Naphtha Hydrotreating

Reliance Hydroprocessing Course 2009

2

ContentsContents

• Introduction• Feedstocks properties• Naphtha hydrotreating kinetics• Naphtha hydrotreating hardware• Pitfalls in naphtha hydrotreating• FCC naphtha processing• Coker naphtha processing

3

IntroductionIntroduction

• Naphtha hydrotreating is found in every refinery• Naphtha feed to reformer must be very low in sulfur• Naphtha can be treated to upgrade properties for

gasoline blending:– Light coker naphtha– FCC naphtha– Steam cracked naphtha

• Some difficult naphtha feeds can be converted into reformate:– Heavy coker naphtha– Intermediate FCCU naphtha

4

Naphtha processing in the refineryNaphtha processing in the refinery

CDUCRUDE

VDU

Coker

FCCPT FCC

HCPT HC

Jet/Diesel HT

LCOHT FCCNHT

CokerNHT

NHT

NHT

Reformer

Isom

DIESEL

GASOLINE

5

Naphtha processing in the refineryNaphtha processing in the refinery

NaphthaC4 - C11

C4 - C6

I-C4 – N-C4=

C7 – C11

Isom

Alky

Reformer

6

IsomerizationIsomerization

• Converts straight chain parraffins to branched isomers– Increases Octane

• Catalyst is based on Platinum Chloride• Sulfur and Nitrogen are catalyst poisons• Water will leach Clorine from the catalyst

– Catalyst will deactivate if water is present in the feed– Extensive feed drying– Constant Clorine addition

• Sensitive to NH4Cl corrosion

7

AlkylationAlkylation

• Reacts Isobutene with N-Butane to form Isooctane– Very high octane– No contaminants

• Either HF or H2SO4 based– extremely toxic and corrosive

• Solid acid (zeolite) based alternatives are available– Alkyclean®

– Not applied yet on a commercial scale• “Everybody wants to be the second”

8

ReformingReforming

• Reforming converts paraffins and naphthenes into aromatics– Increasing octane– Hydrogen as a byproduct

• Reforming reactor cycle and catalyst type determines value of feed sulfur removal– Cyclic units regenerate individual reactors often– Semi-regen units regenerate at end of cycle– CCR units regenerate continuously

• Nitrogen in feed reacts with Cl in reforming catalyst, creating NH4Cl salt in product recovery

9

Reforming Feed SpecificationsReforming Feed Specifications

• Sulfur . . . . . . . < 0.5 ppm• Nitrogen . . . . . . . < 0.5 ppm• Arsenic . . . . . . . < 1.0 ppb• Lead . . . . . . . < 1.0 ppb• Water . . . . . . . < 10 ppm• Silicon . . . . . . . < 20 ppb

10

Virgin Naphtha PropertiesVirgin Naphtha Properties

C ru d e S u lfu r D e n s ity P + O /N /AB re n t 3 0 0 .7 6 9 4 2 /3 4 /2 4

A ra b L ig h t 3 5 0 0 .7 4 2 6 5 /2 0 /1 5A b u D h a b i 6 0 0 0 .7 4 7 6 5 /2 0 /1 5

B e rr i 5 0 0 0 .7 4 6 6 5 /2 0 /1 5B o n n y L ig h t 5 0 0 0 .7 4 6 6 5 /2 0 /1 5

M a y a 4 0 0 6 0 /2 7 /1 3W T I 2 0 0 0 .7 5 7 4 8 /4 5 /1 2

N o rth S lo p e 1 3 0 4 0 /4 5 /1 5L lo y d M in is te r 8 0 0 0 5 5 /3 2 /1 3

11

Cracked Naphtha PropertiesCracked Naphtha Properties

Origin Br. No.(g/100ml)

Diene(g/100ml)

Sulfur(ppmw)

Nitrogen(ppmw)

Visbreaker

High Sulfur 90 2 15,000 500

Low Sulfur 80 2 1,000 200

Delayed Coker

High Sulfur 90 > 5 10,000 1,000

Low Sulfur 80 5 2,000 450

FCCU 50 <0.5 1,200 100

Resid Hydrocracked 2 0 20-100 50-200

12

Feedstock SummaryFeedstock Summary

• Often applied before processes that increase the octane of the gasoline– Downstream processes based on Noble metals– These require very low S and N levels– Often < 0.2 ppmwt S and N

• Virgin naphtha quality is very crude dependent• Cracked naphthas have significantly lower quality

• High sulfur and often high nitrogen• (Very) hydrogen deficient • High Bromine and Diene numbers

13

First Order Kinetics ApplyFirst Order Kinetics Apply

• Assuming Constant Pressure, Temperature: • Rate of Reaction ∝ (Concentration of Reactants)n

• For naphtha applications first-order kinetics apply:

• Where k = rate “constant”, LHSV = space velocity, C = Concentration of reactant of interest (e.g., S, N)

⎟⎟⎠

⎞⎜⎜⎝

⎛⋅=

P

F

CClnLHSVk

14

First Order KineticsFirst Order Kinetics

0

1

2

3

4

5

6

7

0.0 0.1 0.2 0.3 0.41/LHSV

ln(C

o/C

p)

HDN

HDSHDO

50% FCCU Naphtha1,950 ppm Sulfur40.5 ppm Nitrogen45 Bromine No.

15

Hydrogen Consumption in a NHTHydrogen Consumption in a NHT

• For each 1 wt% sulfur removed from a feed:– mercaptan 5 Nm3/m3

– sulfide 10 Nm3/m3

– disulfide 8 Nm3/m3

– thiophene 20 Nm3/m3

• For each 1 wt% nitrogen removed from a feed:– pyridine 60 Nm3/m3

– pyrrole 45 Nm3/m3

• For each vol% olefin 1.3 Nm3/m3

• For each vol% diolefin 2.5 Nm3/m3

• For each vol% aromatic 4.2 Nm3/m3

16

Mercaptan RecombinationMercaptan Recombination

• Olefins and H2S can form mercaptans which increase the total HDS activity requirement

• Olefins can either be present in the feed or created by cracking reactions near the reactor outlet– This becomes significant above 340 °C– 1 to 10 ppm additional S in product from this type of recombination

+H2

-H2

R=CH2 R-CH3

RSH+H 2S

-H 2S

-H2 S+H

2

17

Kinetics SummaryKinetics Summary

• Naphtha treating is a vapor phase reaction• HDS and HDN are first order reactions in naphtha,

but HDN is much slower than HDS• Hydrogen partial pressure is important

– Function of recycle gas circulation rate.• Maximum temperature often set by onset of

recombinant sulfur reactions– Becomes significant at T > 340 °C

18

Catalyst SelectionCatalyst Selection

• Relative level of sulfur and nitrogen determine the preferred catalyst system

• Olefins & diolefins determine need for catalyst size and activity grading

• Naphtha contaminants (i.e. Si and As) require special metal trapping catalysts

19

Catalyst SelectionCatalyst Selection

1

10

100

1000

1 10 100 1,000 10,000

Feed Sulfur (ppm)

Feed

Nitr

ogen

(ppm

)

NiMo Catalyst is Optimal

Split Bed of Catalyst is Optimal

CoMo Catalyst is Optimal

20

Hardware ConsiderationsHardware Considerations

• Reactor design– downflow– multi-reactor, series or parallel

• Vaporization– vapor phase reaction– never in radiant section of furnace

• Reactor effluent heat exchanger– even tiny leaks have profound influence on product sulfur

• Pressure drop build-up

21

Typical Operating ConditionsTypical Operating Conditions

Virgin Naphtha Cracked Naphtha

Unit pressure, barg 20 - 30 45 - 65

LHSV, h-1 3 - 10 1 - 5

Temperature, °C 250 - 340 240 - 340

H2:Oil, Nm3/m3 50 - 100 250 – 500

ppH2, barg 7 - 10 15 - 45

22

Pitfalls in Naphtha HydroprocessingPitfalls in Naphtha Hydroprocessing

• Pressure drop buildup– Occurs most frequently with cracked feed stocks– Can be prevented and controlled by catalyst grading

technology and unit design

• Metals removal– Si and As are the major problems– Requires special metal trapping catalysts to remain activity

maintenance and to increase holding capacity and

23

Pitfalls in Naphtha HydroprocessingPitfalls in Naphtha Hydroprocessing

• Unit monitoring– Traditional normalization only done on difficult units– Requires extremely good analytical data

• Heat exchanger leaks

• Salts and corrosion– ammonium chloride– ammonium bisulfide

24

FCC Naphtha HydroprocessingFCC Naphtha Hydroprocessing

• Goal of FCC naphtha processing is reduced gasoline sulfur– In specific cases olefin saturation may be desirable– Generally, the extra hydrogen consumption and obtained

octane loss due to olefin saturation is not desired.

• Due to a potentially high exotherm in these units, conventional HDS units and catalysts are not suitable for selective hydrogenation.

25

FCC Naphtha Cut PropertiesFCC Naphtha Cut Properties

Property IBP-75 75-126 126-149 149+ Full RangeCut yield 22% 30% 16% 32% 100%S, ppm 75 100 200 600 250N, ppm 5 6 20 75 35Br. No. 100 75 45 25 70Saturates 33 38 30 20 30Olefins 65 50 30 20 45Aromatics 2 12 40 60 25RON 95 87 93 93 92MON 81 77 81 81.5 80

Sulfur is predominately in the heavy cutsOlefins are predominately in the light cuts

26

Pre-treatment vs. Post-treatmentPre-treatment vs. Post-treatment

• Pre-treatment favored by:– Improved FCCU yields/conversion– Process more sour and heavier crudes– Process high N feeds (cokers, West coast)

• Post-treatment favored by:– Lower investment cost– Very low S products

Pre-treatment alone will not always be sufficient to reach the specification

27

Pre-treatment vs. Post-treatmentPre-treatment vs. Post-treatment

• Very deep VGO Pretreatment is required to make ULSG

28

Reactor System forProcessing Cracked NaphthaReactor System forProcessing Cracked Naphtha

Furnace

FeedPump

MainReactor Trim

Reactor

HP Separator

LP Separator

Fuel Gas

PurgeMake-up

Compressor

GuardReactor

Olefin saturation HDS Polishing

29

Gasoline HDSGasoline HDS

• Split FCC naphtha into light and heavy fractions• Fully hydrotreat heavy fraction• Adjust split to meet sulfur target and minimize octane loss• Caustic treatment of light fraction• Additional mid range cut with hydrotreating and reforming can

reduce octane loss

3+ RON loss expectedRefinery needs to be octane long and relatively sweet

FCC naphtha needed (i.e. pretreated FCC feed)

30

Post-treatment Octane LossPost-treatment Octane Loss

• Hydrotreating full range naphtha is impractical in terms of octane loss and H2 consumption

• Hydrotreating heavy fraction may be feasible in octane long refineries

FCC Gasoline Pool Octane Loss RON MON

Hydrotreat Full Range FCC Naphtha 7-10 3-4

Hydrotreat Heavy Fraction 3-4 1-2

31

FCC Naphtha HDS TechnologiesFCC Naphtha HDS Technologies

• Selective hydrotreating– SCANfining (ExxonMobil)– Prime G+ (Axens)

• Hydrotreating + Isomerization– OCTGAIN (ExxonMobil)– ISAL (UOP/PDVSA)

• Catalytic distillation– CDHDS+ (CDTech)

• Selective adsorption– S-Zorb (Phillips)

32

SCANfining®Selective Naphtha HDS TechnologySCANfining®Selective Naphtha HDS Technology

• Low S feed– SCANfining I, little or no new

investment– Small decrease in octane

• High S feed– Upgrading to SCANfining II

can control octane loss– 30 - 40% incremental

investment– Full use of existing equipment

0

1

2

3

4

5

6

0 30 60 90

Product Sulfur (wppm)

Oct

ane

Loss

(R+M

/2)

High S FeedSCANfining I

High S FeedSCANfining II

Low S FeedSCANfining I

33

Coker Naphtha HydroprocessingCoker Naphtha Hydroprocessing

• High Diene Number– High likelyhood of reactor pressure drop issues

• High Bromine Number– Excessive reactor temperature rise

• High Contaminant Levels– High HDS, HDBr and very high HDN requirements– High silicon removal activity needed– High silica capacity needed– High Arsenic tolerance required

34

Reactor System Designfor Coker Naphtha TreatingReactor System Designfor Coker Naphtha Treating

• A three reactor system solves many difficulties in coker naphtha treatment– Guard reactor: saturates diolefins and helps prevent

increasing pressure drop– Main reactor: removes silicon, sulfur, nitrogen and olefins– Trim reactor: combats recombinant sulfur

• Two reactor versions of this system have been developed to provide similar results

• Careful catalyst selection and system design required to maximize catalyst life in any system

35

Catalyst SelectionCatalyst Selection

• A graded bed of active support material to saturate the diolefins and prevent reactor pressure drop problems

• An active catalyst with high capacity for silica to remove the silicon, sulfur, nitrogen, and olefins

• Dilution of the coker naphtha with virgin and other naphtha to reduce the reactor temperature rise to a manageable level

36

Bed GradingBed Grading

• Recommended bed grading for coker naphtha units– 300 to 1200 mm of large rings (i.e. KG 55, KF 542-9R)– 450 to 1200 mm of medium ring support (i.e. KF 542-5R)– 150 mm. or more of 3 mm catalyst (i.e. KF 647-3Q)– the remaining bed of 1.3 mm catalyst

• A large active support layer can be substituted for a guard reactor

• Experience is used to size the bed grading layers

37

HDN is ImportantHDN is Important

• Nitrogen affects catalytic reformers– Affects the acidity of the noble metal CCR catalyst– Forms salts that deposit on compressors and exchangers

• Virgin naphtha has very little nitrogen– CoMo catalysts are used for maximum HDS when naphtha

nitrogen is < 3 ppm• Coker naphtha contains high levels of nitrogen

– Normally HDN controls catalyst life– In high sulfur naphtha a split bed of NiMo and CoMo can

be optimal

38

Silicon Can Control Cycle LengthSilicon Can Control Cycle Length

• Primary source of silicon in naphtha is anti-foam additives used in the delayed coker– Silicon content is not constant– Increases at end of coking cycle– Increases as throughput is increased

• Chemicals used during crude oil production or transportation may contain Silicon based drag reducers

• Silicon deactivates the catalyst as it deposits, and breakthrough occurs before all catalyst is saturated with silicon

• Silica is a more potent catalyst poison after catalyst regeneration – coker naphtha spent catalyst is seldom reused

39

Silica Capacity Depends onCatalyst Size, Grade & LHSVSilica Capacity Depends onCatalyst Size, Grade & LHSV

0 1 2 3 4 5 6 7 8 9 100

5

10

15

20

25

LHSV

Silic

a C

onte

nt a

t Bre

akth

roug

h (%

)

KF-844-3Q

KF-841-1.3QKF-841-3Q

KF-844-1.3Q

40

1 2 3 4 5 6 7 8 9 100

1

2

3

4

5

6

7

8

Section of Reactor

Silic

on U

ptak

e (w

t% o

n fr

esh

cata

lyst

)

Silicon Uptake Exhibits Adsorption Isotherm Like BehaviorSilicon Uptake Exhibits Adsorption Isotherm Like Behavior

41

SummarySummary

• Reformer performance dictates naphtha treating requirements

• Virgin naphtha treating is usually a relatively simple process

• Cracked naphtha treating is much more complicated– High exotherm– Contaminant removal– HDN is important– Hydrogen consumption

• Catalyst selection is very important

42

Reliance CNHTReliance CNHT

Recycle GasFeed

Product Recycle

Hydrotreated Naphtha

R3R1 R2DIOS

MAIN TRIM • CNHT is a classic three reactor design– High pressure (63 barg)– DIOS for ΔP control– Large product recycle for ΔT

control– Quenching with gas– Trim reactor for Recombinant

Mercaptans

• Reformer Quality Product– S & N < 0.5 ppmwt

43

Reliance LNUUReliance LNUU

• LNUU is an atypical design– Designed for Olefin reduction– Lower pressure (30 barg)– DIOS for ΔP control– Quench with DIOS product

for ΔT control

• Petrochemical Naphtha Product– S < 10 ppm, Br < 1– Low levels of Recombinant

Mercaptans can be allowed so no trim reactor

Recycle Gas

Feed

Product Recycle

Hydrotreated Naphtha

R2R1R3DIOS

MAIN 1 MAIN 2

44

Reliance LNUU vs CNHTReliance LNUU vs CNHT

• Advantages of the LNUU design– By using feed quench the product recycle can be reduced– This allows a lower design pressure for the same ppH2

– No gas quench so lower recycle gas rate

• Disadvantages of the LNUU design– DIOS product needs to be full vapor to allow feed split control– Dry point in DIOS can give rise to pressure drop– More complex optimization (feed split, max ΔT, Si/As management)

• The LNUU is not designed to make reformer feed

45

DIOS OperationDIOS Operation

• Diolefins are very reactive– DIOS operating temperatures 170°C < T < 220°C

• RIT set by the ΔT– Approximately 15°C temperature rise is sufficient to get 70% diolefin saturation– Increase RIT only when the observed ΔT drops below 10°C

• If the DIOS RIT is too high, olefin saturation can start– Temperature runaway– Recommended maximum ROT 220°C

• Contaminant pickup is incomplete– Temperatures are too low for the catalysts to reach Si saturation– Typically only 50% of the catalyst Si capacity is used– Temperatures are too low for As removal

46

Main RX OperationMain RX Operation

• Minimum RIT > 240°C– Below this temperature olefin saturation becomes (too) composition dependent– With feed quality fluctuations olefin saturation may or may not start/complete– Large unpredictable swings in ROT

• For LNUU style units– Minimize product recycle to keep acceptable ΔT in the first RX; typically 70°C– Low product recycle increases ppH2 and lowers overall LHSV– Lowest possible product recycle is a function of the feed bromine number– RX1 product will act as heat sink in RX2

• Deactivation by coke formation is very low at typical operating conditions– Cycle length determined by contaminants (Si, As) and ΔP

47

Trim RX OperationTrim RX Operation

• Recombinant Mercaptans react very easily– Low operating temperature; typically 280°C-300°C– High LHSV; typically 10 h-1

– Very low deactivation rates

48

Coker Naphtha Unit OperationsCoker Naphtha Unit Operations

• Avoid reactor temperatures between 220°C (DIOS) and 240°C (Main RX)– Olefin saturation becomes very feed quality dependent in this

temperature window– Can give instabilities in operation

• CNHT type 3 reactor unit– Should always work

• LNUU style unit– Significant cost saving in lower design pressure– More complex operation