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- Herausgeber: John Wiley & Sons
- Kategorie: Fachliteratur
- Sprache: Englisch
- Veröffentlichungsjahr: 2016
Written by a scientist and researcher with more than 25 years of experience in the field, this serves as a complete guide to catalyst activity loss during the hydroprocessing of heavy oils. * Explores the physical and chemical properties of heavy oils and hydroprocessing catalysts; the mechanisms of catalyst deactivation; catalyst characterization by a variety of techniques and reaction conditions; laboratory and commercial information for model validations; and more * Demonstrates how to develop correlations and models for a variety of reaction scales with step-by-step descriptions and detailed experimental data * Contains important implications for increasing operational efficiencies within the petroleum industry * An essential reference for professionals and researchers working in the refining industry as well as students taking courses on chemical reaction engineering
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Table of Contents
Cover
Title Page
Copyright
About the Author
Preface
Nomenclature
Chapter 1: Properties of Heavy Oils
1.1 Introduction
1.2 Refining of Petroleum
1.3 Properties of Heavy Petroleum
1.4 Assay of Petroleum
References
Chapter 2: Properties of Catalysts for Heavy Oil Hydroprocessing
2.1 Introduction
2.2 Hydroprocessing Catalyst
2.3 Characterization of Catalysts
2.4 General Aspects for Developing Catalysts for Hydroprocessing of Heavy Crude
2.5 Catalyst for Maya Crude Oil Hydroprocessing
2.6 Concluding Remarks
References
Chapter 3: Deactivation of Hydroprocessing Catalysts
3.1 Introduction
3.2 Hydroprocessing of Heavy Oils
3.3 Mechanisms of Catalyst Deactivation
3.4 Asphaltenes and Their Effect on Catalyst Deactivation
References
Chapter 4: Characterization of Spent Hydroprocessing Catalyst
4.1 Introduction
4.2 Characterization Techniques
4.3 Early Deactivation of Different Supported CoMo Catalysts
4.4 Carbon and Metal Deposition During the Hydroprocessing of Maya Crude Oil
4.5 Characterization Study of NiMo/SiO
2
–Al
2
O
3
Spent Hydroprocessing Catalysts for Heavy Oils
4.6 Characterization of Spent Catalysts Along a Bench-Scale Reactor
4.7 Hydrodesulfurization Activity of Used Hydrotreating Catalysts
References
Chapter 5: Modeling Catalyst Deactivation
5.1 Introduction
5.2 Effect of Reactor Configuration on the Cycle Length of Heavy Oil Fixed-Bed Hydroprocessing
5.3 Effect of Different Heavy Feedstocks on the Deactivation of a Commercial Catalyst
5.4 Modeling the Deactivation by Metal Deposition of Heavy Oil Hydrotreating Catalyst
5.5 Kinetic Model for Hydrocracking of Heavy Oil in a CSTR Involving Short-Term Catalyst Deactivation
5.6 Modeling the Kinetics of Parallel Thermal and Catalytic Hydrotreating of Heavy Oil
5.7 Modeling Catalyst Deactivation During Hydrocracking of Atmospheric Residue by Using the Continuous Kinetic Lumping Model
5.8 Application of a Three-Stage Approach for Modeling the Complete Period of Catalyst Deactivation During Hydrotreating of Heavy Oil
References
Index
End User License Agreement
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Guide
Cover
Table of Contents
Preface
Chapter
List of Illustrations
Chapter 1: Properties of Heavy Oils
Figure 1.1 Asphaltenes precipitated from various crude oils: (a) 13°API, (b) 21°API, and (c) 33°API.
Figure 1.2 Hypothetical structures of asphaltenes: (a) Continental type and (b) Archipelago type.
Figure 1.3 Tendency to coke formation of crude oils.
Chapter 2: Properties of Catalysts for Heavy Oil Hydroprocessing
Figure 2.1 Pore volume versus surface area for commercial alumina supports
Figure 2.2 Typical pore size distribution for HDS and HDM catalysts
Figure 2.3 Bimodal pore size distribution of CoMo/Al
2
O
3
–SiO
2
using pH swing method for support preparation.
Figure 2.4 Effect of different hydrolyzing agents on pore size distribution of CoMo supported catalysts. (♦) Al
2
O
3
-u, () Al
2
O
3
-acs, () Al
2
O
3
-am, () reference catalyst.
Figure 2.5 Methods used for preparation of mixed oxide supports.
Figure 2.6 (a) NO adsorption over various NiMo-supported catalysts and (b) Lewis acidity of sulfided catalysts with different support composition
Figure 2.7 Effect of temperature on the shape and the size of Maya asphaltene
Figure 2.8 Effect of catalyst composition on Maya crude+hydrodesulfurized naphtha feedstock. (A) CoMo/AT-1, (B) CoMo/AT-2, (C) CoMo/Al
2
O
3
–TiO
2
, (D) PCoMo/Al
2
O
3
–TiO
2
Figure 2.9 Effect of Al
2
O
3
–SiO
2
-support preparation and catalyst composition on Maya crude activities
Figure 2.10 Effect of diluent on (a) HDS and (b) HDAs of Maya crude oil. () NiMo/Al
2
O
3
(HDT Maya+naphtha), (♦) NiMo/Al
2
O
3
–TiO
2
(HDT Maya+naphtha), (◊) NiMo/Al
2
O
3
–TiO
2
(HDT Maya+diesel), () NiMo/Al
2
O
3
–TiO
2
(Maya+diesel)
Figure 2.11 Effect of catalyst support on HDM
Figure 2.12 Comparison between HDS and HDM for CoMo catalyst over Al
2
O
3
and TiO
2
–Al
2
O
3
(AT) as function of TiO
2
(10 wt%) precursor (TiCl
4
= AT-1, AT-2, and Ti isopropoxide = AT-3, AT-4, AT-5, and AT-6) at 120 h TOS and its incorporation method in alumina
Figure 2.13 Effect of average pore diameter of catalyst on Maya crude hydroprocessing at 60 h TOS (feedstock: Maya+HDS diesel, microreactor)
Figure 2.14 Simplified diagram of the two-stage reactor for hydrotreating of heavy oil crude
Figure 2.15 Catalytic activities of (a) CoMo/Al
2
O
3
and (b) a NiMo/TiO
2
–Al
2
O
3
catalysts with time-on-stream during hydroprocessing of Maya crude at bench-scale reactor ((♦) HDS; () HDM; (Δ) HDAs)
Figure 2.16 Pore size distributions and adsorption–desorption isotherms for CoMo/Al
2
O
3
. () Fresh catalyst, (Δ) spent catalyst.
Figure 2.17 Average pore diameter of fresh catalysts versus coke formation at 60 h TOS during Maya crude hydrotreating
Figure 2.18 (a) SEM-EDAX microanalysis of spent CoMo/Al
2
O
3
catalyst and (b) X-ray diffraction patterns for support, fresh, and spent CoMo/Al
2
O
3
catalysts. Deposited Ni and V sulfides intensity is compared with JCPDS-ASTM data: (Δ) V
3
S
4
, () V
2
S
3
, () Ni
2
S
3
Figure 2.19 Removal of vanadium versus removal of nickel over CoMo/TiO
2
–Al
2
O
3
catalyst and Maya diluted with naphtha feedstock
Figure 2.20 SEM-EDAX analysis of vanadium profiles in tetra lobe spent commercial catalyst (a and b) and deposited vanadium and carbon radial profiles of cylindrical extrudate (c)
Figure 2.21 Effect of type of heavy feed on catalyst run length
Figure 2.22 N
2
adsorption–desorption isotherms of NiMo/Al
2
O
3
–TiO
2
catalysts. () Fresh catalyst, (♦) spent catalyst (microflow reactor, 120 h TOS); (Δ) spent catalyst (bench-scale reactor, 200 h TOS)
Chapter 3: Deactivation of Hydroprocessing Catalysts
Figure 3.1 Profiles of concentration in a hydroprocessing TBR
Figure 3.2 FBR with multicatalytic bed and different quench technologies
Figure 3.3 Example of MBR for hydroprocessing: (a) OCR reactor and (b) bunker reactor
Figure 3.4 Examples of EBR for hydroprocessing: (a) H-oil process and (b) LC-fining process
Figure 3.5 Example of SPR for hydroprocessing.
Figure 3.6 Typical profile of catalyst deactivation. Stage 1: deactivation by coke, stage 2: deactivation by metals, and stage 3: pore blockage.
Figure 3.7 Profiles of catalyst activity versus time-on-stream for (a) reversible, (b) quasi-irreversible, (c) irreversible poisoning
Figure 3.8 Evolution of (a) coke, (b) metals, and (c) total occupied volumes as a function of time-on-stream (♦) bottom of catalytic bed, () top of catalytic bed
Figure 3.9 Effect of (a) temperature on catalyst coke deposits and (b) coke steady-state level as a function of hydrogen pressure
Figure 3.10 Adsorption–desorption isotherms for fresh and spent CoMo/Al
2
O
3
catalysts with different average pore diameters.
Figure 3.11 Radial concentration profiles of vanadium determined by electron microprobe scans along the diameter of catalysts used in hydroprocessing of residue
Figure 3.12 Effect of pore size on useful life and hydrodesulfurization activity for catalysts with narrow monomodal pore size distributions tested under standard conditions
Figure 3.13 Effect of pore diameter on the HDS and HDAs, and HDAs versus HDM at 120 h time-on-stream
Figure 3.14 SEM images of purified asphaltenes: (a) from Maya crude oil, (b) from hydrotreated Maya crude at 100 kg/cm
2
, 400 °C and LHSV = 1 h
−1
, (c) from hydrotreated Maya crude at 100 kg/cm
2
, 420 °C and LHSV = 1 h
−1
.
Chapter 4: Characterization of Spent Hydroprocessing Catalyst
Figure 4.1 Typical Soxhlet apparatus.
Figure 4.2 TPO profiles of spent catalysts from four reactors in a series (R-1 to R-4)
Figure 4.3 Deposited vanadium and carbon concentrations profiles obtained in radial distribution of cylindrical extrudate
Figure 4.4 Intraparticle SEM-EDAX analysis of V profiles in tetralobe spent commercial catalyst
Figure 4.5 TGA of asphaltenes at different heating rates.
Figure 4.6 Volatilization of asphaltenes from a 13°API crude as a function of temperature.
Figure 4.7 Determination of kinetic parameters at different heating rates.
Figure 4.8 High-pressure microplant for hydrotreating experiments.
Figure 4.9 Microreactor for hydrodesulfurization of thiophene and hydrocracking of cumene.
Figure 4.10 (a) HDM and (b) HDS activities of CoMo/Al
2
O
3
(A), CoMo/Al
2
O
3
–TiO
2
(B), CoMo/Al
2
O
3
–SiO
2
(C), and CoMo/C (D) catalysts.
Figure 4.11 Rates of (a) HDM and (b) HDS of CoMo/Al
2
O
3
(A), CoMo/Al
2
O
3
–TiO
2
(B), CoMo/Al
2
O
3
–SiO
2
(C), and CoMo/C (D) catalysts.
Figure 4.12 Activity for thiophene hydrodesulfurization of fresh (F), spent (S), and regenerated (R) catalysts. CoMo/Al
2
O
3
(A), CoMo/Al
2
O
3
–TiO
2
(B), CoMo/Al
2
O
3
–SiO
2
(C), and CoMo/C (D).
Figure 4.13 Radial distribution of (a) vanadium and (b) coke of CoMo/Al
2
O
3
(A), CoMo/Al
2
O
3
–TiO
2
(B), CoMo/Al
2
O
3
–SiO
2
(C), and CoMo/C (D) spent catalysts.
Figure 4.14 Thermogravimetric curves of CoMo/Al
2
O
3
(a), CoMo/Al
2
O
3
–TiO
2
(b), CoMo/Al
2
O
3
–SiO
2
(c), and CoMo/C (d) spent catalysts.
Figure 4.15 Pore size distribution of fresh (F), spent (S), and regenerated (R) CoMo catalysts. CoMo/Al
2
O
3
(a), CoMo/Al
2
O
3
–TiO
2
(b), CoMo/Al
2
O
3
–SiO
2
(c), and CoMo/C (d).
Figure 4.16 Fractionation of crude oil and its separation by chemical treatment.
Figure 4.17 Catalyst deactivation species and their instability factor (indicated by dotted lines).
Figure 4.18 Relative catalytic activity with time-on-stream over CoMo/Al
2
O
3
catalyst at (a) microflow scale and (b) bench scale.
Figure 4.19 Effect of catalyst composition on the hydrotreating of diluted Maya crude activities in microflow reactor (MP).
Figure 4.20 SEM-EDX elemental microprobe analysis of the surface of two different spent catalysts extrudates (a) pilot plant (PP) and (b) microplant (MP).
Figure 4.21 Radial analysis of deposited V and Ni in a line analysis by SEM-EDS for the pilot plant (PP) spent catalyst.
Figure 4.22 Structural differences between (a) V and (b) Ni porphyrin molecules.
Figure 4.23 STEM chemical maps showing the metal particle distribution within the selected area of spent hydroprocessing catalyst (PP) (carbon (C
k
), vanadium (V
k
), nickel (Ni
k
), calcium (Ca
k
), sulfur (S
k
), potassium (P
k
), and silica (Si
k
)).
Figure 4.24 Typical HRTEM images of (a) fresh sulfide and (b) spent catalyst (PP).
Figure 4.25
13
C CP/MAS NMR spectra of coke deposited on spent alumina-supported catalysts: A: (a) CoMo/Al
2
O
3
(MP); (b) CoMo/Al
2
O
3
(PP). B: (a) CoMo/Al
2
O
3
(MP); (b) NiMo/Al
2
O
3
(MP). C: With dipolar dephasing time of 40 s of coke deposited on spent catalysts: (a) CoMo/Al
2
O
3
(MP); (b) NiMo/Al
2
O
3
(MP).
Figure 4.26 SEM-EDX profiles of silica content spent catalysts.
Figure 4.27 Pore size distribution of fresh () and spent () catalysts.
Figure 4.28 Metal and carbon depositions on spent catalysts.
Figure 4.29 FTIR spectra of NiMoSA spent catalysts.
Figure 4.30 Integrated intensities of the bands at 2924 cm
−1
(CH
2
groups) and 2954 cm
−1
(CH
3
groups) in the spectra of spent catalysts as a function of Si/(Si+Al) ratio.
Figure 4.31 FTIR spectra of CO adsorbed on fresh (—) and spent (---) catalysts: (a) NiMoSA-5, (b) NiMoSA-10, (c) NiMoSA-25, and (d) NiMoSA-50.
Figure 4.32 Comparison of hydrocracking activity of cumene for fresh and spent catalysts.
Figure 4.33 Catalysts sampling.
Figure 4.34 Profiles of the deposition of Ni, V, C, and S in fresh basis.
Figure 4.35 DRIFT spectra of spent catalysts during regeneration: (a) spectra in the zone of aliphatic carbon taken at room temperature and (b) spectra in the zone of aromatic carbon taken at 300 °C.
Figure 4.36 Pore size distributions: spent (a) and regenerated (b) catalysts.
Figure 4.37 Intraparticle V distribution (a) and
Z
2
-spent micrograph (b).
Figure 4.38 XRD results for spent (a) and regenerated (b) catalysts.
Figure 4.39 Solid-state
13
C CP-MAS NMR spectra of spent catalysts.
Figure 4.40 Progress of spent catalysts oxidation followed by TGA (a) and TPO-MS (b).
Figure 4.41 FTIR spectra of pyridine desorbed at 100 °C from regenerated catalysts.
Figure 4.42 Correlation of hydrocracking activity and Brønsted acid sites.
Figure 4.43 Profiles of remnant catalyst activity in (a) HDS of thiophene and (b) HDC of cumene.
Figure 4.44 Pore size distribution of fresh, used (processed with 21°API feed), and regenerated catalyst (FC = fresh catalyst, UC = used catalyst, and RC = regenerated catalyst).
Figure 4.45 Coke and vanadium deposition for three different feeds, from three different reactor zones and radial distribution of vanadium deposition.
Figure 4.46 Thiophene HDS of fresh, used, and regenerated catalysts (
T
= 400 °C,
P
= atmospheric pressure, FC = fresh catalyst, C-21°API = catalyst processed with 21°API feed, U = used, and R = regenerate).
Figure 4.47 Gas oil HDS of fresh, used, and regenerated catalysts (
T
= 360 °C,
P
= 60 kg/cm
2
).
Figure 4.48 Comparison of gas oil HDS between used and regenerated catalysts at 0.1 h contact time (FC = fresh catalyst, C-21°API = catalyst processed with 21°API, U = used, and R = regenerated).
Figure 4.49 Gas oil HDS of used catalysts obtained after reaction at three different temperatures and from three different reaction zones.
Chapter 5: Modeling Catalyst Deactivation
Figure 5.1 Catalyst life of for different petroleum feeds.
Figure 5.2 HDS and HDM deactivation curves at SOR conditions. Heavy crude oil (13°API) at LHSV = 0.5 h
−1
,
P
= 6.86 MPa, and H
2
/oil = 891 std m
3
/m
3
: () 380 °C, () 400 °C, (♦) 420 °C; () atmospheric residue (5.4°API) at 360 °C, LHSV = 0.25 h
−1
,
P
= 9.81 MPa, and H
2
/oil = 891 std m
3
/m
3
; Maya crude oil (21°API) at LHSV = 0.5 h
−1
,
P
= 6.86 MPa, and H
2
/oil = 891 std m
3
/m
3
: () 380 °C, (Δ) 400 °C, (◊) 420 °C.
Figure 5.3 Evolution of the chemical lumps and gas yields along the reactor at
T
= 380 °C and LHSV = 0.25 h
−1
: (symbols) experimental, (–) simulated.
Figure 5.4 Process performance during time-on-stream: (symbols) experimental, (–) simulated.
Figure 5.5 Comparison between experimental data and model predictions, (---) ±10%.
Figure 5.6 HDM performance and metals-on-catalyst (MOC): (symbols) experimental, (–) simulated,
R
1
(first reactor),
R
2
(second reactor). The experimental values (°) of MOC at the end of the run were estimated based on the metal balance between feed and products.
Figure 5.7 Simulated axial MOC profiles in the first (
R
1
) and second (
R
2
) reactors. The MOC units are referred to the total amount of fresh catalyst in each reactor.
Figure 5.8 Catalyst wetting efficiency as a function of superficial liquid mass velocity: () bench-scale, () semi-industrial scale, (–) theoretical.
Figure 5.9 Comparison of semi-industrial plant data with model predictions, under the following conditions: LHSV = 0.2 h
−1
,
T
= 380 °C,
P
= 9.81 MPa, and H
2
/oil = 890 std m
3
/m
3
.
Figure 5.10 Proposed industrial reactor configurations.
Figure 5.11 Evolution of the axial temperature profiles.
Figure 5.12 Metals deposition profiles at 2700 h.
Figure 5.13 Total sulfur, asphaltene, and metal contents in hydrotreated products at different reaction temperatures and feedstocks: () HCO, () ARHCO, () EHCO.
Figure 5.14 Effect of temperature on V and C deposits on the catalyst for different feedstocks: () HCO, () ARHCO, () EHCO, (—) V, (---) C.
Figure 5.15 Vanadium and carbon contents in the spent catalyst for EHCO feedstock at different positions of catalytic bed.
Figure 5.16 HDM and HDS performance with HCO and ARHCO feeds during time-on-stream: (symbols) experimental, (–) simulated.
Figure 5.17 Profiles of the HDS deactivation function. (a) Effect of feedstock type at 380 °C. (b) Effect of temperature for HCO feed.
Figure 5.18 MOC accumulation with HCO and ARHCO feeds.
Figure 5.19 Evolution of axial MOC profiles with HCO feed at 380 °C.
Figure 5.20 Internal structure of reactor and idealized pore catalyst.
Figure 5.21 Algorithm for solution of deactivation model.
Figure 5.22 Changes in textural properties of fresh () catalyst and spent (Δ) catalyst (200 h TOS).
Figure 5.23 Distribution of normal boiling points of feed. () Experimental, (.....) linear regression, (—) nonlinear regression.
Figure 5.24 Metals concentration in product as a function of TOS.
Figure 5.25 Dependence of dimensionless concentration (
χ
) on dimensionless time (
τ
) and intraparticle position (
ζ
).
Figure 5.26 Thickness of metal sulfides at pore mouth of catalyst.
Figure 5.27 Profiles of instantaneous to initial pore radius (γ) ratio as a function of intraparticle position and dimensionless time.
Figure 5.28 Effectiveness factor (
η
) as a function of dimensionless time (
τ
).
Figure 5.29 Comparison between experimental and predicted HDM conversion as a function of dimensionless time.
Figure 5.30 Continuous stirred tank basket reactor pilot plant.
Figure 5.31 Variation of sulfur conversion with stirring rate.
Figure 5.32 Five-lump kinetic model.
Figure 5.33 Two-, three-, and four-lump kinetic models.
Figure 5.34 Arrhenius plot for the different kinetic parameters.
Figure 5.35 Comparison between experimental and calculated product compositions: (+) residue, (◊) VGO, (Δ) distillates, () naphtha, () gases.
Figure 5.36 Residual values obtained: (+) residue, (◊) VGO, (Δ) distillates, () naphtha, () gases.
Figure 5.37 Hydrotreating reaction pathways.
Figure 5.38 Reactant-oriented catalyst deactivation. (a) HDS reaction: () 380 °C, (Δ) 400 °C, () 410 °C, and () 420 °C. (b) Hydrotreating reactions at 400 °C: () HDNBN, (Δ) HDS, () HDNNBN, () HDNi, () HDV, () HDAsph, and (*) HDCCR.
Figure 5.39 Effect of operating conditions on the conversion of different hydrotreating reactions. (a) Conversion at the lowest severity conditions (380 °C, 2.56 h
−1
). (b) Conversion at the highest severity conditions (420 °C, 0.98 h
−1
). (+) Sulfur, (×) basic nitrogen, () nonbasic nitrogen, () nickel, (*) vanadium, (Δ) asphaltenes, and () CCR.
Figure 5.40 Comparison between experimental and calculated mass conversions. (+) Sulfur, (×) basic nitrogen, () nonbasic nitrogen, () nickel, (*) vanadium, (Δ) asphaltenes, and () CCR.
Figure 5.41 Residual values of the mass conversion. (+) Sulfur, (×) basic nitrogen, () nonbasic nitrogen, () nickel, (*) vanadium, (Δ) asphaltenes, and () CCR.
Figure 5.42 Effect of time-on-stream on distillation curves at (a) 380 °C, (b) 400, and (c) 420 °C and LHSV of 0.50 h
−1
. (–) Feed; () 20 h, () 40 h, () 60 h, (*) 80 h, (×) 100 h, () 120 h, () 140 h, (Δ) 160 h, (Δ) 180 h, (+) 200 h of TOS.
Figure 5.43 Effect of reaction temperature on distillation curves: (,) 420 °C, (,) 400 °C, and (,Δ) 380 °C. (Full symbols) 20 h of TOS, (void symbols) 200 h of TOS. (–) Feed.
Figure 5.44 Effect of time-on-stream on
α
,
a
0
, and
δ
model parameters at (–) 380 °C, (---) 400 °C, and (⋯) 420 °C.
Figure 5.45 Effect of time-on-stream on
k
max
model parameter at (a) 380 °C, (b) 400 °C, and (c) 420 °C.
Figure 5.46 Dependence of kinetic model parameters on reaction temperature at 20 h of TOS.
Figure 5.47 Parity plot of simulated and experimental data at all temperatures and all TOS (20–200 h).
Figure 5.48 Simulated and calculated dimensionless distillation curves as a function of TOS at 410 °C. () 20 h, () 60 h, () 100 h, () 140 h. (Lines) Simulated results.
Figure 5.49 Simulated dimensionless curves as a function of TOS at (a) 380 °C and (b) 400 °C.
Figure 5.50 Effect of catalyst particle size on asphaltenes conversion at 400 °C, LHSV = 1 h
−1
, 890 m
3
/m
3
H
2
-to-oil ratio and 6.9 MPa.
Figure 5.51 Graphical estimation of some model parameters for HDNi deactivation function.
Figure 5.52 Simulation profiles of deactivation for HDNi for the range of experimental TOS: (symbols) experimental, (line) simulation.
Figure 5.53 Simulation profiles of deactivation for HDV, HDS, and HDAsph for the range of experimental TOS: (symbols) experimental, (line) simulation.
Figure 5.54 Profiles of deactivation for HDNi as function of TOS. Simulation for different catalyst life: (– –) 6000 h, (–––) 7000 h, and (– – –) 8000 h, the three overlapping at short TOS.
Figure 5.55 Predicted deactivation profiles for the complete deactivation period. () HDNi, () HDAsph, () HDV, () HDS. ().
List of Tables
Chapter 1: Properties of Heavy Oils
Table 1.1 Example of Chemical Composition of Various Crude Oils
Table 1.2 Properties of Different Crude Oils
Chapter 2: Properties of Catalysts for Heavy Oil Hydroprocessing
Table 2.1 Approximate Deactivation Timescale and Type of Reactor
Table 2.2 Effect of Particle Size and Shape on Hydrodesulfurization Activity
Table 2.3 Methods for Analyzing Physicochemical Properties of Catalysts
Table 2.4 Main Techniques for Surface Characterization Using Probe Molecules
Table 2.5 Main Spectroscopies and Related Techniques for Surface Characterization
Table 2.6 Physical Properties of Maya Crude Oil and Its Residua
Table 2.7 Properties of the Feed for Different Experimental Setup
Table 2.8 Reaction Conditions for Fixed-Bed Integral Reactors
Table 2.9 Effect of Support and Catalyst Preparation on Textural Properties
Table 2.10 Textural Properties and Composition of Catalysts
Table 2.11 Characterization of Spent Catalysts
Table 2.12 N
2
Adsorption–Desorption Measurements of Pore Mouth Plugging and N
2
Adsorption–Desorption Hysteresis Loop Area Analysis
Chapter 3: Deactivation of Hydroprocessing Catalysts
Table 3.1 Relative Effect of Deactivation by Metals and Coke on Catalyst Functionalities
Chapter 4: Characterization of Spent Hydroprocessing Catalyst
Table 4.1 Activation Energy and Preexponential Factors
Table 4.2 Properties and Coke and Vanadium Depositions on Catalysts
Table 4.3 Properties of the Feeds
Table 4.4 Textural Properties of the Fresh, Spent, and Regenerated Catalyst and the Deactivation on Surface Area and Total Pore Volume
Table 4.5 Chemical Analyses of Spent Catalysts
Table 4.6 Textural Properties of Fresh (F) and Spent (S) NiMoSA Catalysts
Table 4.7 Textural Properties Referred to the Fresh Catalyst
Table 4.8 Weight Loss in TGA by Zones and Evolved Gases by TPO-MS
Table 4.9 Acid Sites Determined by Pyridine Adsorption (µmol/g
cat
)
Table 4.10 Properties of the Feeds Used to Obtain the Deactivated Catalysts
Table 4.11 Reaction Conditions for Hydrodesulfurization of Thiophene and SRGO
Table 4.12 Textural Properties of Fresh (FC), Used (UC), and Regenerated (RC) Catalysts
Chapter 5: Modeling Catalyst Deactivation
Table 5.1 Studies on Catalyst Deactivation During Hydroprocessing of Heavy Oils
Table 5.2 Studies on Catalytic Hydrotreating of Heavy Oil
Table 5.3 Studies on Noncatalytic Hydrotreating of Heavy Oil
Table 5.4 Physical and Chemical Properties of the Feedstock
Table 5.5 Properties of the Feedstocks and Their Asphaltenes
Table 5.6 Correlations for Thermodynamic and Transport Properties
Table 5.7 Properties of the Catalyst
Table 5.8 Properties of the Feedstock
Table 5.9 Effectiveness and Contact Efficiency Factors
Table 5.10 Kinetic Parameters
Table 5.11 Statistical Analysis
Table 5.12 Effectiveness Factors
Table 5.13 Kinetic and Deactivation Parameters
Table 5.14 Statistical Analysis
Table 5.15 Complementary Equations for the Hydrocracking Kinetic Model
Table 5.16 Properties of Feedstock
Table 5.17 Model Parameters for Deactivation Function
Table 5.18 Properties of Catalyst
Table 5.19 Initial and Optimal Model Parameters of Deactivation Function for HDNi by Using Two Approaches
Deactivation of Heavy Oil Hydroprocessing Catalysts
Fundamentals and Modeling
Jorge Ancheyta
Copyright © 2016 by John Wiley & Sons, Inc. All rights reserved
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Published simultaneously in Canada
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Library of Congress Cataloging-in-Publication Data
Names:Ancheyta Juárez, Jorge, author.
Title: Deactivation of heavy oil hydroprocessing catalysts : fundamentals and modeling / Jorge Ancheyta.
Description: Hoboken, New Jersey : John Wiley & Sons, 2016. | Includes bibliographical references and index.
Identifiers: LCCN 2016019443| ISBN 9781118769843 (cloth) | ISBN 9781118769812 (epub)
Subjects: LCSH: Petroleum--Refining. | Catalyst poisoning.
Classification: LCC TP690.8 .A53 2016 | DDC 622/.33827--dc23 LC record available at https://lccn.loc.gov/2016019443
Cover image courtesy of GettyImages/avdeev007
About the Author
Jorge Ancheyta, PhD, graduated with a Bachelor's degree in Petrochemical Engineering (1989), Master's degree in Chemical Engineering (1993), and Master's degree in Administration, Planning, and Economics of Hydrocarbons (1997) from the National Polytechnic Institute (IPN) of Mexico. He splits his PhD between the Metropolitan Autonomous University (UAM) of Mexico and the Imperial College London, UK (1998), and was awarded a postdoctoral fellowship in the Laboratory of Catalytic Process Engineering of the CPE-CNRS in Lyon, France (1999). He has also been a visiting professor at the Laboratoire de Catalyse et Spectrochimie (LCS), Université de Caen, France (2008, 2009, 2010), Imperial College London, UK (2009), and Mining University at Saint Petersburg, Russia (2016).
He has worked for the Mexican Institute of Petroleum (IMP) since 1989 and his present position is Manager of Products for the Transformation of Crude Oil. He has also worked as professor at the undergraduate and postgrade levels for the School of Chemical Engineering and Extractive Industries at the National Polytechnic Institute of Mexico (ESIQIE-IPN) since 1992 and for the IMP postgraduate since 2003. He has been supervisor of more than one hundred BSc, MSc, and PhD theses. He has also been supervisor of a number of postdoctoral and sabbatical year professors.
He has been working in the development and application of petroleum refining catalysts, kinetic and reactor models, and process technologies mainly in catalytic cracking, catalytic reforming, middle distillate hydrotreating, and heavy oils upgrading. He is author and coauthor of a number of patents, books, and about 200 scientific papers, and has been awarded the highest distinction (Level III) as National Researcher by the Mexican government and is a member of the Mexican Academy of Science. He has also been guest editor of various international journals, for example, Catalysis Today, Petroleum Science and Technology, Industrial Engineering Chemistry Research, Chemical Engineering Communications, and Fuel. He has also chaired numerous international conferences.
Preface
Apart from the reactor, catalyst is another important component of a chemical process, and a thorough understanding of the catalytic phenomena occurring during the transformation of reactants into desired products is of vital importance for the development and optimization of the process.
In the case of petroleum refining industry, it is currently immersed in the dilemma of higher production of heavy petroleum compared with that of light petroleum. Producing and refining heavy crude oils is more complicated since they exhibit higher content of impurities (sulfur, nitrogen, metals, and asphaltenes), as well as higher yield of residue with consequent low production of valuable distillates (gasoline and diesel) than conventional crude oils, which in turn are responsible for the low price of heavy petroleum. And not only that, the existing refineries have been designed to process light crude oil and heavy crude oil can only be blended at a certain reduced proportion. To increase the diet of heavy crude oils as feed to a refinery, units require major changes or installation of new plants.
A solution to this problem is the use of heavy crude oil upgrading processes prior to a refinery or conversion processes for the upgrading of bottom-of-barrel (heavy residue) in the refinery. These upgrading processes are able to convert heavy oil into medium/light oil with reduced amounts of impurities and high content of valuable distillates, by two main principles: carbon rejection and hydrogen addition. In the latter case, catalytic hydrotreating is the most used technology in commercial application.
For a proper design of heavy petroleum hydroprocessing reactors, it is required to have simulation tools based on information collected in laboratory experiments, which consist of mathematical models to represent the phenomena occurring during heavy oil conversion. The hydroprocessing reactors are complex and complicated to model and design. The composition and properties of heavy petroleum that is converted in reactors are such that the reaction system can involve various phases, different types of catalysts, reactor configuration, reaction conditions, catalyst deactivation, and so on, making the development of a model a challenging task. Moreover, hundreds of components are present in heavy petroleum that undergo different reaction pathways and compete for the active sites of catalysts, which contribute to increasing the complexity for the formulation of the kinetics, catalyst deactivation, and reactor models.
Deactivation of hydroprocessing catalyst is mainly due to the formation of carbonaceous (coke) and metal depositions, which block the pore mouth leaving unutilized catalytic active sites. This is the most important concern during hydroprocessing of heavy oils, since the life of the catalyst and the entire economy of the process strongly depend on it. Hence, from the industrial point of view, modeling the catalyst deactivation is highly valuable. The deactivation phenomenon is commonly divided into three stages: early deactivation due to coke deposition, middle stage deactivation due to loss of sites by poisoning and pore plugging by metal-sulfide deposits, and total loss of activity by severe diffusional resistances due to almost total pore plugging.
Modeling the kinetics and catalyst deactivation is of great importance for proper reactor and process design as well as to establish suitable operating policies to compensate for the loss of catalyst activity during time-on-stream.
Deactivation of Heavy Oil Hydroprocessing Catalysts: Fundamentals and Modeling deals with this topic of current and future relevance: the loss of activity of catalyst during hydroprocessing of heavy oils. The book is organized in five chapters, each one having individual references. More than 400 references are cited and discussed within the entire book, which cover practically all the previous published literature regarding the fundamentals and modeling of catalyst deactivation during hydroprocessing.
Chapter 1 is dedicated to introduce those readers requiring an in-depth knowledge on topics related to the properties of heavy oils, such as petroleum refining processes, asphaltenes, tendency to coke formation, viscosity of crude oils and blends, stability, compatibility, and assay of petroleum. A brief description of all the petroleum refining processes is given. Detailed experimental data of light, medium, and heavy crude oil are also provided.
Chapter 2 deals with the properties of catalysts for heavy oil hydroprocessing. Particular mention is done to the description of the preparation, characterization, and evaluation of hydroprocessing catalysts using heavy oils. Some of the most important features that must be taken into account when processing heavy feeds are also discussed.
Chapter 3 is devoted to the description and analysis of the deactivation of hydroprocessing catalysts. Detailed descriptions are provided on the reactors used for hydroprocessing of heavy oils, process variables, effect of reaction conditions on catalyst deactivation, mechanisms of catalyst deactivation, and the effect of asphaltenes on it.
Chapter 4 aims at describing the characterization of spent hydroprocessing catalysts. The main characterization techniques are commented. A series of several studies on heavy oil hydroprocessing are reported in detail, which include synthesis of supports and catalysts, and evaluation of hydroprocessing catalyst and its deactivation at different reaction experimental scales.
Chapter 5 is focused on the modeling of catalyst deactivation. Various approaches are described and discussed in detail using different study cases, such as the effect of reactor configuration on the cycle length of heavy oil fixed-bed hydroprocessing, effect of different heavy feedstocks on catalyst deactivation, modeling deactivation by metal deposition, modeling short-term catalyst deactivation, modeling parallel thermal and catalytic hydrotreating including deactivation, modeling catalyst deactivation by the continuous kinetic lumping model, and application of a three-stage approach for modeling the complete period of catalyst deactivation during hydroprocessing of heavy oils. The kinetic modeling approaches, estimation of model parameters, and reactor model and catalyst deactivation models are described.
The development of correlations and models is thoroughly described with the aid of detailed experimental data collected from different reaction scales. Experimental data, explanations of how to determine model parameters, and rigorous treatment of the different topics as well as the step-by-step description of the models formulation and application will make this book an indispensable reference not only for professionals working in the area of modeling reactor and catalyst deactivation but also a textbook for full courses in chemical reaction engineering.
It is anticipated that Deactivation of Heavy Oil Hydroprocessing Catalysts: Fundamentals and Modeling becomes promptly an outstanding and distinctive book because it emphasizes a detailed description of fundamentals and modeling of catalyst deactivation, uses laboratory and commercial data for model validations, gives details of results of simulations at different conditions, and, in general, focuses on more practical issues regarding modeling of catalyst deactivation than textbooks published related to the topic in the past.
Jorge AncheytaMexico city, Mexico.2016
Nomenclature
a
0
,
a
1
,
S
0
parameters of yield distribution function Equation (5.58)
A
1
,
B
1
Riazi's correlation parameters
A
2
Goto and Smith's correlation parameter
A
fitting parameter of Equation (5.13)
Arrhenius preexponential factor for catalytic kinetic constants (h
−1
)
Arrhenius preexponential factor for deactivation constants (h
−1
)
van't Hoff preexponential factor for hydrogen sulfide adsorption constant (cm
3
/mol)
a
L
gas–liquid interfacial area (cm
−1
)
a
MOC
unit conversion factor of Equation (5.17)
A
S
sectional area of the reactor (cm
−2
)
a
S
liquid–solid interfacial area (cm
−1
)
Arrhenius preexponential factor for thermal kinetic constants (h
−1
)
B
matrix for orthogonal collocation, fitting parameter of Equation (5.13)
C
reactant or species concentration
C
A
reactant concentration of A species
asphaltene content (wt%)
reactant concentration at entrance of reactor system
basic nitrogen content (ppm)
hydrogen concentration (mol/cm
3
)
C
i
molar concentration of compound i (cm
3
/mol), content of the compound i at the reactor outlet
content of the compound i at the reactor inlet
c
(
k
,
τ
)
concentration of the species with reactivity
k
at residence time
τ
c
(
k
, 0)
concentration of the species with reactivity
k
in the feed
hydrogen sulfide concentration (mol/cm
3
)
nonbasic nitrogen content (ppm)
nickel content (ppm)
C
p
molar concentration of compound i (cm
3
/mol)
sulfur content (wt%)
vanadium content (ppm)
cwt
cumulative weight fraction
D
bulk diffusion
effective diffusivity of A in the pores of catalyst
D
(
k
)
species-type distribution function for hydrocracking reaction
D
r
restrictive diffusion coefficient
d
p
catalyst particle diameter
d
t
reactor diameter
D
0
initial diffusion coefficient within pore catalyst
D
t
diffusion coefficient within pore catalyst
activation energy for the catalytic reactions (kcal/mol)
activation energy for the thermal reactions (kcal/mol)
deactivation energy for the reaction i (kcal/mol)
EOR
end-of-run
e
exponential function basis
g
gas mass rate (g/s)
G
L
superficial liquid mass velocity (kg/m
2
s)
H
i
Henry's law constant for compound i (MPa cm
3
/mol)
H
2
/oil
hydrogen-to-oil ratio (std m
3
/m
3
)
I
degree of polynomial
I
0
Bessel function of the first kind, zero order
I
1
Bessel function of the first kind, first order
K
reaction rate constant per unit of surface area
k
hydrocracking reactivity of any species (h
−1
)
k
0
global rate constant for hydrocracking of residue
k
1
second-order rate constant for hydrocracking of residue to VGO
k
2
second-order rate constant for hydrocracking of residue to distillates
k
3
second-order rate constant for hydrocracking of residue to naphtha
k
4
second-order rate constant for hydrocracking of residue to gas
k
5
first-order rate constant for hydrocracking of VGO to distillates
k
6
first-order rate constant for hydrocracking of VGO to naphtha
k
7
first-order rate constant for hydrocracking of VGO to gases
k
8
first-order rate constant for hydrocracking of distillates to naphtha
k
9
first-order rate constant for hydrocracking of distillates to gases
k
10
first-order rate constant for hydrocracking of naphtha to gases
k
app
apparent rate coefficient
kinetic constants for the three and four kinetic models
catalytic kinetic constant for the HDAsph reaction (wt%
−0.503
/h)
catalytic kinetic constant for the HDNBN reaction (ppm
−0.792
/h)
catalytic kinetic constant for the reaction i
catalytic kinetic constant for the HDNNBN reaction (wt%
−1.154
/h)
catalytic kinetic constant for the HDNi reaction (ppm
−1.406
/h)
catalytic kinetic constant for the HDS reaction (wt%
−0.503
/h)
catalytic kinetic constant for the HDV reaction (ppm
0.290
/h)
k
d
deactivation rate constant
deactivation constant for the reaction i (h
−1
)
adsorption-equilibrium constant for the hydrogen sulfide (cm
3
/mol)
k
int
reaction rate constant
gas–liquid mass transfer coefficient for compound i (cm/s)
liquid–solid mass transfer coefficient for compound i (cm/s)
k
i
intrinsic rate coefficient
k
max
hydrocracking reactivity of the species with the highest TBP in the mixture (h
−1
)
k
p
particle rate coefficient
thermal kinetic constant for the HDAsph reaction (wt%
0.795
/h)
thermal kinetic constant for the HDNBN reaction (ppm
0.137
/h)
thermal kinetic constant for the reaction i
thermal kinetic constant for the HDNNBN reaction (ppm
0.137
/h)
thermal kinetic constant for the HDNi reaction (ppm
0.350
/h)
thermal kinetic constant for the HDV reaction (ppm
0.487
/h)
thermal kinetic constant for the HDS reaction (wt%
0.062
/h)
L
characteristic catalyst particle size
LHSV,
l
liquid hourly space velocity (h
−1
)
M
ms
molecular weight of metal sulfide compounds
MOC
concentration of metals-on-catalyst (wt%)
MOR
middle-of-run
m
deactivation rate order
m
i
deactivation order for the reaction i
total mass flow
N
reaction order, total number of species in the mixture, total concentration of sites available for any particular reaction
n
reaction order of the hydrocracking of residue
reaction order of the catalytic reaction rate i
n
j
order of reaction j
reaction order of the thermal reaction rate i
N
A
molar flow across circle area
N
i
concentration of any active sites at any time-on-stream, molar flow of compound i (mol/s)
concentration of any active sites at initial time-on-stream
N
1
concentration of sites type I
N
2
concentration of sites type II
P
total pressure (MPa)
p
i
partial pressure of compound i (MPa)
q
quench fluid mass flow rate (g/s)
R
1
first reactor
R
2
second reactor
R
universal gas constant (kcal/mol K)
reaction rate of distillates
reaction rate of gases
HDCCR reaction rate (wt%/h)
HDAsph reaction rate (wt%/h)
HDNB reaction rate (ppm/h)
HDNNBN reaction rate (ppm%/h)
HDNi reaction rate (ppm/h)
HDS reaction rate (wt%/h)
HDV reaction rate (ppm/h)
r
j
rate of jth reaction (mol/cm
3
s)
r
mol
molecular radius of metal-bearing compounds
r
N
reaction rate of naphtha
r
p
instantaneous pore radius
r
R
reaction rate of residue
r
VGO
reaction rate of VGO
S
cross-flow area
SOR
start-of-run
S
p
total geometric external area of particle
t
time
t
time-on-stream (h)
T
absolute temperature
T
0
boiling temperature of the lightest compound in the feed mixture
TBP
true boiling point of any pseudocomponent (K)
TBP(h)
highest boiling point of any pseudocomponent in the mixture (K)
TBP(l)
lowest boiling point of any pseudocomponent in the mixture (K)
T
mean
mean absolute temperature
TOS
time-on-stream
t
∞
catalyst life
u
G
gas superficial velocity (cm/s)
u
L
liquid superficial velocity (cm/s)
V
p
total geometric volume of catalyst
v
molar liquid volume
x
hydrocracking reactivity of any species (h
−1
); variable of integration
x
MOC
fraction concentration of metals-on-catalyst (MOC)
y
D
distillates composition
y
G
gas composition
y
N
naphtha composition
y
R
residue composition
y
VGO
VGO composition
W
cat
weight of catalyst (g)
WHSV
weight hourly space velocity (h
−1
)
wt
weight fraction of species
wt
1,2
(
τ
)
concentration in weight fraction of any pesudocomponent with arbitrary boiling point range as function of residence time
z
position within pore, Axial coordinate along the reactor
Subscripts
0
initial
f
feed
Asph
asphaltenes
BN
basic nitrogen
CCR
Conradson carbon residue
HDS
hydrodesulfurization
HDNi
hydrodenickelation
HDV
hydrodevanadization
HDAsph
hydrodeasphaltenization
HDCCR
hydro-Conradson carbon residue conversion
HDM
hydrodemetalization
HDNNBN
hydrodenitrogenation of nonbasic nitrogen
HDNBN
hydrodenitrogenation of basic nitrogen
i
S, Ni, V, Asph, CCR, NBN, BN
in
intrinsic
in
inlet to the following catalytic bed
NBN
nonbasic nitrogen
Ni
nickel
out
outlet of the previous catalytic bed
p
product
q
quench stream
r
restrictive
S
sulfur
t
instantaneous
V
vanadium
Greek Symbols
α
geometry parameter, model parameter in Equation (5.62), fitting parameter of Equations (5.16) and (5.58)
α
1
rate constant of diminution on sites concentration type I
α
2
rate constant of diminution on sites concentration type II
β
proportional constant in Equation (5.101), fitting parameter of Equations (5.16) and (5.58)
Γ
gamma function
γ
ratio of instantaneous pore radius to initial pore radius
γ
fitting parameter of Equations (5.16) and (5.58)
Δ
H
ads
enthalpy of adsorption of hydrogen sulfide (kcal/mol)
Δ
H
R
overall heat of reaction (kJ/kg sulfur)
δ
metal sulfide thickness within catalyst pore, model parameter of hydrocracking yield distribution function (
p
(
k
,
K
))
є
metal sulfide molecules per molecule of reactant
ɛ
0
bed void fraction
ɛ
L
dynamic liquid holdup
ζ
dimensionless intraparticle position
η
effectiveness factor
η
0
initial effectiveness factor
η
t
effectiveness factor affected by diffusional resistances
η
EF
effectiveness factor
η
CE
solid–liquid contact efficiency factor, external catalyst wetting efficiency
ϕ
,
φ
catalyst activity
ϕ
A
deactivation function of active sites
ϕ
D
deactivation function due to deposits
φ
j
deactivation function of jth reaction
φ
Coke
deactivation function for coking reactions
φ
Metals
deactivation function for metals deposition
θ
deactivation function for metals deposition
λ
ratio of molecule radius to pore radius
μ
dynamic liquid viscosity
ρ
G
gas density at process conditions (g/cm
3
)
ρ
ms
metal sulfide compound density
ρ
L
liquid density at process conditions (g/cm
3
)
ρ
oil
heavy oil density
τ
dimensionless time
τ
inverse of space velocity or residence time (h)
φ
thiele modulus
χ
dimensionless reactant concentration
Superscripts
app
apparent
G
gas phase
L
liquid phase
Q
quench fluid
S
solid phase
Chapter 1Properties of Heavy Oils
1.1 Introduction
The physical properties and chemical composition of petroleum vary from one source to another. The petroleum fractions, that is, distillates, are separated from each other by fractionated distillation according to boiling points. The lighter fractions, straight-run naphtha and gas oil, are used to produce commercial fuels, gasoline and diesel, respectively. However, bottoms-of-barrel (heavy residua) obtained by distillation of crude oils need further processing. An example of chemical composition of crude oils is given in Table 1.1 in terms of SARA (Saturates, Aromatics, Resins, and Asphaltenes) analysis. It is clearly seen that the composition varies remarkably, for instance, asphaltenes content in crude oils ranges from 5.9 to 23.9 wt%, concentrating more in the heavy petroleum. Another important observation is that heteroatoms (N and S) and metals concentrate in asphaltene fraction. In other words, most of these crude oil impurities are of asphaltenic nature. These aspects and the complex nature of asphaltenes are crucial facts when studying catalyst deactivation.
Table 1.1 Example of Chemical Composition of Various Crude Oils
wt%
Crude Oil (wt% of the total)
AR (345 °C+)
S
N
V
Ni
Ni
V
Maya (21°API)
Saturates
21.2
0.9
3.3
–
–
–
–
Aromatics
27.1
24.4
8.2
0.4
3.3
2.7
2.7
Resins
30.6
38.7
39.6
17.9
17.7
13.0
12.9
Asphaltenes
21.1
36.0
48.9
81.7
79.0
84.3
84.4
Kern River (13°API)
Saturates
23.3
0.2
2.7
–
–
–
–
Aromatics
30.7
30.7
4.2
7.5
4.5
1.8
2.7
Resins
40.1
60.3
77.3
52.7
63.0
22.8
16.7
Asphaltenes
5.9
8.8
15.8
39.8
32.5
75.4
80.6
Arabian Heavy (27°API)
Saturates
0.2
6.7
–
–
–
–
0.2
Aromatics
29.6
8.4
3.4
10.4
5.2
1.6
29.6
Resins
46.3
43.8
25.2
28.0
14.2
11.8
46.3
Asphaltenes
23.9
41.1
71.4
61.6
80.6
86.6
23.9
AR, Atmospheric residue.
In the particular case of heavy crude oil, the typical and widely accepted definition is that heavy petroleum is any type of crude oil that does not flow easily. API gravity is the most common parameter to define how heavy or light a crude oil is. API gravity is correlated with the specific gravity (sg) or density by means of the following equations:
Heavy crude oils possess low API gravity; thus, the API gravity is an inverse measure of the density of petroleum. Heavy crude oils are generally considered as those samples having an API gravity of less than 20°, while extra-heavy crude oils have less than 10°API, both with gas-free viscosity between 100 and 10,000 cP at original reservoir temperature. Heavy oils are then characterized by high viscosities (i.e., resistance to flow) and high densities compared with light crude oil.
In general, heavy oils exhibit a wide range of physical properties. While properties such as viscosity, density, and boiling point may vary widely, the ultimate or elemental analysis varies over a narrow range for a large number of samples. The carbon content is relatively constant, while the hydrogen and heteroatom contents are responsible for the major differences in various heavy oils.
Heavy oils are constituted by heavy hydrocarbons and several metals, predominantly in the form of porphyrins. Heavy feeds also contain aggregates of resins and asphaltenes dissolved in the oil fraction held together by weak physical interactions.
The main problems that heavy crude oil presents during different steps of storage, transportation, and processing are low processing capacity in the refineries, low mobility through the reservoir because of its high viscosity, and difficult and costly transportation from the platform to the ground and to the refineries.
For transportation purposes, viscosity and density (or API gravity) are the most important parameters. Frequently, heavy crude oils with an API gravity of less than 16° cannot be transported without a prior reduction in their viscosity, as this type of crudes come along with viscosities ranging from a few thousands to millions of centipoises (cP) at reservoir temperature, while 250 cSt at 100 °F is a normal maximum desired pipeline viscosity.
Due to the different properties that the various crude oils exhibit around the world, several classifications have been proposed. The classifications of petroleum take into consideration physical properties, distillates properties, chemical structure, origin, and so on. For instance, if the sulfur content in a crude oil is high, the petroleum is classified as “sour,” while if this content is low the petroleum is termed as “sweet.” On the other hand, if the API gravity is low, the petroleum is termed as “heavy” and if the API gravity is high the petroleum classification is termed “light.” Generally speaking, petroleum is classified as follows (Ancheyta and Speight, 2007):
Light Crude Oil
. It is also called conventional oil and has an API gravity of at least 20° and a viscosity less than 100 cP.
Heavy Crude Oil
. It is a dense and viscous oil that is chemically characterized by its high content of asphaltenes (very complex and large molecules). Its upper limit of API gravity is 20° and a viscosity of 100 cP.
Extra-Heavy Crude Oil
. It has an API gravity of less than 10°.
Bitumen
. It is also called “tar sands” or “oil sands.” It has similar properties to that of heavy oil but is yet more dense and viscous. The main difference between bitumen and heavy oil is that the former does not flow at all. Natural bitumen is oil having a viscosity of greater than 10,000 cP.
Heavy crude oils have low API gravity and high amount of impurities. In general, it is known that the lower the API gravity, the higher the impurities content. Such properties make the processing of heavy feeds different from that used for light distillates, causing several problems such as permanent catalyst deactivation in catalytic cracking and hydrocracking processes caused by metal deposition, temporary deactivation of acid catalysts due to the presence of basic nitrogen, higher coke formation, and lower liquid product yield as a result of high Conradson carbon and asphaltene contents, products with high content of sulfur.
The complex nature of heavy crude oils is the reason why their refining becomes so difficult. Therefore, an evaluation of the overall chemical and physical properties of petroleum feeds is mandatory to determine the processing strategy. Apart from having low API gravity (high density), high viscosity, and high initial boiling point, heavy oils exhibit higher content of sulfur, nitrogen, metals (Ni and V), and high-molecular-weight material (asphaltenes).
1.2 Refining of Petroleum
A petroleum refinery is mainly designed to produce fuels, for example, gasoline, jet fuel, and diesel. To achieve this goal, the crude oil is subjected to a series of operations and processes. Due to their high amount of impurities (particularly sulfur), straight-run distillates cannot be used directly as fuels; in addition, they possess octane and cetane numbers (naphtha and gas oil, respectively) that are not appropriate for engines. To convert them into suitable materials for fuel production, they need certain treatment, which is carried out in different refining processes. The following sections present a brief description of the main processes used in a petroleum refinery (Ancheyta, 2011, 2013):
1.2.1 Desalting
The first separation process that takes place at the front end of a petroleum refinery is desalting. Its main objective is to prevent corrosion and fouling of downstream lines and equipment by significantly reducing the salt content of oil. Desalting is normally considered a part of the crude distillation unit since heat from some of the streams in the atmospheric distillation is used to heat the crude in the desalting process. Sodium, calcium, and magnesium chlorides, in the form of crystals or ionized in the water present in the crude, are the most frequently found salts in crude oil. The high temperatures found during crude oil refining could cause water hydrolysis if salt is not removed, forming hydrochloric acid (HCl), which will provoke serious corrosion problems in the equipment. Nonremoved salt can also cause fouling problems in pipes, heat transfer equipment, and furnace. Deactivation of catalysts, for example, zeolite-type catalysts used in fluid catalytic cracking (FCC), may be enhanced by metals from salts, particularly sodium. The maximum allowed salt content in the feed to crude distillation units is typically 50 PTB (pounds of salt per thousand barrels of crude oil).
Desalting can be carried out in single stage (dehydration efficiency of ∼95%) or in two (dehydration efficiency of ∼99%) stages. Dehydration efficiency can be compared with desalting efficiency as most of the salt passed from the organic phase into the water phase if mixing is good. The decision of single or double stage depends on the requirements of the refinery. Typical desalters have an arrangement of two electrodes that generate an electric field among the emulsion causing the droplets vibrate, migrate, and collide with each other and coalesce.
Apart from removing salt, electrostatic desalting also eliminates water and suspended solids in crude oil. Water removal is important to reduce pumping costs and to avoid its vaporization when passing through the preheat train; otherwise, due to high pressure it causes disturbances and vibrations and eventually plant shutdown.
