Optimizing Bitumen Upgrading Scheme –

7/22/2019 Optimizing Bitumen Upgrading Scheme

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Optimizing Bitumen Upgrading ScModeling and Simulation Appr

Mugurel Catalin Munteanu, Jinwen ChenCanmetENERGY, Natural Resources Canada

One Oil Patch Drive, Devon, AB, T9G 1A8, Canada

2012 AIChE Spring Meeting, April 1-5, 2012, Houston, TX, U


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Research Background

The production of Canadian bitumen is expected to increas

from the current 1.3 MBPD to 3.0 MBPD by 2018 and 5.6 M

The carbon footprints, or greenhouse gas (GHG) emission,bitumen production, upgrading and refining to produce cleafuels is higher than those related to conventional crudes.

Incremental or evolutional steps to improve process efficien

energy consumption and increase raw crude utilization to ptransportation fuels remain critically important to the indust

Process modeling and simulation can help refineries to imphydrotreating performance and reduce energy consumptiono eratin conditions h drotreater confi urations and catal


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Research Objectives

Conducting simulation and optimization of the entire bupgrading schemes to optimize operation, improve proefficiency, minimize energy consumption

Each process and unit involved in the whole upgradinscheme (such as distil lation, coking, hydrotreating, etmodeled and simulated usin ASPEN-HYSYS or in-hdeveloped programs) using relatively simple models

Identify the most bottlenecking upgrading stepsuidance and directions for industrial retrofittin

research and development.


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What are Oil Sands and Bitumen?

Wikipedia: Wikipedia:

Oil sands are a type of bitumen deposit. The

sands are naturally occurring mixtures of sand,

clay, water, and an extremely dense and viscousform of petroleum called bitumen.

Bitumen is a mixture of organic liqui

black, sticky, entirely soluble in carb

primarily of highly condensed polycyNaturally occurring or crude bitumen

petroleum which is so thick and hea

Alberta Energy:

Oil sand is a naturally occurring mixture of sand,

clay or other minerals, water and bitumen, which

is a heavy and extremely viscous oil that must be

treated before it can be used b refineries to

diluted before it will flow. At room te

molasses.

Alberta Energy:

A heav black viscous oil that must

produce usable fuels such as gasoline and

diesel.

convert it into an upgraded crude oi

refineries to produce gasoline and d

Alberta's bitumen deposits were knoreferred to as oil sands.


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Production of Canadian Bitumen from Oil Sa

Two major technologies: Open Pit Mining

In-situ

-

Current production:

1.6 Million bpd (2010)

(53% mining; 47% in-situ)

Recoverable with current173 billion barrelsPotentially recoverable w+315 billion barrels

(all mined bitumen is upgraded in Canada)

Forecast:2.9 million bpd by 20203.5 million b d b 2025

Source: Alberta Energy and Uti


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Bitumen Production from Oil Sands Minin

Composit

Mineral s

Bitumen:

Water: ~3

Tailings m

~90% bitumen recovery from oil sands with mining and

extraction 3-4 barrels of water consumed for one barrel of

Source: Bantrel Corp., www.bantrel.com

bitumen


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Bitumen Production from Oil Sands In-Si

Boiler

Separator

Bitumen to

upgrader

Bitumen r

Less than

water is c

Source: Alberta Energy Resources Conservation Board, www.ercb.ca


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Why Bitumen Upgrading?

All petroleum refineries are designed to process conven

oils. Raw bitumen cannot be directly processed in refinemuch higher viscosity, sulphur, metal and asphaltene co

Bitumen upgrading is an integrated process during whic

goes through a series of chemical and physical treatmen

s ens y, v scos y, car on, su p ur an me a con en

increase its hydrogen content. Such a bitumen-derived o

synthetic crude oil (SCO).

Ultimate objective: to increase its processibility and mar


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Properties of Bitumen and Conventional Cr

Bitumen(Cold Lake, Alberta)

Conven(A

Density(16C), g/ml (API gravity) 1.00 (10.0) 0.8

Viscosity @ 15C/ 40C, cp 235000/1050 1

Boiling range, C 250 to over 800 3

Sulphur/nitrogen content, wt% 4.0/0.42 1

Metal content (nickel/ vanadium),ppm 69/190

Carbon content wt% 84.0

Hydrogen content, wt% 10.5

Saturates, wt% 30

Aromatics, wt% 70

Asphaltenes 10

Source: Environment Canada database


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Schematic Diagram of Bitumen Upgrading t

DiluentRecovery

Diluted

Bitumen

NaphthaNaphtha

Hydrotreater

Light Gasoi l

Naphtha

Unit

VacuumDistillationUnit

Bitumen

Heavy Gasoil

Hydrotreater

Hydrotreater

LGO

LGO

HGO

Coker

OilResidue

Separato

r

HGOTLP

Hydrogen

H2

H2

Hydroconversion

Residue

Plant

Bitumen upgrading scheme


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Properties of Typical Athabasca Bitumen andProducts

Property Unit Bitumen Bitumen Vacuum Naphtha Light Gas H

Density @15C g/mL 0.9960 0.9957 1.0670 0.782 0.941

API gravity API 10.57 10.62 1.10 49.4 18.9

. . . . .

Nitrogen wppm 5423 5421 10590 237 1600

Hydrogen wt% 10.45 12.31 10.57 12.36 10.87

Carbon wt% 82.82 85.30 82.5 85.1 84.8

H/C atomic

ratio

- 1.53 1.75 1.43 1.74 1.54


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Simulation of Coking-Based Upgrading Sch

Coker

Hysys Bitumen upgrading flowsheet coking based


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Coking-based scheme streams properties

Dilue

Bitumen Diluent DilBit Return

Properties Units

Mass flow kg/h 494800 126600 620800 126600

Nitrogencontent wppm 5423.00 0.00 4318.00 10.80

. . . .

Aromatics vol% 61.45 0.53 46.22 3.40

Density g/ml 0.9960 0.7643 0.9381 0.7670

API API 10.57 53.63 19.34 52.99

CCR wt% 9.53 0.00 7.59 0.00


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-

Vacuum distillation

Napht Vacuum

Coker

Lights

Coker

Properties Units

Mass flow kg/h 6672 75720 188000 223900 19140 33590

Nitrogen

. . .

Sulfur

content wt% 0.20 1.53 3.48 5.98 0.00 0.95

Aromatics vol% 4.30 26.14 54.61 82.08 0.00 11.00

Density g/ml 0.7802 0.8836 0.9753 1.0670 0.6500 0.7535 0

API API 49.87 28.64 13.58 1.10 86.20 56.28

. . . . . .


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-

Naphtha Diesel

Mixed

Naphtha

Hydrotreated

Naphtha Mixed Diesel

Hydrotreated

Diesel G

Properties Units

Mass flow kg/h 40260 37290 102600 102000 2

Nitrogencontent wppm 75.85 21.96 446.2 432.2 2

Sulfur

content wt% 0.83 0.08 2.13 0.14

Aromatics vol% 9.92 5.98 32.40 26.37

Density g/ml 0.7578 0.7591 0.8830 0.8516 0

API API 55.22 54.91 28.74 34.66

CCR wt% 0.00 0.00 0.03 0.00


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Simulation of Hydroconversion-Based UpgrScheme

Hydroconverter

reactor

H s s Bitumen u radin flowsheet -

hydroconversion based


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Hysys Bitumen upgrading flowsheet -

hydroconversion based


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y roconvers on- ase sc eme s reams proper es

Diluent Re

Diluent

Bitumen Diluent DilBit Return

Properties Units

Mass flow kg/h 494800 126600 620800 126600

Nitrogen

content wppm 5423.00 0.00 4318.00 9.95

Sulfur

content wt% 4.30 0.00 3.43 0.14

Aromatics vol% 61.45 0.53 46.22 3.23

Density g/ml 0.9960 0.7643 0.9381 0.7653

API API 10.57 53.63 19.34 53.39

CCR wt% 9.53 0.00 7.59 0.00


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Hydroconversion-based scheme streams properties

Vacuum Distillation Hydrocrac

Naphtha LVGO HVGO

Vacuum

Bottoms Residue

EB

Lights

Ends

EB

Naphtha

EB

Dies

Properties Units

Mass flow kg/h 1781 80990 187500 224000 348400 16230 17150 7637

Nitrogen

content wppm 12.75 194. 1553. 10590 9202 - 8.0 162

Sulfur

content % 0.18 1.47 3.48 5.97 4.21 - 0.12 0.64

Aromatics vol% 3.83 25.13 54.63 82.07 69.19 - 21.5 29.0

Density g/ml 0.7723 0.8805 0.9754 1.0670 1.0780 0.6495 0.7423 0.878

API API 51.72 29.20 13.57 1.10 -0.30 86.35 59.13 29.6

CCR wt% 0.00 0.00 1.41 19.85 17.72 - 0 0


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y roconvers on- ase sc eme s reams proper es

NaphthaHydrotreater

DieselHydrotreater

Mixed

Naphtha

Hydrotreated

Naphtha

Mixed

Diesel

Hydrotreated

Diesel

Mix

Properties Units

Mass flow k /h 18930 16690 157400 159900 2

Nitrogen

content wppm 8.45 0.39 178.47 21.18 14

Sulfur

content % 0.13 0.01 1.07 0.16

Aromatics vol% 19.87 10.23 27.01 16.41 4

Density g/ml 0.7450 0.7465 0.8794 0.8516 0

API API 58.43 58.04 29.40 34.66 1

CCR wt% 0.00 0.00 0.00 0.00


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SCO Properties Comparison

SCO SCO

Coking-based

scheme

Hydroconversion

scheme

Properties Units

Mass flow kg/h 400500 454100

Nitrogen

content wtppm 320.30 85.02

content % 0.12 0.10

Aromatics vol% 39.45 20.35

Density g/ml 0.8607 0.8561

API API 32.91 33.78

CCR % 0.00 0.00

Yield vol% 93.65 106.80

Yield wt% 81.01 91.86


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Diluent Recover Unit Vacuum Distillation Column

Diluent Recovery and Vacuum DistillationColumn Operating Conditions

Number of stages 24 Number of stages

Feed stage 24 Feed stageDiluent return

stage

Overhead liquid

outlet

Naphtha withdraw

stage

Atmospheric bottoms

stage

Bottom liquid

outlet

Light vacuum gas oil

Withdraw stage

Pressure (top) 120 kPa

Heavy vacuum gas oil

Withdraw stage

Vacuum bottoms

Pressure (bottom) 140 kPa Withdraw stage

Diluent D86

90% Temperature 206.1C Pressure top

Pressure bottom


D86 90% temperature


D86 90% temperature

ap a y e

Light vacuum gas oil yield

Heavy vacuum gas oil yield

Vacuum bottoms yield


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Operating conditions Coker Hydroconverter

Reactor catalyst

densit k /m3 N/A 1500

Coker and Hydrocracker Operating Conditio

LHSV h-1 N/A 0.48

Reactor pressure MPa Atmospheric 16Reactor temperature C 482.2 430.0

Sul hur conversio wt% N/A 71.5

Conradson carbon residue conversion wt% N/A 48.5

Nitrogen conversion wt% N/A 51.6

Aromatics conversion wt% N/A 39.1

H consum tion SCF/bbl N/A 1512

Total liquid product yield wt% 70.6 92.2

NH3 yield wt% 0.45 4.8

H2S yield wt% 2.0 3.0

Li ht ends initial boilin oint C -60.0 -60.0

naphtha initial boiling point C 37.0 37.0

diesel initial boiling point C 242.7 204.0

gas oil initial boiling point C 402.2 371.0

Residue initial boilin oint C N/A 565.0

Light ends yield wt% 8.6 5.1

Naphtha yield wt% 15.0 5.3

Diesel yield wt% 12.0 23.8

Gas oil ield wt% 35.0 27.0

Coke/Residue yield wt% 27.0 38.8

Residue conversion wt% 100.0 61.2


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Operating Conditions for Hydrotreaters inCoking-Based Scheme

Naphtha

hydrotreater

Diesel

hydrotreater

Number of reactors 2 2

Number of beds/ reactor 2 2

Reactor catalyst density kg/m3 1500 1500

Reactor ID m 2.5 m 2.5

Catalyst loading kg/bed 18,000 18,000

Bed voidage 0.37 0.37

Reactor pressure kPa 5,000 8,000

Reactor temperature C 285.0 351.2

Gas/oil ratio STD m3/m3 300.0 300.0

Sulphur conversion wt% 90.0 93.3

Conradson carbon residue conversion wt% 0.0 100.0

Nitrogen conversion wt% 71.1 3.1

Aromatics conversion wt% 39.7 18.6

H2

consumption SCF/bbl 170.0 581.3

Product yield wt% 99.9 99.6


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Operating Conditions for Hydrotreaters inHydroconversion-Based Scheme

ap a

hydrotreater

ese

hydrotreater

Number of reactors 2 2

Number of beds/ reactor 2 2

eactor cata yst

density kg/m3 1500 1500

Reactor ID m 2.5 2.5

Catalyst loading kg/bed 18,000 18,000

Bed voidage 0.37 0.37

Reactor pressure kPa 5,000 8,000


Gas/oil ratio STD m3/m3 300.0 300.0

Sulphur conversion wt% 88.8 78.5

Conradson carbon residue conversion wt% 0.0 100.0

Nitrogen conversion wt% 67.6 78.8

roma cs convers on w . .

H2 consumption SCF/bbl 170.0 892.4

Product yield wt% 99.8 99.5


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Conclusions

Two major commercially used bitumen upgrading schemes are simulated w

properties and flow rates of the intermediate and final products in each scheestimated and compared.

o e s or t e atmosp er c st at on co umn, t e vacuum st at on co um

hydroconverter, and the hydrotreaters are calibrated according to the pilot p

industrial data.

Hydroconversion-based upgrading scheme has a SCO yield of about 92wt%

co ng- ase upgra ng sc eme as a y e o a ou , w c are

commercial operation values.

SCO generated from the hydroconversion-based scheme has higher quality

nitrogen and aromatics contents) than that generated from coking-based sc

The simulation is versatile and multiple options can be considered for differe

and therefore can be considered as an important tool to guide bitumen upgr

design and operation.


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Partial funding for this study was provided by the

n er epar men a rogram o nergy esearc a

Development (PERD 1.1.3).


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Optimizing bitumen upgrading scheme modeling and simulation approach

Jinwen Chen and Mugurel Munteanu

CanmetENERGY, Natural Resources CanadaOne Oil Patch Drive, Devon, AB, T9G 1A8, Canada

Abstract

The present study focuses on modeling and simulation of the bitumen upgrading andrefining schemes using the HYSYS modeling software in conjunction with pilot plantexperimental data obtained at CanmetENERGY, as well as any available commercialoperation data. Two existing upgrading schemes were investigated: coking-based andhydroconversion-based, which are commonly used by oil sands companies. The majorupgrading units, such as atmospheric and vacuum distillation columns, coker/hydroconverter,and hydrotreaters, were depicted in detail and the commercial operating conditions for each ofthem were identified.

The coking-based upgrading scheme was simulated under various operating scenarios.

Using existing data, mass balance was performed and a synthetic crude oil yield close to82wt% was achieved based on the initial diluted bitumen feedstock. The hydroconversion-based upgrading scheme was also studied in this work by replacing the coker with ahydroconverter (an ebullated bed reactor) and by utilizing commercially available data underdifferent operating conditions.

Introduction

About 1.6 million barrels of combined mining and in-situ based bitumen is currentlyproduced. Over 50% of this production is upgraded to synthetic crude oil (SCO). To date,virtually all of the mining based bitumen is upgraded. Much of the synthetic crude is processed

in Canadian refineries today, but increasingly large volumes will be marketed in the northerntier US states as the industry expands its output1.Production of transportation fuels from Canadian bitumen feedstocks requires either

new integrated upgrading and refining facilities, or converting existing refineries that useconventional crudes to allow higher input of bitumen feedstocks. In either case, it is importantand useful to optimize the entire upgrading and refining scheme under different processconfigurations and product scenarios to minimize the process related energy intensity/consumption, at the same time to achieve the best economic benefits. Such optimization canprovide guidelines to either existing upgrading and refining operations or process design fornew upgraders and refineries.

There are two major commercial primary bitumen upgrading processes: coking and

hydroconversion. Historically coking has predominated as the choice for primary upgrading. Asthe first step to produce a bottomless (zero residue) SCO, it handles the higher solids andwater content in mining based bitumen more easily. The by-product coke helps to trap solids,and concentrate and remove metals as well as some of the sulphur and nitrogen. However, thetotal liquid product yield is relatively low due to the formation of coke. In comparison, ebullatedbed catalytic hydroconversion process has much higher total liquid product yield due to thehydrogen addition. In some commercial operations the conversion of bitumen is not 100% in


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the hydroconversion unit, generating a small portion of residue that is further processed with acoking unit.

Both of the two primary processes produce liquid products with boiling ranges similar toconventional crudes. However they have high concentrations of impurities, such as sulphurand nitrogen. The secondary hydrotreating processes remove these impurities to producesweet blending stocks for the SCO without changing much the boiling range of the liquid. TheSCO boiling range is essentially controlled by the primary upgrading step. In reviewing some ofthe major challenges that the oil sands industry is facing, bitumen upgraders need to capitalizeon, or address, the following:

(a) Take advantage of some relatively minor upgrading at the recovery stage(b) Take advantage of the necessity to move to alternative energy and hydrogen sources,

particularly internally generated residues, which is a trend with very large impact onmain upgrading process selection

(c) Address major environmental concerns in an integrated way(d) Meet future crude quality requirement with existing facilities

The oil sands industry by its very size is in a position to influence technologydevelopment for their relatively unique needs. It is important to identify the possible avenuesfor better upgrading technology for current and future projects. The most important technology

developments for existing commercial processes are: coking, ebullated bed hydroconversion,moderate primary upgrading, hydrotreating, hydrocracking, and catalyst development.

The objective of this study is to identify the technologies and different operatingconditions that directly meet the future trends in current upgrader performances. Improvementin process efficiency and bitumen utilization will benefit from advanced modeling techniques.

Advanced modeling can also help to achieve better process control. Advanced simulationresults also provide valuable information for understanding bitumen processabilities andincreasing marketability, reducing GHG emissions and other related environmental impacts inbitumen upgrading and refining.

Modeling and Simulation Bases

Figure 1 presents a simplified generic flow diagram of current upgrading process. Thediluted bitumen from the extraction and froth treatment plant is distilled in the diluent recoveryunit (DRU), or atmospheric distillation unit (ADU). The diluent is recovered and recycled to theextraction plant. The bitumen constitutes the feed for the vacuum distillation unit (VDU). Thedistilled products from the VDU are routed directly to naphtha, light gas oil and heavy gas oilhydrotreaters, and the vacuum-topped bitumen is either thermally cracked in the coker orcatalytically hydroconverted in the ebullated bed hydroconverter. The total liquid product (TLP)from the coker or hydroconverter is fractionated into naphtha, light gas oil and heavy gas oil,which are combined with the corresponding fractions from the VDU. The combined naphtha,light gas oil and heavy gas oil are further hydrotreated in three individual hydrotreaters. Theliquid products from the hydrotreaters are blended to form the final upgrading product SCO,

which is shipped to refineries in Canada and the US by pipeline for further refining2,3.Table 1 summarizes the properties of typical Athabasca bitumen and its distilled

products. The bitumen contains about 4.3wt% of sulfur and the API gravity is about 10.6.


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DiluentRecoveryUnit

Coker

Diluted

Bitumen

Diluent

Naphtha

VacuumD

istillationUnit

Bitumen

Oil

Residue

Naphtha

Hydrotreater

Separator

Heavy GasoilHydrotreater

Light Gasoil

Hydrotreater

Synthetic

Crude Oil

Naphtha

LGO

HGOTLP

Treated

Naphtha

Hydrogen

Plant

Diluent

H2

H2

Hydroconversion

Coke

LGO

HGO

Residue

TreatedLGO

Treated

HGO

DiluentRecoveryUnit

Coker

Diluted

Bitumen

Naphtha

Hydrotreater

Naphtha

VacuumD

istillationUnit

Bitumen

Oil

Residue

Separator

Heavy GasoilHydrotreater

Light Gasoil

Hydrotreater

Synthetic

Crude Oil

Naphtha

LGO

HGOTLP

Treated

Naphtha

Hydrogen

Plant

H2

H2

Hydroconversion

Coke

LGO

HGO

Residue

TreatedLGO

Treated

HGO

Figure 1. Simplified generic schematic diagram of upgrading process

Table 1. Properties of typical Athabasca bitumen and its distilled products

Property Unit Bitumen

Bitumenatmospheric

bottomsVacuumbottoms Naphtha

Lightgas oil

Heavygas oil

Syntheticcrude oil

Density g/cm3

0.9960 0.9957 1.0670 0.7820 0.9410 1.0020 0.8650

API gravity API 10.6 10.6 1.1 49.4 18.9 9.8 32.0

Sulfur wt% 4.3 4.3 6.0 1.7 3.6 4.3 0.15

Nitrogen wppm 5423 5421 10590 237 1600 3780 800

Hydrogen wt% 10.5 12.3 8.5 12.4 10.9 10.2 12.6

Carbon wt% 82.82 85.3 83.7 85.1 84.8 84.2 86.6

H/C atomic ratio - 1.53 1.8 1.4 1.7 1.5 1.5 1.8

The present work focuses on modeling and simulation of the bitumen upgrading andrefining schemes using the HYSYS modeling software in conjunction with pilot plant

experimental data obtained at CanmetENERGY, as well as any available commercialoperation data and published literature data4-12. Two existing upgrading schemes areinvestigated: coking-based and hydroconversion-based. The major upgrading units,atmospheric and vacuum distillation columns, coker/hydroconverter, and hydrotreaters, aredepicted in detail and the commercial operating conditions for each of them were identified.


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Results and DiscussionsSimulations are performed for both schemes, coking-based and hydroconversion-based

with the same bitumen-to-diluent ratio as feedstock (75:25 vol/vol). The processing capacitiesare assumed to be the same at 100K barrel/day diluted bitumen. The properties of the bitumenfeed, intermediate streams and the final SCO for both simulated schemes are presented inTables 2 to 4 (coking-based scheme), Tables 5 to 7 (hydroconversion-based scheme), andTable 8 (synthetic crude oil), respectively. The upgrading units are modeled and calibratedadequately in order to simulate commercial operating conditions and to generate data ofindustrial interest. Since there are no available models for coking and ebullated bedhydroconversion in HYSYS, pilot plant experimental data obtained at CanmetENERGY andpublished in literature are used to develop the coker and hydroconverter models. Simulationresults show that a SCO yield of about 81wt% can be achieved based on the initial dilutedbitumen feedstock for the coking-based scheme. In contrast, the hydroconversion-basedupgrading scheme generates a SCO yield of about 92wt%. The difference in the SCO yieldbetween the two schemes is due to the fact that the ebullated bed hydroconversion unitcompletely converts the vacuum bottoms into gaseous and liquid products without generatingany solid residual material. As seen in Table 8, the SCO from hydroconversion-based schemehas slightly lower concentrations of sulfur, nitrogen and aromatics than that from coking-based

scheme. This results from the hydrodesulphurization, hydrodenitrogenation and hydrogenation,in addition to the hydrocracking of heavy molecules, occurring in the ebullated bedhydroconverter.

The major upgrading units are investigated in detail and calibrated accordingly tocommercial operating conditions. In this paper, the authors present only one set of operatingconditions and parameters for the two above mentioned upgrading schemes as shown inTable 10. It is noted that the atmospheric distillation column, the vacuum distillation columnand the hydrotreaters are operated under the same conditions for both schemes. The onlydifference is that one uses coking and the other one uses hydroconversion. The operatingconditions are summarized in Table 9.

As seen in Tables 11 and 12, even if the hydrotreaters are operated under the same

conditions, the hydrogen consumptions for diesel and gas oil in the hydroconversion-basedupgrading are significantly higher than those in the coking-based upgrading. This is becausefeed flow rates to these two units in the hydroconversion-based scheme are much higher thanthose in the coking-based scheme (Tables 4 and 7). Consequently the hydroconversion-basedupgrading scheme has a higher SCO yield at the cost of higher hydrogen consumption.

Table 2. Coking-based scheme streams properties

Bitumen Diluent DilBitDiluentreturn

Atmosphericbottoms

Mass flow kg/h 494800 126600 620800 126600 494300

Nitrogen

content wppm 5423.0 0.0 4318.0 10.8 5420.0Sulfur content Wt% 4.3 0.0 3.4 0.15 4.3

Aromatics content vol% 61.5 0.5 46.2 3.4 60.4

Density g/cm3 0.9960 0.7643 0.9381 0.7670 0.9949

API gravity API 10.6 53.6 19.3 53.0 10.7

Conradson carbon residue wt% 9.5 0.0 7.6 0.0 9.5


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Vacuum distillation Coker

Naphtha

Lightvacuumgas oil

Heavyvacuumgas oil

Vacuumbottoms

Cokerlightsends

Cokernaphtha

Cokerdiesel

Cokergas oil Coke

Mass flow kg/h 6672 75720 188000 223900 19140 33590 26870 78370 60460

Nitrogen

content wppm 14.68 202.8 1552.00 10590.0 0.0 88.0 1132.0 3100.0 18370.0Sulfurcontent wt% 0.20 1.5 3.5 6.0 0.0 0.9 3.8 3.9 7.9

Aromaticscontent vol% 4.3 26.1 54.6 82.1 0.0 11.0 50.0 57.0 89.0

Density g/cm3 0.7802 0.8836 0.9753 1.0670 0.6500 0.7535 0.8814 0.9798 1.0690

API gravity API 49.9 28.6 13.6 1.1 86.2 56.3 29.1 12.9 0.9

Conradsoncarbonresidue wt% 0.0 0.0 1.4 19.9 0.0 0.0 0.1 1.5 20.4


Naphthahydrotreater

Dieselhydrotreater

Gas oilhydrotreater

Mixednaphtha

Hydrotreatednaphtha

Mixeddiesel

Hydrotreateddiesel

Mixedgas oil

Hydrotreatedgas Oil

Mass flow kg/h 40260 37290 102600 102000 266400 261200

Nitrogencontent wppm 75.9 22.0 446.2 432.2 2007.0 319.2

Sulfurcontent wt% 0.8 0.08 2.1 0.14 3.6 0.1

Aromaticscontent vol% 9.9 6.0 32.4 26.4 55.3 50.3

Density g/cm

3

0.7578 0.7591 0.8830 0.8516 0.9766 0.8811API gravity API 55.2 54.9 28.7 34.7 13.4 29.1

Conradsoncarbonresidue wt% 0.00 0.00 0.03 0.00 1.44 0.00

Table 5. Hydroconversion-based scheme streams properties

Bitumen Diluent DilBitDiluentreturn

Atmosphericbottoms

Mass flow kg/h 494800 126600 620800 126600 494300

Nitrogencontent wppm 5423.0 0.0 4318.0 9.9 5421.0

Sulfurcontent wt% 4.3 0.0 3.4 0.14 4.3

Aromatics content vol% 61.5 0.5 46.2 3.2 60.5

Density g/cm3 0.9960 0.7643 0.9381 0.7653 0.9957

API gravity API 10.6 53.6 19.3 53.4 10.6

Conradson carbon residue wt% 9.5 0.0 7.6 0.0 9.5


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Vacuumdistillation

Hydroconverter

Naphtha

Lightvacuumgas oil

Heavyvacuumgas oil

Vacuumbottoms

Residue(vacuum

bottoms +recycle)

Lightsends naphtha diesel gas oil

Residu(recycle

Mass flow kg/h 1781 80990 187500 224000 348400 16230 17150 76370 86880 124600Nitrogencontent wppm 12. 194.0 1553.0 10590.0 9202.0 0.0 0.0 0.0 0.0 6645.0

Sulfurcontent wt% 0.2 1.5 3.5 6.0 4.2 0.0 0.0 0.0 0.2 0.9

Aromaticscontent vol% 3.8 25.1 54.6 82.1 69.2 0.0 0.0 0.0 10.0 44.0

Density g/cm3 0.7723 0.8805 0.9754 1.0670 1.0780 0.6495 0.7423 0.8783 0.9767 1.1000

API gravity API 51.7 29.2 13.6 1.1 -0.3 86.4 59.1 29.6 13.4 -2.8Conradsoncarbonresidue wt% 0.0 0.0 1.4 19.9 17.7 0.0 0.0 0.0 0.0 14.6


Naphthahydrotreater

Dieselhydrotreater

Gas oilhydrotreater

Mixednaphtha

Hydrotreatednaphtha

Mixeddiesel

Hydrotreateddiesel

Mixedgas Oil

Hydrotreatedgas oil

Mass flow kg/h 18930 16690 157400 159900 274400 277500

Nitrogencontent wppm 1.2 0.4 99.9 21.2 1061.0 126.9

Sulfurcontent wt% 0.02 0.00 0.8 0.16 2.5 0.07

Aromaticscontent vol% 0.4 0.2 12.9 6.4 40.5 29.9

Density g/cm3 0.7450 0.7465 0.8794 0.8516 0.9758 0.8664

API gravity API 58.4 58.0 29.4 34.7 13.5 31.8

Conradsoncarbonresidue wt% 0.00 0.00 0.00 0.00 0.96 0.00

Table 8. Synthetic crude oil properties

SCOCoking-based

scheme

SCOHydroconversion-based

scheme

Mass flow kg/h 400500 454100

Nitrogen content wppm 320.3 85.0

Sulfur content wt% 0.12 0.10

Aromatics content vol% 39.5 20.5

Density g/cm3 0.8607 0.8561

API gravity API 32.9 33.8

Conradson carbon residue wt% 0.0 0.0

Yield vol% 93.7 106.8

Yield wt% 81.0 91.9


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Table 9. Diluent recovery and Vacuum distillation column operating conditions

Diluent Recovery Unit Vacuum Distillation Column

Number of stages 24 Number of stages 24

Feed stage 24 Feed stage 8

Diluent return

stage

Overhead liquid

outlet

Naphtha withdraw

stage

Overhead liquid

outletAtmospheric bottomsstage

Bottom liquidoutlet

Light vacuum gas oilWithdraw stage 2

Pressure (top) 120 kPaHeavy vacuum gas oil

Withdraw stage 7

Pressure (bottom) 140 kPaVacuum bottomsWithdraw stage

Bottom liquidoutlet

Diluent D8690% Temperature 206.1C Pressure top 2 kPa

Pressure bottom 5 kPa

Naphtha D86 90% temperature 221C


D86 90% temperature 345CLight vacuum gas oil

D86 90% temperature 524C

Naphtha yield 1.4wt%

Light vacuum gas oil yield 15.3wt%

Heavy vacuum gas oil yield 38.0wt%

Vacuum bottoms yield 45.3wt%

Table 10. Coker (coking-based scheme) and Hydrocracker (hydroconversion-based scheme)operating conditions

Operating conditions Coker HydroconverterReactor catalystdensity kg/m

3 N/A 1500

LHSV h-1

N/A 0.48

Reactor pressure MPa Atmospheric 16


Sulphur conversion wt% N/A 71.5

Conradson carbon residue conversion wt% N/A 48.5

Nitrogen conversion wt% N/A 51.6

Aromatics conversion wt% N/A 39.1

H2consumption SCF/bbl N/A 1512

Total liquid product yield wt% 70.6 92.2

NH3yield wt% 0.45 4.8

H2S yield wt% 2.0 3.0

Light ends initial boiling point C -60.0 -60.0


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Table 10 - continuednaphtha initial boiling point C 37.0 37.0

diesel initial boiling point C 242.7 204.0

gas oil initial boiling point C 402.2 371.0

Residue initial boiling point C N/A 565.0

Light ends yield wt% 8.6 5.1

Naphtha yield wt% 15.0 5.3

Diesel yield wt% 12.0 23.8

Gas oil yield wt% 35.0 27.0

Coke/Residue yield wt% 27.0 38.8

Residue conversion wt% 100.0 61.2

Table 11. Operating conditions for hydrotreaters in coking-based scheme

Naphtha

hydrotreater

Diesel

hydrotreater

Gas oil

hydrotreater

Number of reactors 2 2 2

Number of beds/ reactor 2 2 2

Reactor catalyst density kg/m3 1500 1500 1500

Reactor ID m 2.5 m 2.5 2.5 m

Catalyst loading kg/bed 18,000 18,000 18,000

Bed voidage 0.37 0.37 0.37

Reactor pressure kPa 5,000 8,000 13,260

Reactortemperature C 285.0 351.2 365.6

Gas/oil ratioSTD

m3/m

3 300.0 300.0 584.2

Sulphur conversion wt% 90.0 93.3 96.8

Conradson carbon residue conversion wt% 0.0 100.0 100.0

Nitrogen conversion wt% 71.1 3.1 84.1

Aromatics conversion wt% 39.7 18.6 9.1

H2consumption SCF/bbl 170.0 581.3 912.6

Product yield wt% 99.9 99.6 99.4


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Table 12. Operating conditions for hydrotreaters in hydroconversion-based scheme

Naphthahydrotreater

Dieselhydrotreater

Gas oilhydrotreater

Number of reactors 2 2 2

Number of beds/ reactor 2 2 2

Reactor catalystdensity kg/m3 1500 1500 1500

Reactor ID m 2.5 2.5 2.5

Catalyst loading kg/bed 18,000 18,000 18,000

Bed voidage 0.37 0.37 0.37

Reactor pressure kPa 5,000 8,000 13,260

Reactortemperature C 285.0 351.2 365.6

Gas/oil ratio STD m3/m

3300.0 300.0 584.2

Sulphur conversion wt% 88.8 78.5 97.0

Conradson carbon residue conversion wt% 0.0 100.0 100.0Nitrogen conversion wt% 67.6 78.8 88.0

Aromatics conversion wt% 33.2 50.4 26.1

H2consumption SCF/bbl 170.0 892.4 1628.0

Product yield wt% 99.8 99.5 99.6

Summary

In this work, two major commercially used bitumen upgrading schemes are simulatedwith HYSYS. The properties and flow rates of the intermediate and final products in each

scheme are estimated and compared. Models for the atmospheric distillation column, thevacuum distillation column, the coker, the hydroconverter, and the hydrotreaters are calibratedaccording to the pilot plant and industrial data. It is shown that the hydroconversion-basedupgrading scheme has a SCO yield of about 92wt% which the coking-based upgradingscheme has a SCO yield of about 81%, which are quite close to commercial operation values.In addition, the SCO generated from the hydroconversion-based scheme has higher quality(lower sulphur, nitrogen and aromatics contents) than that generated from coking-basedscheme. The simulation is versatile and multiple options can be considered for differentscenarios, and therefore can be considered as an important tool to guide bitumen upgradingprocess design and operation.

Acknowledgments

Partial funding for this study was provided by the Canadian Interdepartmental Programof Energy Research and Development (PERD 1.1.3).


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