY OPTIMIZATION
EngOpt 2012 – 3rd International Conference on Engineering Optimization, Rio de Janeiro, Brazil, 01 - 05 July 2012.
Refining Structures Optimization
M. A. Beltrán Marín 1, V. Kafarov 2, C. A. Mahecha Bohorquez 3
1 Universidad Industrial de Santander (UIS), Research Center for Sustainable Development in Industry and Energy - CIDES, Bucaramanga, Colombia
mianbem@gmail.com
2 Professor of chemistry engineering, UIS. Research Center CIDES – kafarov@uis.edu.co
3Empresa Colombiana de Petróleos (ECOPETROL S.A.)-ICP, Bucaramanga, Colombia
 cesaraugusto.mahecha@ecopetrol.com.co
Abstract
Optimization techniques applied to the oil industry have been developed at different levels of design, planning and scheduling, and at different scales (macro, meso and micro scale). These techniques deal with environmental issues, operation optimization and energy analysis. Moreover, they consider several factors, from an economic perspective, since their goal could be: maximization of profits, net present value, IRR (Internal Rate Revenue), and minimization of different cost types. To achieve these goals, different programming techniques are used, including: mixed integer linear programming (MILP), mixed integer nonlinear programming (MINLP), generalized disjunctive programming (DGP), Benders decomposition, and cutting plane method, and so on. In order to compile the main financial criteria used in literature on refining structures optimization, this paper discusses different financial criteria used at macro scale for design and planning of refineries. It could be applied on further works focusing on selecting alternative investment in petrochemical refining structures. Introduction The optimization of refining schemes is based upon process synthesis. This paper uses mathematical programming approach and a financial criteria analysis, used for synthesis and planning considering mainly MILP optimization models. Initially, there is a revision of previous works supporting process design focused on mathematical programming, where the incorporation of logic-based methods are observed, promoting the definition and the use of superstructures. Besides, those works show term definitions such as: State Tasks Network STN, State Equipment Network SEN, Disjunctive Normal Form DNF, Conjunctive Normal Form CFN, Value on Processing VOP, Cost of Production COP, among others. Moreover, some relevant works on financial criteria are also studied, specifically those where a vast quantity of options for the selection of a financial criterion is observed. Finally, works on optimization of oil refining schemes at synthesis and planning levels are collected; where the objective function for each one of the cases is given a careful attention.
Free Full Text Source: http://www.engopt.org/paper/287.pdf

Microcontroller System for Oil Refinery Parameters Measurements Based on Piezoresistive and Strain Gauge Pressure Sensors

CATEGORY: PRESSURE SENSORS
Applied Mechanics and Materials (Volumes 249 - 250), Pages 1133-1138, December, 2012
Microcontroller System for Oil Refinery Parameters Measurements Based on Piezoresistive and Strain Gauge Pressure Sensors
Iman Morsi, Loay Mohy El Din Rasheed
Abstract
A typical oil refinery has a number of physical parameters that need to be measured, including pressure, flow rate and level. Authors built a microcontroller system based on PIC 16F877A, piezoresistive differential pressure DP sensor (24PC series) and strain gauge DP sensor (IDP-10) with ranges from 0 to 15psi.
The results of the microcontroller system revealed the following: the percentage error for piezoresistive sensor in pressure from 0.43808% to 8.613 %, in flow rate from 0.21929% to 20.340%, and in level from 0.43808% to 2.5789%. The percentage error for strain gauge sensor from 0.846% to 1.946% for pressure measurement, from 0.1% to 0.4% for flow rate measurement and from 0% to 0.64% for level measurement. The percentage error of the piezoresistive sensor is more than the percentage error of the strain gauge sensor: for pressure measurement by about 6.667%, for flow rate measurement by about 19.94% and for level measurement by about 1.9389%. Fuzzy logic is used to predict the output surface of pressure, flow rate, and level measurements.
Full Text Source (Subscription or Fee): http://www.scientific.net/AMM.249-250.1133

Novel method for targeting the optimal purification feed flow rate of hydrogen network with purification reuse/recycle

CATEGORY: HYDROGEN
AIChE Journal, Early View (Online Version of Record published before inclusion in an issue), Article first published online: 30 NOV 2012
Novel method for targeting the optimal purification feed flow rate of hydrogen network with purification reuse/recycle
Guilian Liu 1,*, Hao Li 2, Xiao Feng 1, Chun Deng 3
Abstract
The purification reuse/recycle is an effective resource conservation strategy. Authors propose a novel method to identify the optimal purification feed flow rate (PFFR) and the corresponding maximum hydrogen utility savings (HUS) of the hydrogen network with purification reuse/recycle.
The method divides sources and sink-tie-lines into three regions according to the purified product and purification feed. Authors analyzed the quantitative relationship between the HUS and the PFFR for the sink-tie-lines and sources of each region. With the quantitative relationship line between the HUS and the PFFR of each source plotted, the quantitative relationship diagram can be obtained and can be used to identify the pinch point and the HUS for a given PFFR. Furthermore, the optimal PFFR and the maximum HUS can be identified easily. Three cases are presented to illustrate the applicability of the proposed method
Full Text Source (Subscription or Fee): http://onlinelibrary.wiley.com/doi/10.1002/aic.13962/abstract;jsessionid=D57025C4A89C75F8037C4A1063F90CC7.d02t01?deniedAccessCustomisedMessage=&userIsAuthenticated=false

Heavy Hydrocarbon Reactor

CATEGORY: HEAVY CRUDE
PATENT
Heavy Hydrocarbon Reactor
United States Patent Application 20120267286
Inventors:
Salazar-guillen, Jose Armando (Reno, NV, US)
Ard, Christopher (Catlettsburg, KY, US)
Application Number:
13/292747
Publication Date:
10/25/2012
Assignee:
MARATHON OIL CANADA COMPANY (Calgary, CA)
Abstract:
A reactor for cracking heavy hydrocarbons includes a tube having an internal passage filled with a fluid that includes heavy hydrocarbon material. The reactor is oriented vertically so that the fluid moves downward through the internal passage of the tube. The internal passage includes alternating linear sections and curved sections. The internal passage is oriented so that it lies on a single plane. The reactor may be combined with another reactor to produce a reactor system.
BACKGROUND
Since different crude oils yield different distillation products, oil refining requires balancing product yield with market demand. Balancing these two without manufacturing large quantities of low value fractions requires processes for converting hydrocarbons of one molecular weight range and/or structure into those of another molecular weight range and/or structure. The basic processes for doing this are commonly referred to as cracking processes. This is because the relatively high boiling constituents are cracked, that is, thermally decomposed, into lower molecular weight, smaller, lower boiling molecules.
Conventional thermal cracking is the thermal decomposition of high molecular weight constituents (higher molecular weight and higher boiling than gasoline constituents) to form lower molecular weight (and lower boiling) species. Many of these processes use catalysts to crack residual and other heavy feedstocks, alkylation, polymerization, and isomerization. Catalytic cracking is one of the leading processes for upgrading lighter oils (e.g., conventional crude oil) into high quality fuel. Hydrocracking, a catalytic cracking process conducted in the presence of hydrogen, is especially suitable for producing yielding gasoline and/or jet fuels.
The discovery of huge reserves of heavy oil has attracted renewed interest in thermal cracking processes. Thermal cracking processes such as visbreaking, an abbreviated term for viscosity breaking or viscosity lowering, are used to convert heavy, high viscosity, high boiling hydrocarbons to lower viscosity fractions suitable for further processing or use in heavy fuel oil. These processes may accomplish one or more of the following objectives. First, they reduce the viscosity of the feed stream, which may include heavy hydrocarbon sources such as the residue from distillation operations, the residue from hydroskimming operations, natural bitumen from sources such as tar sands, and even certain high viscosity crude oils. Second, they reduce the amount of residual fuel oil produced in a refinery, which is generally regarded as a low value product. Third, they increase the proportion of middle distillates produced in the refinery. Middle distillates are often used as a diluent for heavy hydrocarbons to lower their viscosity to a marketable level. Cracking the residual hydrocarbons reduces the diluent requirement so that the saved middle distillates can be diverted to higher value products.
In one example of a process for cracking heavy hydrocarbon material such as those mentioned above, the feed is passed through one or more tubes in a furnace. The heavy hydrocarbon material is heated to a high temperature causing partial vaporization and mild cracking Conversion is achieved primarily as a result of temperature and residence time, which is why this process is described as being high temperature (e.g., 455 to 510° C.) and short residence time. The short residence time is the principal reason that this is considered a mild thermal reaction. The product that exits the tube is quenched to halt the cracking reactions. This may be done by heat exchange with the feed material, which saves energy, or with a stream of cold material such as gas oil to achieve the same effect.
These processes extend the boiling range of the heavy hydrocarbon materials so that light and heavy gas oils can be fractionated from the product stream, fed into a catalytic cracking unit, or otherwise processed further as desired. The yield of the various hydrocarbon products depends on the “severity” of the cracking operation as determined by the temperature the feed is heated to in the furnace. At the low end of the scale, a furnace operating at 425° C. would crack only mildly, while operations at 500° C. would be considered as very severe. Arabian light crude residue cracked at 450° C. would yield around 76 wt % tar, 15 wt % middle distillates, 6 wt % gasolines and 3 wt % gas and LPG.
One problem commonly encountered when cracking heavy hydrocarbon materials is excessive coke formation. As thermal cracking proceeds, reactive unsaturated molecules are formed that continue to react and can ultimately create higher molecular weight species that are relatively hydrogen deficient and readily form coke. The coke is deposited on the cracking equipment and leads to fouling and necessitates frequent cleaning. This is especially a problem in tubular reactors. The coke is deposited in the reaction tubes and eventually fouls or blocks them. Tubular reactors require frequent de-coking, which is labor intensive and can result in substantial downtime.
Another disadvantage of processes for cracking heavy hydrocarbon material is that, unlike conventional thermal cracking, they do not employ a recycle stream. Conditions are too mild to crack a gas oil recycle stream, and the unconverted heavy hydrocarbon material, if recycled, would cause excessive coking. Further cracking of the residuals must be done in a separate unit that can remove the very heavy fractions that are left.
Processes for cracking heavy hydrocarbon material also produce a significant amount of gaseous hydrocarbons as a by-product. Although these can be separated for other uses, it is preferable to limit the amount of gases produced to maximize liquid yields.
SUMMARY
Disclosed below are representative embodiments that are not intended to be limiting in any way. Instead, the present disclosure is directed toward novel and nonobvious features, aspects, and equivalents of the embodiments of the methods described below. The disclosed features and aspects of the embodiments can be used alone or in various novel and nonobvious combinations and sub-combinations with one another.
A reactor for cracking heavy hydrocarbon material into distillates includes a tube having an internal passage through which the heavy hydrocarbon material passes. The heavy hydrocarbon undergoes cracking reactions as it travels through the reactor thereby producing the distillates. The heavy hydrocarbon can react with a cracking fluid in the reactor that facilitates the cracking reactions.
The reactor may be oriented vertically so that the fluid in the reactor moves downward through the internal passage. Although the reactor is oriented vertically, the internal passage may lie substantially on a plane so that the reactor appears to be flat. The internal passage may include alternating linear sections and curved sections that form a zig-zag or serpentine shape. The tube can be at least approximately 6 inches in width. In one embodiment, the internal passage has a cylindrical shape and its diameter is at least approximately 6 inches.
The reactor can be used as part of a method for cracking the heavy hydrocarbon material and forming distillates. The method includes reacting the heavy hydrocarbon material with a cracking fluid such as steam or natural gas in the reactor. The temperature and residence time of the heavy hydrocarbon material is sufficient to convert a substantial amount of it to distillates. The residence time and linear velocity of the fluid in the reactor may be approximately 0.05 s to 1.5 s and approximately 4 to 40 m/s, respectively.
In one embodiment, the reactor is part of a multiple reactor system for cracking heavy hydrocarbon material. The reactor is the second reactor in the system and is positioned in series after a first reactor. The heavy hydrocarbon material begins to crack in the first reactor into lighter hydrocarbon material. The second reactor provides the residence time at high temperature that further drives conversion of the heavy hydrocarbon material into distillates.
The first reactor may be a nozzle reactor. The cracking fluid is accelerated to supersonic speed in the nozzle reactor and mixed with the heavy hydrocarbon material in the feed to initiate cracking. The cracking fluid functions as a hydrogen source thereby minimizing coke formation due to excessive hydrogen loss from the heavy hydrocarbon material.
The effluent from the second reactor is separated to isolate any remaining heavy hydrocarbon material. The heavy hydrocarbon material may be recycled back to the first reactor until it is completely eliminated. The recycled heavy hydrocarbon material does not produce significant amounts of coke due to the hydrogen rich environment supplied by the cracking fluid. The entire process may be operated without the use of a catalyst or added hydrogen.
In one embodiment, the raw feed is combined with the effluent from the second reactor and separated into distillates and heavy hydrocarbon material. Any suitable separation process may be used such as distillation. The distillates continue on to further processing and the heavy hydrocarbon material is fed into the reactor system. This design allows the distillates from the feed and the reactor effluent to be separated in a single step with the same separation unit. It also increases the concentration of heavy hydrocarbon material in the feed to the reactor system.
In another embodiment, the raw feed may be fed directly into the reactor system before being separated into its constituent fractions. For example, this may be desirable when the raw feed is largely made up of heavy hydrocarbon material. A variety of other configurations may also be used. For example, the raw feed may be separated in a first separation unit, the heavy hydrocarbon material fed into the reactor system, and the effluent separated in a second separation unit.
The term “heavy hydrocarbon material” is used to refer to the hydrocarbon fraction that has a boiling point at or above 525° C. This material may be obtained from a number of sources such as the residue from distillation operations such as atmospheric or vacuum distillation, the residue from hydroskimming operations, natural sources such as tar sands (including oil sands and oil shale), and even certain high viscosity crude oils. The term “distillates” is used to refer to the hydrocarbon fraction that has a boiling point below 525° C. The term “coke precursor” is used to refer to carbon based material that is not soluble in toluene. It should be appreciated that all pressures are given as gauge pressures unless noted otherwise.
The foregoing and other features, utilities, and advantages of the subject matter described herein will be apparent from the following more particular description of certain embodiments as illustrated in the accompanying drawings. In this regard, it is be understood that the scope of the invention is to be determined by the claims as issued and not by whether any given subject matter includes any or all features or aspects noted in this Summary or addresses any issues noted in the Background.
Free Full Text Source: http://www.freepatentsonline.com/y2012/0267286.html

A novel optimization approach of improving energy recovery in retrofitting heat exchanger network with exchanger details

CATEGORY: HEAT EXCHANGERS
Energy, Available online 7 December 2012, In Press, Corrected Proof
A novel optimization approach of improving energy recovery in retrofitting heat exchanger network with exchanger details
Ming Pan, Robin Smith, Igor Bulatov
Centre for Process Integration, School of Chemical Engineering and Analytical Science, The University of Manchester, Manchester M13 9PL, United Kingdom
Abstract
There is increasing interest in improving energy recovery with retrofitting heat exchanger network. Authors present a novel optimization method for dealing with the main exchanger geometry details in HEN retrofit problems.
The addressed details of shell and tube exchangers include tube passes, shell passes, heat transfer intensification, logarithmic mean temperature difference (LMTD), and LMTD correction factor (FT), which are systematically identified under given objective function and topological constraints in the existing heat recovery systems. Based on the recent works proposed by Pan et al. on HEN retrofit scenarios addressing network topology modification, an efficient optimization framework, consisting of two optimization stages with the implementation of MILP-based iterative method, was developed to deal with the computational difficulties associated with the nonlinearity of LMTD and FT.  A case study from literature examples was conducted to demonstrate the validity and soundness of the proposed approach, showing that the new proposed approach is able to provide realistic and practical solutions for debottlenecking of HEN with systematic consideration of exchanger details.
Full Text Source (Subscription or Fee): http://www.sciencedirect.com/science/article/pii/S0360544212008365

Novel natural gas to liquids (GTL) processes: Process synthesis and global optimization strategies†

CATEGORY: GTL – GAS TO LIQUIDS
AIChE Journal, Accepted Article (Accepted, unedited articles published online and citable. The final edited and typeset version of record will appear in future.) 12 DEC 2012
Novel natural gas to liquids (GTL) processes: Process synthesis and global optimization strategies†
Richard C. Baliban, Josephine A. Elia, Christodoulos A. Floudas‡,*
floudas@titan.princeton.edu
Department of Chemical and Biological Engineering, Princeton University, Princeton, NJ 08544, USA
Abstract
Authors propose an optimization-based process synthesis framework for the conversion of natural gas to liquid transportation fuels.  They compared natural gas conversion technologies including steam reforming, auto-thermal reforming, partial oxidation to methanol, and oxidative coupling to olefins to determine the most economic processing pathway.
They produced hydrocarbons from Fischer-Tropsch conversion of syngas, ZSM-5 catalytic conversion of methanol, or direct natural gas conversion.  They studied multiple Fischer-Tropsch units with different temperatures, catalyst types, and hydrocarbon effluent compositions.  They generated gasoline, diesel, and kerosene through upgrading units involving carbon-number fractionation or ZSM-5 catalytic conversion.  They introduce a powerful deterministic global optimization method to solve the mixed-integer nonlinear optimization model that includes simultaneous heat, power, and water integration.  They analyzed twenty-four case studies to determine the effect of refinery capacity, liquid fuel composition, and natural gas conversion technology on the overall system cost, the process material/energy balances, and the lifecycle greenhouse gas emissions
Full Text Source (Subscription or Fee): http://onlinelibrary.wiley.com/doi/10.1002/aic.13996/abstract

Influence of Cathodal Performance on Electricity Generation of Microbial Fuel Cell with Refinery Oil Wastewater as Fuel

CATEGORY: FUEL CELLS
Advanced Materials Research (Volume 599), Pages 582-585, November, 2012
Influence of Cathodal Performance on Electricity Generation of Microbial Fuel Cell with Refinery Oil Wastewater as Fuel
Xuan Guo, Ya Li Zhan, Shao Hui Guo, Guang Xu Yan, Su Xiu Sun, Li Jie Zhao, Rong Mei Geng
Abstract
Authors constructed a double-chambered microbial fuel cell (MFC) to investigate the feasibility of electricity generation using microbial fuel cell with refinery oil wastewater as its fuel and the influence of cathodal performance. Results suggest that refinery oil wastewater could be used as fuel in MFCs to generate electricity.
Catholyte type could influence the electricity generation of MFCs directly and Fe (Ⅲ)-EDTA was the best choice, voltage generation and stable operational period of which were highest and longest; voltage generation increased following with catholyte concentration linear but had little relation to cathode areas.
Full Text Source (Subscription or Fee): http://www.scientific.net/AMR.599.582

Complexity-based methodology for Fault Diagnosis: application on a centrifugal machine

CATEGORY: FAULT DIAGNOSIS
Complexity-based methodology for Fault Diagnosis: application on a centrifugal machine
S. M. Zanoli*, G. Astolfi*, J. Marczyk**
*D.I.I., Università Politecnica delle Marche, Ancona, Italy
(s.zanoli@univpm.it, g.astolfi@univpm.it )
** Ontonix s.r.l. – Complexity management
(jacek@ontonix.com )
Abstract:
Presents a novel approach for the detection and the isolation of typical faults in oil refinery plants is presented. The proposed approach is based on a complexity-based methodology that allows monitoring a complex system by a holistic vision and provides a metric for the complexity measurements of the system.
Authors considered applications for FDI of a centrifugal compressor. Because this metric resulted sensitive to change in the operative conditions of the plant under study, for Fault Diagnosis purposes, a proper filtering procedure was developed. System data relative to different operative conditions were clustered and the information was used to discriminate between variations of the complexity measure due to system failure from the one strictly related to changes in the operative conditions. The validity of the proposed method was tested on real data concerning a fault occurred in a centrifugal compressor located in the Air Separation Unit (ASU) of a refinement plant.
Free Full Text Source: http://www.design4resilience.com/ardocCM/files/5/file/CHAOS12_0060_FI.pdf

A data-driven rolling-horizon online scheduling model for diesel production of a real-world refinery

CATEGORY: DIESEL
AIChE Journal, Early View (Online Version of Record published before inclusion in an issue), Article first published online: 28 SEP 2012
A data-driven rolling-horizon online scheduling model for diesel production of a real-world refinery
Cao Cuiwen 1,*, Gu Xingsheng 1, Xin Zhong 2
caocuiwen@ecust.edu.cn
1 Key Laboratory of Advanced Control and Optimization for Chemical Processes, Ministry of Education, East China University of Science and Technology, Shanghai 200237, P.R. China
2 State Key Laboratory of Chemical Engineering, School of Chemical Engineering, East China University of Science and Technology, Shanghai 200237, P.R.
Abstract
Describes a rolling-horizon optimal control strategy, developed to solve the online scheduling problem for a real-world refinery diesel production based on a data-driven model, using a mixed-integer nonlinear programming (MINLP) scheduling model considering the implementation of nonlinear blending quality relations and quantity conservation principles.
The data variations which drive the MINLP model come from different sources of certain and uncertain events. The scheduling time horizon is divided into equivalent discrete time intervals, which describe regular production and continuous time intervals which represent the beginning and ending time of expected and unexpected events that are not restricted to the boundaries of discrete time intervals. This rolling-horizon optimal control strategy ensures the dimension of the diesel online scheduling model can be accepted in industry use. LINGO is selected to be the solution software. The daily diesel scheduling scheme of one entire month for a real-world refinery is effectively solved.
Full Text Source (Subscription or Fee): http://onlinelibrary.wiley.com/doi/10.1002/aic.13895/abstract

Sonocatalytic Oxidative Desulfurization of Thiophene and Its Derivatives

CATEGORY: DESULFURIZATION
Procedia Engineering, Volume 42, 2012, Pages 1711–1719
Sonocatalytic Oxidative Desulfurization of Thiophene and Its Derivatives
A. Tugrul Albayrak, M. Ali Gurkaynak
University of Istanbul, Engineering Faculty, Department of Chemical Engineering, Istanbul, Avcilar 34320, Turkey
Abstract
Currently, the sulfur level in diesels is limited to 10 and 15 ppm in Europe and USA respectively, since the organosulfur compounds available in fuels emit corrosive SO2 gases into atmosphere during combustion, thus leading to acid rain. A lot of processes such as hydrodesulfurization (HDS), oxidative desulfurization (ODS) etc. have been used to reduce sulfur level in fuels and ODS, which is alternative to conventional HDS, is much more efficient in removing benzothiophene (BT), dibenzothiophene (DBT) and their alkyl derivatives as compared with HDS and more economical. One of very powerful oxidation systems used in ODS is H2O2-formic acid and removal of alkyl-substituted derivatives of T, BT and DBT with this oxidation system is easier than that with H2O2-phosphotungstic acid catalyst system due to the steric hindrance of alkyl groups adjacent to sulfur atom because phosphotungstic acid is a bulky catalyst.
In this work, oxidative desulfurization reactions of the model compounds, thiophene (T), 2-methylthiophene (2-MT) and 2,5-dimethylthiophene (2,5-DMT), which have the lowest reactivity in ODS, on sonication at low H2O2 (O)/F (formic acid)/S (organosulfur solution) volume ratios were carried out sequentially in the presence of tetrabutylammonium bromide (TBAB) as phase transfer catalyst at 30 and 40 °C.
First, the solution of the relevant model sulfur compound in n-heptane was put into a steel batch reactor and later, reactions were performed by adding mixture of 35% H2O2, formic acid and TBAB onto the organic phase. After each reaction cycle, the aqueous phase was removed by a separation funnel and the oxidative desulfurization reaction of the remaining treated organic phase was repeated three or four times with reuse of the same amounts of fresh hydrogen peroxide, formic acid and TBAB as in the first reactions at 30 and 40 °C for 15 min. After every reaction cycle, the sulfur compounds in heptane were analyzed by using GC with Sulfur Chemiluminescence Detector. Afterwards, the oxidative desulfurization reactions of the model sulfur compounds in heptane were performed for only one cycle in sonoreactor with total amount of oxidation reagents H2O2, formic acid and the same amount of TBAB used in the former multi-cycle reactions at 30 and 40 °C for 15 and 60 min. It was observed that the total conversions of model sulfur compounds obtained from multicycle reactions were higher than its conversions obtained from single-cycle reactions with total amount of oxidation reagents used in the multicycle reaction. The same method was also applied to diesel fuel sample and it was shown that high sulfur removal is reached
Free Full Text Source: http://www.sciencedirect.com/science/article/pii/S1877705812029700

Investigation of the oxidative desulfurization of LCO model mixture by GC-MS and FTIR spectroscopy

CATEGORY: DESULFURIZATION
Fuel Processing Technology, Volume 101, September 2012, Pages 101–105
Investigation of the oxidative desulfurization of LCO model mixture by GC-MS and FTIR spectroscopy
Vesislava Toteva, Anton Georgiev, Liliana Topalova
University of Chemical Technology and Metallurgy, 8 “St. Kliment Ohridski” Blvd., Sofia 1756, Bulgaria
Abstract
Describes oxidative desulfurization of a model mixture of fluid-catalytic-cracked light cycle oil (LCO). Oxidations of the sulfur compounds were monitored by FTIR spectroscopy. Oxidized sulfur compounds and degree of desulfurization by oxidation were determinad by gas chromatography-mass spectroscopy (GC-MS).
Researchers determined that after oxidation and proper extraction process about 90% of the highly refractive by HDS (hydrodesulfurization) sulfur compound like 4,6-Dimethyl-dibenzothiophene (4,6-DMDBT) is removed from the oxidized model mixture.
Full Text Source (Subscription or Fee): http://www.sciencedirect.com/science/article/pii/S0378382012001282

Devices And Processes For Deasphalting And/Or Reducing Metals In A Crude Oil With A Desalter Unit

CATEGORY: DESALTERS
PATENT
Devices And Processes For Deasphalting And/Or Reducing Metals In A Crude Oil With A Desalter Unit
Patent number: 8147678
Issue date: Apr 3, 2012
Application number: 12/252,017
Inventors: Sudhakar Chakka, Steve E. Orwig, Joachim Voelkening
Original Assignee: BP Corporation North America Inc.
Abstract
This invention relates to devices and processes for removing asphaltenes and/or metals from crude oil to increase refinery processing of heavy materials. The desalters of this invention reduce and/or remove at least a portion of asphaltenes and/or metals form the crude oil. The separation occurs by mixing water with the crude oil to result in an aqueous phase having water and water soluble salts, an interface phase having asphaltenes and/or metals along with water, and a hydrocarbon phase having desalted, deasphalted and/or reduced metal crude oil.
BACKGROUND
1. Field of the Invention
This invention relates to devices and processes for removing asphaltenes and/or metals from crude oil to increase refinery processing of heavy hydrocarbon feedstocks.
 
2. Discussion of RelatedArt
The current trend in refining includes utilization of heavier crude oil and alternative hydrocarbon sources, such as bitumen and tar sands. These heavier materials include an increased amount of asphaltenes and an increased amount of metals and/ or heavy metals, Which makes processing diflicult due to among other things, viscosity, fouling, and catalyst deactivation issues.
 
In response to this need, the petroleum refining industry has developed efforts and resources to develop neW Ways to solve problems associated With asphaltene-containing streams and metal-containing streams. HoWever, such efforts have only partially succeeded in providing practical methods and devices to maintain refinery capacity.
 
Solvent deasphalting is a commercially practiced process to separate the asphaltenes out of the heavy oils from a bottom of atmospheric and/or vacuum distillation toWers. Solvent deasphalting units require high capital expenditures and have high operating costs to recycle the solvent.
 
Stephenson et al., U.S. Pat. No. 6,120,678 discloses desalting adjunct chemistry and teaches asphaltene dispersing treatments to reduce the rag interface. Stephenson et al. does not teach or suggest collecting asphaltenes and/ or metals in a rag layer for separation from the crude oil in a desalter.
 
Wilson et al., U.S. Pat. No. 3,779,895 discloses high temperature steam treatment of asphaltene-containing streams to form an emulsion that is then solvent deasphalted. Wilson et al. does not teach or suggest collecting asphaltenes and/or metals in a rag layer for separation from the crude oil in a desalter.
 
Jorgensen, U.S. Patent Application Publication 2005/ 021 1602 discloses superheated steam treatment of high boiling temperature material to demetalize the feed. Jorgensen does not teach or suggest collecting asphaltenes and/ or metals in a rag layer for separation from the crude oil in a desalter.
 
Gunnerman, U.S. Patent Application Publication 2005/ 0205463 discloses using ultrasound of a suflicient intensity to convert heavy hydrocarbons in an emulsion to lighter components. Gunnerman does not teach or suggest collecting asphaltenes and/or metals in a rag layer for separation from the crude oil in a desalter.
 
Van der Toorn et al., U.S. Pat. No. 3,730,880 discloses problems of coking and catalyst issues for hyrdroconversion units When processing materials having asphaltenes and metals. Barger, U.S. Pat. No. 4,384,948 discloses similar problems With coking and catalyst poisoning in fluidized catalytic cracking units When processing materials With asphaltenes and metals.
 
Although the foregoing disclosures provide advances in the art, there is still a need for a method of removing asphaltenes and/or metals from crude oil, such as improved processability, reduced fouling, reduced viscosity, improved coke product quality, and/or, reduced catalyst deactivation.
 
SUMMARY
These and other aspects of this invention are met at least in part by a process and an apparatus for using a desalter to
remove and/ or reduce at least a portion of asphaltenes and/or metals from the crude oil, such as to improve processability, reduce fouling, reduce viscosity, improve coke product quality, reduce catalyst deactivation, and/ or the like.
 
According to one embodiment, this invention relates to a desalter unit for removing Water soluble salts and asphaltenes from a crude oil stream. The unit includes a separator for receiving a Water-in-oil emulsion formed from crude oil and Wash Water. The separator includes a first nozzle for WithdraWing an aqueous phase having Water and Water soluble salts, a second nozzle for WithdraWing an interface phase having asphaltenes and Water, and a third nozzle for WithdraWing a hydrocarbon phase having desalted and deasphalted crude oil.
 
According to a second embodiment, this invention relates to a process of desalting and deasphalting crude oil. The process includes mixing a Wash Water stream and a crude oil stream to form a Water-in-oil emulsion. The crude oil stream includes Water soluble salts and asphaltenes. The process includes separating the Water-in-oil emulsion in a desalter unit to form a first stream having Water and Water soluble salts, a second stream having asphaltenes and Water, and a third stream having desalted and deasphalted crude oil.
 
According to a third embodiment, this invention relates to a method of increasing asphaltene-containing crude oil processing capacity in a refinery With a hydroconversion unit having an asphaltene-based operating constraint. The method includes removing at least a portion of asphaltenes from an asphaltene-containing crude oil in a desalter unit, and increasing a volume of the asphaltene-containing crude oil to the refinery until an amount of asphaltenes in a feed to the hydroconversion unit reaches the asphaltene-based operating constraint.
 
According to a fourth embodiment, this invention relates to a method of increasing metal-containing crude oil processing capacity in a refinery With a hydroconversion unit having a metal-based operating constraint. The method includes removing at least a portion of metals from a metal-containing crude oil in a desalter unit, and increasing a volume of the metal-containing crude oil to the refinery until an amount of metals in a feed to the hydroconversion unit reaches the metal-based operating constraint. The metals can be any metal, such as those that deactivate a heavy oil hydroconversion catalyst.
Free Full Text Source: http://www.google.com/patents/US8147678?dq=novel+refinery

Feasibility Study of Integrating Multi Effect Desalination and Gas Turbine Systems for Lavan Island Oil Refinery

CATEGORY: DESALINATION
Iran. J. Chem. Chem. Eng, Vol. 31, No. 3, 2012
Feasibility Study of Integrating Multi Effect Desalination and Gas Turbine Systems for Lavan Island Oil Refinery
Shakouri, Mahdi●*+
m.shakouri@srbiau.ac.ir
Young Researchers Club, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
Ghadamian, Hossein
Department of Energy Engineering, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
Mohammadpour Bagheri, Farzaneh
Department of Medical Engineering, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
ABSTRACT:
Researchers conducted a feasibility study of integrating thermal desalination unit with Gas Turbine (GT) using retrofit and grass root design techniques for Lavan Island Oil Refinery, located in Persian Gulf.
According to computed parameters on developed code for the power generation unit No.1 using EES (Engineering Equation Solver) software, thermal efficiency of the GT unit No.1 and thermal energy recovered by HRSG (Heat Recovery Steam Generator) are equal to 22.79% and 4847 kW, respectively. Therefore, it shows a considerable potential on heat recovery and motive steam production. Effect of variations on different quantitative and qualitative parameters has been reviewed on the next step of this research. Finally, effect of engineering and economical parameters has been compared based on the following scenarios:
● Integrating available Thermal Desalination Unit (TDU) with available steam boiler,
● Retrofitting available TDU with HRSG,
● Integrating GT unit No.1 with novel simulated TDU based of grass root design.
As a result, based on economical model, which has been developed using GAMS (Generalized Algebraic Modelling System) software, the selected scenario is the third scenario.
Free Full Text Source: http://www.sid.ir/en/VEWSSID/J_pdf/84320126313.pdf

Predicting Petroleum Coke Morphology From Feedstock Properties

CATEGORY: DELAYED COKING
PATENT
Predicting Petroleum Coke Morphology From Feedstock Properties
Document Type and Number: United States Patent Application 20120298553
Inventors:
Fern, Jared (Avondale, PA, US)
Application Number:
13/117446
Publication Date:
11/29/2012
Assignee:
Lyondell Chemical Company (Houston, Tx, Us)
Abstract:
A method of predicting the morphological type of coke produced in a delayed coking process is provided by measuring S-values of an asphaltene containing feedstock with an S-value machine. Improved refinery operations and delayed coking operations can be obtained by virtue of the invention.
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to the formation of coke by the delayed coker process. The coke formed can be a fuel grade coke, classified as either sponge coke or shot coke. The type of coke produced can be predicted from a preliminary testing of the feedstock to improve coke morphology.
2. Description of the related art
Delayed coking is a thermal cracking process used in petroleum refineries to upgrade and convert petroleum residuum (bottoms from distillation of crude oil) into liquid and gas product streams leaving behind a solid, concentrated carbon material, petroleum coke (hereinafter “coke”). Petroleum coke was first made by the pioneer oil refineries of Northwestern Pennsylvania in the 1860's. Those primitive refineries boiled crude oil in small, iron stills to recover kerosene, a valuable and much needed luminescent. The stills were heated by wood or coal fires built underneath the still which over-heated and coked the oil near the bottom. After the distillation was complete, the still was allowed to cool so that workmen could dig out the coke and tar before the next run.
The origin of the vertical coke drum was probably from thermal cracking of gas oil for the production of gasoline and diesel fuel. From 1912 to 1935 the Burton process developed by Standard Oil at Whiting, Indiana converted gas oil to gasoline with the production of petroleum coke. The lack of an adequate supply of crude oil and the lack of a heavy oil market caused land-locked middle American refineries to process the heavy fuel oil (atmosperic distillation bottoms and vacuum distillation bottoms) in a delayed coker to produce more gasoline and diesel fuel.
Delayed coking combined a number of the features and improvements from the development of the thermal cracking process. The use of pressure as well as heat for cracking and separating the heater from the coker and the use of two coking drums enabled the delayed coker to operate on a continuous basis. The number of cokers built before 1955 was small, with a surge in delayed coker construction between 1955 and 1975 at 6% per year and an 11% growth rate during the 1965 to 1970 period. The growth of delayed cokers was in step with the growth of fluid catalytic cracking and rapid decline in thermal cracking.
Today, the delayed coker is the only main process in a modern petroleum refinery that is a batch-continuous process. A schematic of a basic refinery is shown in FIG. 1. The flow through the tube furnace is continuous. The feed stream is switched between the two coker drums. One drum is on-line filling with coke while the other drum is being steam stripped, cooled, decoked, pressure checked and warmed up. The overheat vapors from the coke drums flow to a fractionator, usually called a combination tower. The fractionator, or combination tower, has a resevoir in the bottom where the fresh feed is combined with condensed product vapors (recyle) to make up the feed to the coker heater.
A basic coker operation flow diagram is shown as FIG. 2 to illustrate some of the delayed coking unit hardware.
Coke drum diameters range from 4 to 9 meters (13 to 30 feet) with the straight side being about 25 meters (82 feet) with a 1.5 meter diameter top blind flange closure and a 2 meter diameter bottom blind flange in which a 15 to 30 cm inlet nozzle is attached. Both the top blind flange and bottom blind flange must be removed when decoking the drum. The pressure in the drum ranges from 1 to 5.9 bars, typically about 2 to 3 bars.
A high pressure water jet is employed to cut the coke out of the drum, but other mechanical removal methods can be employed.
The physical structure of coke can be broken down into three main types, shot coke, sponge coke and needle coke. Shot coke is in the form of balls of 2 to 5 mm in size, but can agglomerate into larger balls as large as 25 centimeters. Sponge coke is named for its sponge-like appearance. One manner of influencing the production of sponge coke is disclosed in U.S. Pat. No. 4,096,097. Needle coke is named for its needle-like structure. Needle coke is produced from feedstocks without asphaltenes present. Such production requires special feedstocks and other special processing parameters as disclosed in U.S. Pat. No. 4,490,244. There are various methods for determining the properties, such as luster, of coke such as disclosed in U.S. Pat. No. 6,954,545, among others. However, none of these disclosures can predict the type of coke which will be produced from any given asphaltene-containing feedstock.
When crudes are processed where blends of shot coke and sponge coke are produced, the shot coke, composed of spherical particles, tend to agglomerate together. When this happens, regions within the coke drum do not cool as efficiently as the rest of the drum creating operational problems when cutting the coke out of the drum with high pressure water. Such operational problems are known as “hot spots” and “steam eruptions” when subsequently cutting the coke with a high pressure jet of water.
There are some techniques available in the literature for prediction of coke morphology. The most prevalent technique involves measuring the ratio of the microcarbon residue (hereinafter “MCR”) to the quantity of asphaltenes present in the resid. If this ratio is less than 2, the resid will produce primarily shot coke. If the ratio is higher than 2, the resid will produce primarily sponge coke. The MCR to asphaltene ratio is based upon historical plant experience and is engrained in coking lore, but this ratio is only accurate at the extremes of the morphology spectrum and not at the intermediate values that are typically found in refineries.
A second approach found in the literature is to experimentally measure the quantity of aromatic carbon and heteroatoms (O, S, N) present in a precipitated asphaltene sample. If the ratio is greater than 11 then primarily sponge coke will be formed and if the ratio is less than 7 primarily shot coke will be formed. The region between 7 and 11 is a transitional region where the coke can create hot spots. This technique does not quantify the intermediate resids processed at some refineries, and the analysis is difficult to perform in a timely manner without specialized equipment. Furthermore, each of these techniques add an additional error to the measurement because the resid suspension is broken to remove the asphaltene molecules for analysis. Another approach is disclosed in U.S. Pat. No. 7,803,627.
Thus, there exists a need to predict the type of coke to be produced in a delayed coker, based on the asphaltene containing feedstock used in the refinery
Each of the foregoing U.S. Patents are herein incorporated by reference in their entireties.
BRIEF SUMMARY OF THE INVENTION
The stability of a solution that contains asphaltenes can be measured using an S-value machine. An S-value machine is an analytical apparatus that measures the stability of heavy fuels. One such machine is available from ROFA FRANCE from the manufacturer, DPC SA of Grand Rue 86 CH-20075 Thielle-Wavre, SWITZERLAND. The parameters generated from the stability analysis are typically used to determine if two different crude oils are compatible for blending.
In one embodiment according to the present invention, the parameters measured by an S-value machine are used to predict the type of coke produced from a given asphaltene containing feedstock.
In another embodiment of the invention a delayed coking apparatus is utilized to primarily produce either shot coke or sponge coke.
These and other embodiments of the invention will become apparent when reading the following detailed description of preferred embodiments in connection with the appended drawings.
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Co-promotion of fluorine and boron on NiMo/Al2O3 for hydrotreating light cycle oil

CATEGORY: CATALYSIS
Catal. Sci. Technol., 2012,2, 1925-1932Catalysis Science & Technology, Issue 9, 2012
Co-promotion of fluorine and boron on NiMo/Al2O3 for hydrotreating light cycle oil
Songdong Yao ,  Ying Zheng ,  Lianhui Ding ,  Siauw Ng and Hong Yang
Department of Chemical Engineering,University of New Brunswick, P.O. Box 4400, Fredericton, Canada
Abstract
After modifying the hydrotreating catalyst NiMo/Al2O3 with various amounts of fluorine (F) and boron (B) through the pore-saturated impregnation method, researchers characterized the resulting catalysts by BET, pyridine-IR, XPS, and TEM techniques.
Incorporation of fluorine and boron led to the variations in the catalyst acidity and the dispersion of active metals, causing direct impacts on the hydrotreating activities of the catalysts. The hydrodesulfurization (HDS), hydrodenitrogenation (HDN) and hydrodearomatization (HDA) activities of the catalysts were examined in an autoclave reactor using real light cycle oil as feed. The HDS activity decreased in the order NiMo/F,B-Al(5.0) > NiMo/F,B-Al(7.0) > NiMo/F,B-Al(3.5), indicating the existence of an optimum amount of F and B.
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Novel Steam Reformer Based Hydrogen Plant Scheme For Enhanced Carbon Dioxide Recovery

CATEGORY: CARBON CAPTURE
PATENT
Novel Steam Reformer Based Hydrogen Plant Scheme For Enhanced Carbon Dioxide Recovery
Inventors: Tarun D. Vakil, Ulrich Wolf
Original Assignees: LURGI GmbH, L'Air Liquide Societe Anonyme Pour L'Etude ed I'Exploitaion Des Procedes Georges Claude
Current U.S. Classification: 423/652
Application number: 13/396,229
Publication number: US 2012/0141368 A1
Filing date: Feb 14, 2012
Abstract
A novel steam reformer unit design, a novel hydrogen PSA unit design, a novel hydrogen/nitrogen enrichment unit design, and novel processing scheme application are presented.

FIELD OF THE INVENTION
[0002] This invention relates to novel steam reformer unit design, a novel hydrogen PSA unit design, a novel hydrogen/ nitrogen enrichment unit design, and a novel processing scheme application.
 
BACKGROUND
[0003] The production of hydrogen by the steam reforming of hydrocarbons is Well knoWn. In the basic process, a hydrocarbon, or a mixture of hydrocarbons, is initially treated to remove, or convert and then remove, trace contaminants, such as sulfur and olefins, Which Would adversely affect the reformer and the doWn stream Water gas shift unit catalyst. Natural gas containing predominantly methane is a preferred starting material since it has a higher proportion of hydrogen than other hydrocarbons. HoWever, light hydrocarbons or refinery off gases containing hydrocarbons, or refinery streams such as LPG, naphtha hydrocarbons or others readily available light feeds might be utilized as Well.
 
[0004] The pretreated hydrocarbon feed stream is typically at a pressure of about 200 to 400 psig, and combined With high pressure steam, Which is at a higher than the feed stream pressure, before entering the reformer furnace. The amount of steam added is much in excess of the stoichiometric amount. The reformer itself conventionally contains tubes packed With catalyst through Which the stean1/hydrocarbon mixture passes. An elevated temperature, e.g. about 1580° F., or 860° C., is maintained to drive the endothermic reaction.
 
[0005] The efliuent from the reformer furnace is principally hydrogen, carbon monoxide, carbon dioxide, Water vapor, and methane in proportion close to equilibrium amounts at the furnace temperature and pres sure. The efliuent is conventionally introduced into a one- or tWo-stage Water gas shift reactor to form additional hydrogen and carbon dioxide. The shift reactor converts the carbon monoxide to carbon dioxide by reaction With Water vapor, Which generates additional Hydrogen. This reaction is endothermic. The combination of steam reformer and Water gas shift converter is Well knoWn to those of ordinary skill in the art.
 
[0006] If CO2 capture from the high pressure syngas stream exiting the Water gas shift unit is desired, the shift converter effluent, Which comprises hydrogen, carbon dioxide and Water With minor quantities of methane and carbon monoxide is introduced into a conventional absorption unit for carbon dioxide removal. Such a unit operates on the WellknoWn amine Wash or Benfield processes Wherein carbon dioxide is removed from the effluent by dissolution in an absorbent solution, i.e. an amine solution or potassium carbonate solution, respectively. Conventionally, such units can remove up to 99 percent or higher of the carbon dioxide in the shift converter efliuent.
 
[0007] The efliuent from the carbon dioxide absorption unit is introduced into a pressure sWing adsorption (PSA) unit. PSA is a Well-knoWn process for separating essentially pure hydrogen from the mixture of gases as a result of the difference in the degree of adsorption among them on a particulate adsorbent retained in a stationary bed.
 
[0008] Conventionally, the remainder of the PSA unit feed components, after recovery of pure hydrogen product, Which comprises carbon monoxide, the hydrocarbon, i.e. methane, hydrogen and carbon dioxide, is returned to the steam reformer furnace and combusted to obtain energy for use therein
 
[0009] To practice CO2 emissions capture from such hydrogen plants, one must consider total emissions resulting from the plant, Which includes CO2 recovery from reformer furnace flue gas as Well.
 
[0010] The CO2 emissions from a steam reformer based conventional hydrogen plant originate from the reformer furnace flue gas. The root source of this total CO2 in the furnace flue gas results from tWo sources:
 
[0011] (a) the reaction Within the reformer tubes and shift; and
 
[0012] (b) the combustion of fuel in reformer furnace. [0013] Each source contributes betWeen about 40 and about 60% of the total CO2 emitted through the reformer furnace flue gas. For CO2 capture, conventional schemes employed consist of:
 
[0014] (a) removal of CO2, only from the high pressure syngas stream exit shift unit; [0015] (b) removal of CO2, only from the reformer furnace flue gas; and
 
[0016] (c) removal of CO2 via both (a) and (b) above. [0017] Option (a) permits about 50 to about 60% of total CO2 emissions capture. Option (b) permits about 90% of total CO2 emissions capture. Option (c) permits about 95% of the total CO2 emissions capture. Option (a) permits only partial capture at reasonable cost, Option (b) is considered the most expensive of the three options, capital and utility requirements Wise. Option (c) is also expensive, utility intensive and quite elaborate. [0018] Therefore, it is very desirable and cost effective to have a H2 plant design that results in betWeen about 85% and about 95%+of total CO2 capture, solely from the high pressure syngas stream exit Water gas shift reactor.
 
SUMMARY
[0019] The present invention is a novel steam reformer design and method using the same. This method includes a variety of steps of Which the first is to provide a first gas mixture. This first gas mixture may comprise natural gas containing mostly methane, light hydrocarbons, refinery off gases containing hydrocarbons, refinery streams such as LPG, naphtha hydrocarbons or other readily available light feeds. Step tWo involves introducing said first gas mixture into either a pre-reforrner folloWed by a primary reformer, or directly into a primary reformer, thereby generating a second gas mixture comprising hydrogen, carbon monoxide, carbon dioxide. The novelty here is in the design and operating parameters of the primary reformer. The third step of the method includes introducing said second gas mixture into at least one isothermal shift reactor, or a combination of a high folloWed by a loW temperature shift reactor, or a medium temperature shift reactor, thereby generating a third gas mixture. Step four includes introducing said third gas mixture into an amine Wash, Wherein said third gas is separated into a fourth gas mixture and a carbon dioxide enriched stream. The fifth step includes introducing said fourth gas mixture into a standard hydrogen PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. In the final step, the reformer furnace uses the PSA purge gas as fuel With the supplemental fuel or remainder of the fuel for the reformer furnace being natural gas or a portion of the feed hydrocarbon stream, or any other external fuel. By virtue of the novel reformer, the syngas/ flue gas CO2 distribution is higher than the conventional design.

[0020] In one embodiment of the present invention, the novel steam reformer design along With a novel hydrogen PSA design that is loWer cost is used. Additionally, this embodiment is self-sufficient in reformer fumace fuel requirements and therefore does not require any import of supplemental fuel. This embodiment is the same With regard to steps one to four above but differs in the remaining steps. More specifically, the fifth step of this embodiment includes introducing said fourth gas mixture into either a standard recovery or a special loW recovery PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. In this particular embodiment, the reformer furnace uses all of the PSA purge gas as fuel. Additionally, it uses a novel hydrogen PSA design that is loWer cost. By virtue of this novel PSA design, the PSA purge gas is suflicient to satisfy all fuel requirements of the reformer furnace. Because the scheme is self-suflicient in reformer furnace fuel requirements, there is no requirement of any import of supplemental fuel. By virtue of the novel reformer and the novel PSA designs, the syngas/flue gas CO2 distribution is higher than the conventional design.
 
[0021] In a still further embodiment of the present invention, the novel steam reformer design is used along With a novel hydrogen PSA design that is loWer cost. This embodiment is self-suflicient in reformer furnace fuel requirements and therefore, does not require any import of supplemental fuel. Additionally, a second novel gas separation unit is designed to be included in this embodiment (preferably an adsorption based unit although a membrane or a cryogenic separation unit may be used) that separates the compressed primary PSA unit purge gas into tWo streams-one that is recycled back as feed to the reforming section and the other that is used as reformer furnace fuel. Steps one to four of this embodiment are the same With regard to steps one to four above. The fifth step includes introducing said fourth gas mixture into either a standard recovery or a special loW recovery PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. A second novel gas separation unit is additionally employed, preferably an adsorption based unit, that separates the compressed primary PSA unit purge gas into tWo streams, one that is recycled back as feed to the reforming section and the other that is used as reformer furnace fuel. While an adsorption based unit is preferred, a membrane or a cryogenic separation unit may also be used. The scheme is self-suflicient in reformer fumace fuel requirements and therefore, does not require any import of supplemental fuel. By virtue of the novel reformer, the novel primary hydrogen PSA, and the novel second adsorption
 
based separation unit, the syngas/ flue gas CO2 distribution is higher than the conventional design.
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Novel Fuel Compositions And Methods For Making Same

CATEGORY: BUNKER FUEL
PATENT
Novel Fuel Compositions And Methods For Making Same
United States Patent Application 20120246999
Inventors:
Stern, David L. (Fairfax, VA, US)
Di Mauro, Salvatore R. (Fairfax, VA, US)
Roccaro, Aldo (Legnano, IT)
Bessonette, Paul W. (Deptford, NJ, US)
Application Number:
13/431050
Publication Date:
10/04/2012
Assignee:
Exxonmobil Research And Engineering Company (Annandale, Nj, Us)
Abstract:
This invention relates to low sulfur marine/bunker fuel compositions and methods of making same. Contrary to conventional marine/bunker fuel compositions/methods, the inventive lower sulfur compositions/methods focus on use of mostly uncracked components, such as (cat feed) hydrotreated gasoils, and/or can also have reduced contents of residual components.
FIELD
This invention relates generally to methods for making marine/bunker fuels having relatively low sulfur content, as well as to the resulting low sulfur content fuel compositions made according to such methods.
BACKGROUND
As promulgated by the International Maritime Organization (IMO), issued as Revised MARPOL Annex VI, marine fuels will he capped globally with increasingly more stringent requirements on sulfur content. In addition, individual countries and regions are beginning to restrict sulfur level used in ships in regions known as Emission Control Areas, or ECAs.
The fuels used in global shipping are typically marine/bunker fuels, for larger ships. Bunker fuels are advantageous since they are less costly than other fuels; however, they are typically composed of cracked and/or resid fuels and hence have higher sulfur levels. Meeting the lower sulfur specs for marine vessels can be conventionally accomplished through the use of distillates. However, distillate fuels typically trade at a high cost premium for a variety of reasons, not the least of which is the utility in a variety of transport applications employing Compression ignition engines. They are produced at low sulfur levels, typically significantly below the sulfur levels specified in the IMO regulations.
Those regulations specify, inter alia, a 1.0 wt % sulfur content on ECA Fuels (effective July, 2010) for residual or distillate fuels, a 3.5 wt % sulfur content cap (effective January, 2012), which can impact about 15% of the current residual fuel supply, a 0.1 wt % sulfur content on ECA Fuels (effective January, 2015), relating mainly to hydrotreated middle distillate fuel, and a 0.5 wt % sulfur content cap (circa 2020-2025), centered mainly on distillate fuel or distillate/residual fuel mixtures. When the ECA sulfur limits and sulfur cap drops, various reactions may take place to supply low sulfur fuels. The 0.1% S ECA fuel can he challenging to supply, since shippers typically purchase lower sulfur fuel oils with properties suitable for marine applications, and at a steep price discount to distillate fuels.
Hydrotreaters in front of FCC units, commonly called CFHT, typically hydroprocess Virgin Gas Oils (VGOs) to sufficiently low sulfur levels such that the product fuels are sufficient to he sold as fuel with no further treatment, or with minimal incremental hydroprocessing.
It would be advantageous to utilize a fuel high energy content, low sulfur fuels in marine applications, which fuels have conventionally included cracked distillates. Distillates can typically command a much higher value than bunker fuels. An alternative low sulfur marine/bunker fuel, with the correct fuel quality characteristics, could command a high premium in the marketplace.
Indeed, there are some publications that disclose the desirability of lowering the sulfur content of marine/bunker fuels. A non-exclusive list of such publications includes, for example, U.S. Pat. Nos. 4,006,076, 4,420,388, 6,187,174, 6,447,671, and 7,651,605, U.S. Patent Application Publication No. 2008/0093262, PCT Publication Nos. WO 1999/057228 and WO 2009/001314, British Patent No. GB 1209967, Russian Patent No. RU 2213125, Japanese Patent No. JP 2006000726, and the following articles: Chem. & Tech. of. Fuels and Oils (2005), 41(4), 287-91; Ropa a Uhlie (1979), 21(8), 433-40; Godishnik na Visshya Khim. heski Institut, Sofiya (1979), 25(2), 146-48; and Energy Progress (1986), 6(1), 15-19.
Thus, it would be desirable to find compositions and methods for making them) in which hydrotreated and/or untracked gasoil products could he used in marine/bunker fuels, as described with reference to the invention herein.
SUMMARY OF EMBODIMENTS OF THE INVENTION
One aspect of the invention relates to a method for making a low sulfur marine and/or bunker fuel composition with a reduced concentration of components that have been cracked, the method comprising: contacting a gasoil feed stream having at least 7500 wppm, for example at least 2000 wppm, sulfur content with a hydrogen-containing gas in the presence of a hydrotreating catalyst under effective hydrotreating conditions in a catalytic feed hydrotreater, such that the product exhibits at most 5000 wppm, for example at most 1000 wppm, sulfur content, a pour point of at least 7° C., and a kinematic viscosity of at least 12 cSt at about 50° C., without the product being subject to cracking; optionally blending at least a portion of the uncracked product with 0-70 vol % of other components, selected from viscosity' modifiers, pour point depressants, lubricity modifiers, antioxidants, and combinations thereof, to form a marine and/or bunker fuel composition, the resulting marine and/or bunker fuel composition containing the uncracked product having: at most 5000 wppm, for example at most 1000 wppm, sulfur content; at most 25 vol %, based on all components of the marine and/or bunker fuel composition, of residual components selected from crude fractionation vacuum resid, crude fractionation atmospheric resid, visbreaker resid, deasphalted vacuum resid, slurry oil, and combinations thereof; less than 50 vol %, based on all components of the marine and/or bunker fuel composition, of residual components, components subject to a refinery cracking step, or both; and at least one of a kinematic viscosity at about 50° C. from 12 cSt to 50 cSt; a density at about 15° C. from 0.90 g/cm3 m to 0.94 g/c3, a pour point from 7° C. to 45° C., and a calculated carbon aromaticity index of 850 or less.
Another aspect of the invention relates to a low sulfur marine and/or bunker fuel composition comprising: 30 vol % to 100 vol % of an uncracked, hydrotreated gasoil product having at most 5000 wppm, for example at most 1000 wppm, sulfur content, a pour point of at least 7° C., and a kinematic viscosity of at least 12 cSt at about 50° C.; and up to 70 vol % of other components, selected from viscosity modifiers, pour point depressants, lubricity modifiers, antioxidants, and combinations thereof, wherein the low sulfur marine and/or bunker fuel composition has: at most 5000 wppm, for example at most 1000 wppm, sulfur content; at most 25 vol %, based on all components of the marine and/or bunker fuel composition, of residual components selected from crude fractionation vacuum resid, crude fractionation atmospheric resid, visbreaker resid, deasphalted vacuum resid, slurry oil, and combinations thereof; less than 50 vol %, based on all components of the marine and/or bunker fuel composition, of residual components, components subject to a refinery cracking step, or both; and at least one of a kinematic viscosity at about 50° C. from 12 cSt to 50 cSt, a density at about 15° C. from 0.90 g/cm3 to 0.94 g/cm3, a pour point from 7° C. to 45° C., and a calculated carbon aromaticity index of 850 or less.
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