catalagram - w. r. grace and company · provides details on cracking these feedstocks and the...

Grace FCC CatalystTHE ADVANTAGEACHIEVE™

In this issue:

p

CatalagramA Catalysts Technologies Publication

No. 114 / Spring 2014/ www.grace.com

®

pp

p

Processing Tight Oils in FCC: Issues, Opportunities and Flexible Catalytic Solutions

Tight Oil Distillate in ULSD Production, What To Expect? Two Companies Joined to Develop a Catalytic Solution for Bottoms Upgrading to Diesel in the FCC Unit Meeting Tier 3 Gasoline Sulfur Regulations

Innovative Catalytic Solutions

Grace FCC Catalysts and Additives

■ Industry’s Broadest Catalyst Portfolio■ Flexible Functionality for Processing

Unconventional Feeds■ Global Manufacturing Footprint■ World-class R&D■ Industry-leading Technical Service

Catalagram®

ISSUE 114, Spring 2014

Editor:Rosann Schiller

Contributors:Luis Almanza

Colin Baillie

Kenneth Bryden

Tania Chanaga

Michael Federspiel

E. Tom Habib, Jr

John Haley

Luis Javier Hoyos

Larry Hunt

Jeff Koebel

Hongbo Ma

Clemencia Marín

William Morales

Uriel Navarro

Charles Olsen

Hipólito Rodríguez

Greg Rosinski

Rosann Schiller

Brian Watkins

Rick Wormsbecher

Please address your comments to:[email protected]

Grace Catalysts Technologies7500 Grace DriveColumbia, MD 21044 410.531.4000

© 2014 W. R. Grace & Co.-Conn.3.21.14

3 Processing Tight Oils in FCC: Issues, Opportunities andFlexible Catalytic Solutions

By Kenneth Bryden, Michael Federspiel, E. Thomas Habib, Jr.and Rosann Schiller, Grace Catalysts Technologies

Tight oils (shale oils) are becoming a major feed source for North American

refineries. Problems in treating these feedstocks are contaminant metals,

heat balance effects, and the overall refinery configuration. This paper

provides details on cracking these feedstocks and the application of new

catalyst technologies and unit operating strategies to maximize product

value.

23 Tight Oil Distillate in ULSD Production, What To Expect?

By Greg Rosinski, Brian Watkins and Charles Olsen, Advanced Refining Technologies

This article addresses the challenges in meeting the high distillate demands

while maintaining key product quality specifications. We explore the impact

of refinery processes such as hydrotreating, hydrocracking and

hydrodewaxing on product yields and cycle life. We also evaluate the impact

of varying feedstocks on the middle distillate yields and quality.

30 Two Companies Joined to Develop a Catalytic Solution forBottoms Upgrading to Diesel in the FCC Unit

By William Morales, Hipólito Rodríguez, Luis Javier Hoyos,Tania Chanaga, Luis Almanza, Ecopetrol - Instituto Colom-biano de Petróleo Uriel Navarro, Larry Hunt, Clemencia Marín, Hongbo Ma, RickWormsbecher, Tom Habib, Grace Cayalysts Technologies

Ecopetrol (Colombia) and W.R. Grace joined to develop a new catalyst

technology geared towards increasing bottoms cracking to produce more

diesel in efforts to meet local and worldwide demands. The project included

intensive Pilot Plant work (DCR), with the implementation of existing and

new deactivation techniques for catalyst, and a commercial trial of the new

catalyst technology in an Ecopetrol FCC.

36 Meeting Tier 3 Gasoline Sulfur Regulations

New Tier 3 gasoline regulations require <10 ppm sulfur in the gasoline

compared to 30 ppm in Tier 2. The options for accomplishing this usually

involve some form of hydrotreating before or after the FCC. There are

several catalyst options and operating strategies that will produce a

reduction in gasoline sulfur, while minimizing the detrimental effects normally

associated with some of these solutions.

2 Issue No. 114 / 2014

EditorialDear Refiners,

When a freshly minted journalism major arrived at

Grace 40 years ago, she knew nothing about oil

refining. She was handed a stack of Catalagrams®

(already in its 15th year) and the only thing she

understood was a line in one of the past editorials

that quoted from an old Art Linkletter show, “Kids

say the Darndest Things”:

Linkletter: Do you know what a cat cracker is?

Boy: (shrugging) I dunno…maybe a cat who eats

crackers?

This journalism major has become pretty familiar

with what a cat cracker is since then. Many things

have changed in refining since 1974, but two

things will always be true:

-The refiner’s need to get the optimal value out of a barrel of oil

-Grace and ART’s commitment to achieving that goal

Over those 40 years, I’ve seen refining become more exact and challenging. And, always we’ve

responded, whether it’s broadening our product portfolios, strengthening our industry-leading tech

service, investing in our plants, committing to R&D, or expanding globally to meet market demand.

I’m proud and privileged to have worked with my ART and Grace colleagues and the fine people in

the petroleum refining industry and I am confident in our joint future.

Sincerely,

Elizabeth W. MetteeDirector of CommunicationsGrace Catalysts TechnologiesAdvanced Refining Technologies

Jeff Hazle, AFPM Technical Director, presents the author withthe Peter G. Andrews Lifetime Achievement Award at the 2008Question and Answer Session.

Grace Catalysts Technologies Catalagram® 3

Kenneth BrydenManager, FCC Evaluations Research

Michael FederspielNational Sales Leader,Americas

E. Thomas Habib, Jr.Director, Customer Research Partnershipsand DCR LicensingManager

Rosann SchillerMarketing Director,FCC Commercial Strategy

Grace Catalysts TechnologiesColumbia, MD, USA

AbstractTight oils (also called shale oils) such as Eagle Ford and Bakken are fast becoming a major feed source

for North American refineries. While these feedstocks are generally light and sweet, issues that refiners

can face when processing tight oil include: contaminant metals, heat balance effects, and configurational

imbalances in the refinery. This paper provides detailed characterization of tight oils along with data on

the cracking of these feedstocks under different operating conditions. Catalytic solutions for (1) metals

tolerance, (2) achieving maximum conversion and selectivity on light feeds, and (3) optimum butylene

selectivity, are discussed, along with case studies on how refiners can apply new catalyst technologies to

maximize the value present in tight oil feedstocks.

IntroductionAs novel technology for hydraulic fracturing with directional drilling continues to develop, tight oil (also

called shale oil) will continue to be a game changer for North American refiners. Although credited with

many advantages, tight oil does not come without its challenges. Suppliers and processors alike are

urgently working to adapt to the changing oil landscape. Just a few years ago, investments were focused

on processing heavy crudes. Now, however, the industry is faced with lighter, sweeter crude streams

from tight oil plays.

In varying degrees at each refinery, tight oil makes up only a percentage of the total feedstock. In

December 2013, production from the Bakken region passed 1.0 MM bbl/day and production from the

Eagle Ford region reached an estimated 1.23 MM bbl/day1. The December 2013 production of these two

tight oil regions is slightly more than 10% of the total US crude oil demand. The percentage of tight oil

could grow substantially as tight oil production increases and refiners invest in process modifications to

handle this lighter feed. While drilling technology advances and the rapid growth of tight oil production

have made forecasts difficult, the U.S. Energy Information Agency currently forecasts that United States

tight oil production will top 4.8 MM bbl/day in 20212. Tight oil resources are not confined to the United

States. Recent analysis indicates that tight oil formations are located throughout the world and constitute

a substantial share of overall global technically recoverable oil resources3. The January 2014 BP Energy

Processing Tight Oils in FCC: Issues, Opportunities and FlexibleCatalytic Solutions

4 Issue No. 114 / 2014

Outlook projects that by 2035 tight oils will constitute 7% of the

total global oil supply, with more than one third of tight oil

production coming from outside the United States4. While the

North American refining industry undergoes a renaissance due to

abundant tight oil, the new feeds present challenges as well as

opportunities. This paper discusses the challenges with tight oil

feeds and how to overcome them with proper choice of catalyst

technology.

Tight Oil PropertiesTight oil is highly variable. Density and other properties can show

wide variation, even within the same field5-8. Tight oils are

generally light, paraffinic and sweet. Table I presents the

properties of a sample of whole Bakken crude, compared to

publically published assays of Bakken, West Texas Intermediate

(WTI) and Light Louisiana Sweet (LLS) and a “typical” Eagle Ford

crude based on the Eagle Ford Marker. Eagle Ford crude is highly

variable and the Eagle Ford Marker is based on a pool of Eagle

Ford assays10. The Bakken crude is light and sweet with an API of

42° and a sulfur content of 0.19 wt.%. Similarly, Eagle Ford is a

light sweet feed, with a sulfur content of ~0.1 wt.% and with

published APIs between 40° API and 62° API, with a value of 47°

used for the Eagle Ford Marker. Similar to other light crudes, raw

Bakken crude and Eagle Ford crude have a low amount of FCC

feed (<28% 680°F+ for Bakken, and <27% 680°F+ for Eagle Ford

Marker). The straight run Bakken sample was distilled into a 430°F

minus gasoline cut and a 430°F to 650°F LCO cut and the

properties of these cuts were measured to better characterize the

Bakken feed. The gasoline composition and properties were

analyzed via a Grace’s proprietary G-Con® octane calculation

software based on detailed GC analysis12,13. The gasoline fraction

from the straight Bakken was highly paraffinic and had low octane

numbers (a RON of 61 and MON of 58). The LCO fraction had an

aniline point of 156°F and an API gravity of 37.6, resulting in a

diesel index of 59.

Table II presents properties of a 430°F+ distillation of Bakken, a

650°F+ distillation of Bakken, along with two Eagle Ford based

FIGURE 1: Scanning Electron Micrograph of Sediment Filtered from Whole Bakken Crude (pg. 6)


Bakken sampleused in this work

Published Assay Data

Bakken (9) WTI (9) LLS (9) “Typical” EagleFord (10, 11)

API Gravity Degrees 41.9 >41 40 35.8 47.0

Sulfur Wt.% 0.19 <0.2 0.33 0.36 0.11

Distillation Yield Wt.% Vol.% Vol.% Vol.% Vol.%

Light Ends C1-C4 1 3 1 2 1

Naphtha C5-330˚F 32 30 32 17 34

Kerosene 330-450˚F 14 15 15 14 15

Diesel 450-680˚F 25 25 24 34 23

Vacuum Gas Oil 680-1000˚F 23 22 23 25 20

Vacuum Residue 1000+˚F 5 5 7 8 7

Total 100 100 100 100 100Conradson Carbon Residue Wt.% 0.78

Gasoline FractionProperties

RON (G-Con) 60.6

MON (G-Con) 57.6

LCO Fraction(430˚F-650˚F)Properties

Anline Point, ˚F 155.9

API Gravity 37.6

Diesel Index 58.6

TABLE I: Properties of Straight Run Tight Oil Feed Used in this Study Compared to Publically Published Assay Data

PropertyEagle Ford

CondensateSplitter Bottoms

HVGO Derived from 85%

Eagle Ford

430°F+ Distillation of Whole

Bakken Crude


Bakken Crude

Mid-ContinentVGO

API Gravity, ˚F 36.6 30.0 28.6 23.0 24.7

CCR, wt.% 0.15 0.17 0.34 2.27 2.32

K Factor 12.48 12.39 11.73 11.86 12.01

Sulfur, wt.% 0.08 0.83 0.3 0.43 0.35

Basic Nitrogen, wt.% 0.00 0.02 0.02 0.04 0.05

Hydrogen, wt.% 13.7 13.4 13.1 12.7 12.9

Percent Boiling > 1000˚F 10.7 13.1 14.5 23.6 16.5

Molecular Weight 373 455 321 414 430

n-d-m Analysis

Ca, Aromatic Ring Carbons, % 14.8 15.2 16.9 22.1 17.6

Cn, Naphthenic Ring Carbons, % 19.4 9.8 21.7 17.3 20.3

Cp, Paraffinic Carbons, % 65.8 75.0 61.4 60.6 62.1

D2887 Simulated Distillation, °F

Initial Boiling Point 266 597 330 530 527

10% 519 715 470 658 691

20% 599 762 524 711 734

30% 649 797 580 756 773

40% 693 830 638 798 810

50% 735 862 699 844 848

60% 780 895 767 895 886

70% 835 929 840 953 928

80% 907 967 931 1027 976

90% 1006 1015 1057 1135 1045

TABLE II: Properties of Tight Oil Derived FCC Feeds Compared to Typical Mid-Continent Vacuum Gas Oil

6 Issue No. 114 / 2014

fluid catalytic cracking (FCC) feeds. A typical mid-continent VGO is

included for comparison. The tight oil derived feeds are all light

and paraffinic. Table III shows the results of an HRMS 22-

Component Hydrocarbon Types Analysis of the FCC feeds. This

breakdown of hydrocarbon types further highlights that the Bakken

and Eagle Ford crudes are high in saturates. However, the 650°F+

distillation of the Bakken crude does contain a significant portion of

tetra-aromatics that are inactive to cracking and are coke

precursors.

While most tight oils are low in nickel and vanadium, they have

been found to be high in inorganic solids, iron, and alkali metals6,14.

Table IV presents metals analysis of several tight oil derived feed

streams along with published metals analyses of tight oil. While

metals levels in the samples vary (as would be expected for tight

oil), iron and calcium levels are generally high. Reports from the

field indicate that Bakken crude is typically low in nickel and

vanadium, while crudes sourced from the Eagle Ford formation

have higher nickel and vanadium levels that can vary significantly

based on their source.

To better understand the possible sources of metals in tight oil, a

sample of whole Bakken crude was filtered through a 0.8 micron

filter and the solids recovered. Scanning electron microscopy of

the solids identified irregular micron and submicron sized particles

as shown in Figure 1 (pg.4). Energy dispersive spectroscopy

maps of iron, sulfur and calcium are pictured in Figure 2. The iron

in the sediments is associated with the sulfur.

Eagle Ford Condensate

Splitter Bottoms


Bakken Crude

Mid-Continent VGO

Saturates AVE, wt.% AVE, wt.% AVE, wt.%

C(N)H(2N+2) Paraffins 44.4 12.4 12.2

C(N)H(2N) Monocycloparaffins 25.5 27.8 25.5

C(N)H(2N-2) Dicycloparaffins 8.9 12.5 11.0

C(N)H(2N-4) Tricycloparaffins 5.8 6.5 6.1

C(N)H(2N-6) Tetracycloparaffins 2.1 0.0 0.0

C(N)H(2N-8) Pentacycloparaffins 0.7 0.0 0.0

Total Saturates 87.6 59.2 54.7

Monoaromatics

C(N)H(2N-6) Alkylbenzenes 3.1 10.8 10.5

C(N)H(2N-8) Benzocycloparaffins 0.8 6.0 6.3

C(N)H(2N-10) Benzodicycloparaffins 1.2 4.2 3.7

Diaromatics

C(N)H(2N-12) Naphthalenes 1.1 2.6 3.8

C(N)H(2N-14) 1.2 2.0 4.2

C(N)H(2N-16) 2.2 3.9 6.4

Triaromatics

C(N)H(2N-18) 1.5 3.1 4.6

C(N)H(2N-22) 0.2 4.3 2.4

Tetra-aromatics

C(N)H(2N-24) 0.0 1.4 0.1

C(N)H(2N-28) 0.0 0.0 0.0

Total Aromatics 11.3 38.3 41.9

Thiophenic Compounds

C(N)H(2N-4)S Thiophenes 0.0 0.0 0.0

C(N)H(2N-10)S Benzothiophenes 0.7 1.6 2.3

C(N)H(2N-16)S Dibenzothiophenes 0.5 0.8 1.1

C(N)H(2N-22)S Naphthobenzothiophenes 0.0 0.0 0.0

Total Thiophenic Compounds 1.1 2.4 3.4

TABLE III: HRMS 22-Component Hydrocarbon Types Analysis of Two Tight Oil Derived FCC Feeds Compared to aTypical Mid-Continent Vacuum Gas Oil


X-ray diffraction of the sediment identified the following crystalline

phases: anhydrite (Ca2SO4), magnetite (Fe3O4), and pyrrhotite

(substoichiometric FeS). Anhydrite and pyrrhotite have been

mentioned in the literature as being present in the Bakken

formation15,16. Based on this analysis, it appears that much of the

iron in the Bakken crude comes from very small particles of iron

oxide and pyrrhotite.

Cracking Yields of Whole Tight Oiland Tight Oil Cuts To examine the impact of tight oil on FCC yields, cracking was

done with whole Bakken, a 430°F+ distillation of Bakken, a 650°F+

distillation of Bakken, two Eagle Ford derived FCC feeds, and a

reference sample of a typical mid-continent VGO. Feed properties

FIGURE 2: Energy Dispersive Spectroscopy Maps of Sediment in Bakken Crude

Samples in this Paper Published Assay Data14 Published AssayData7

PropertyMid-

ContinentVGO

Whole Bakken Crude

650°F+ Distillation of Bakken

Crude


Splitter Bottoms

Flashed Bakken Crude

75% Eagle Ford

Stream(total)

75% Eagle Ford

Stream (filtered)

Bakken Crude

Eagle Ford

Crude

Barium, ppm <0.01 0.2 0.1 0.8 not reported

not reported

not reported 0.02 0.21

Calcium, ppm <0.1 0.5 1.2 5.4 0.6 15 1.4 0.54 9.8

Iron, ppm <0.1 7.5 7.8 8.6 4.1 16 3 0.7 2.3

Magnesium, ppm <0.04 0.2 0.2 0.3 <0.2 1.6 <0.12 0.05 0.34

Nickel, ppm <0.04 04 1.9 0.2 0.6 8 8 0.05 <0.14

Potassium, ppm <0.04 0.4 0.3 0.0 <0.2 1.2 <0.3 0.1 0.5

Sodium,ppm <0.06 8.7 3.9 3.1 4.1 34 0.4 2.8 12

Vanadium, ppm <0.03 0.1 0.5 0.9 0.22 22 22 0.02 <0.05

TABLE IV: Metals Analysis of Several Tight Oils

8 Issue No. 114 / 2014

are presented in Tables I and II. Cracking was done over an FCC

catalyst in a fixed-fluidized bed ACE test unit17 at a constant

reactor temperature of 980°F, using three catalyst-to-oil ratios

(4,6,8) for each of the feeds. The catalyst used in the experiments

was an FCC catalyst with optimized matrix and mesoporosity,

deactivated metals free using a CPS type protocol. The properties

of the deactivated catalyst are given in Table V.

Interpolated yields at a catalyst-to-oil (C/O) ratio of 6 are

presented in Table VI. The whole Bakken crude resulted in low

coke, and a low octane gasoline. While the whole Bakken crude

yielded significant gasoline, much of the gasoline was from

uncracked starting material in the feed. The yields of the 430°F+

and 650°F+ distillations of the Bakken crude were similar to those

of the mid-continent VGO reference sample. The 650°F+

distillation of the whole Bakken crude had higher coke than the

mid-continent VGO due to its heavier end as seen it its higher

Conradson carbon number and higher tetra-aromatic content.

Compared to the mid-continent VGO, the light Eagle Ford derived

feeds yielded higher gasoline and lower coke, bottoms and LCO.

Processing Straight Run Tight Oil -Effect of Operating Variables onYields and Product PropertiesWhile fluid catalytic cracking is typically done to reduce the

molecular weight of the heavy fractions of crude oil (such as

vacuum gas oil and atmospheric tower bottoms), in some cases

refiners are charging whole tight oil as a fraction of their FCC feed.

Since tight oil is low in components boiling above 650°F and high

in components boiling below 650°F, a refiner processing 100% tight

oil can be at their maximum distillation and light cut capacity and

be short on FCC feed. Also, whole crude oil has been charged to

FCC units when gas oil feed is not available due to maintenance

on other units in the refinery18, and to produce a low-sulfur

synthetic crude19.

As a model case to understand the cracking of whole crude oil in

the FCC and the effect of process conditions on yields, the whole

Bakken crude described in Table I was processed in a DCR™

circulating riser FCC pilot plant at three riser outlet temperatures:

970°F, 935°F, and 900°F. As a reference case, the mid-continent

VGO described in Table II was cracked at a riser outlet

temperature of 970°F. Details of the DCR™ circulating riser pilot

plant can be found in Reference 20. The catalyst used in the

experiments was a high-matrix FCC catalyst, deactivated metals

free using a CPS type protocol. The properties of the deactivated

catalyst are given in Table V.

Figure 3 presents the yield structure of the starting feeds and the

cracked products for a riser outlet temperature of 970°F. The mid-

continent VGO is a typical VGO feed with a large portion of 650°F+

Total Surface Area, m2/g 196

Zeolite Surface Area, m2/g 110

Matrix Surface Area, m2/g 86

Unit Cell Size, Å 24.30

Rare earth, wt.% 2.1

Alumina, wt.% 52.1

TABLE V: Deactivated Catalyst Properties

Whole Bakken Crude

430°F+ Distillationof Bakken

650°F+ Distillation of Bakken

Mid-ContinentVGO

HVGO Derivedfrom 85%

Eagle Ford


Splitter Bottoms

Conversion, wt.% 83.5 71.7 74.3 74.4 83.3 86.3

H2 Yield, wt.% 0.02 0.06 0.08 0.04 0.09 0.05

C1's+C2's, wt.% 0.9 1.2 1.5 1.3 1.3 1.0

Total C3, wt.% 4.5 5.1 5.2 5.1 6.7 8.1

C3= , wt.% 3.5 4.4 4.4 4.4 5.8 7.0

Total C4's, wt.% 10.1 10.8 10.7 10.8 14.3 17.3

C4=, wt.% 4.3 5.7 5.9 6.1 8.2 9.4

LPG, wt.% 14.6 16.0 15.9 15.9 21.0 25.4

Gasoline (C5-430°F), wt.% 65.4 52.1 52.9 54.1 58.6 58.4

RON (G-Con) 78.0 89.2 90.1 90.3 90.8 89.1

MON (G-Con) 70.9 78.9 79.6 79.5 79.9 78.8

LCO (430-700°F), wt.% 14.2 24.6 19.6 19.1 12.2 11.5

Bottoms (700°F+), wt.% 2.3 3.7 6.0 6.4 4.5 2.2

Coke, wt.% 1.8 2.7 4.1 2.9 2.5 1.3

TABLE VI: Interpolated Yields at C/O = 6 for Five Tight Oil Derived Feedstocks Compared to Mid-Continent VGO


material and small fraction of LCO range material. When cracked,

the LCO range material cracks to LPG and gasoline, and the

650°F+ material cracks to the typical distribution of LPG, gasoline

and LCO, resulting in a net increase in LCO. The whole Bakken

crude starts with large fractions of gasoline and LCO range

material and a low amount of 650°F+ material. The amount of

gasoline produced after cracking is high since the LCO range

material cracks to predominantly gasoline and much of the starting

gasoline is unconverted. LCO yields are low since there is little

starting 650°F+ material to crack to LCO.

For the three different reactor outlet temperatures, plots of

catalyst-to-oil ratio, gasoline, LCO, and coke yields versus

conversion are shown in Figure 4. As expected, lowering reactor

temperature increases the amount of LCO produced. Cracking

straight run tight oil produces little coke and bottoms. At the same

conversion level, lowering reactor temperature results in slightly

more gasoline yield (due to increased C/O), which is consistent

with prior work21. At a riser outlet temperature of 970°F, the whole

Bakken feed produces more gasoline, less LCO and less coke

than the reference mid-continent VGO. Figure 5 presents plots of

gasoline olefins, iso-paraffins and RON and MON estimated via

G-Con®. Cracking straight run Bakken tight oil produces a

paraffinic low-quality gasoline with research octane less than 80

and motor octane less than 70. At constant conversion, increasing

reactor temperature results in more gasoline olefins and higher

research octane number.

Straight RunBakken

Bakken Crackedat 970˚F ROT

Mid-ContinentVGO Cracked

at 970˚F

Mid-ContinentVGO

Dry Gas LPG Gasoline (C5-430˚F) LCO (430-650˚F)

Bottoms (650˚F+) Coke

Wt.%

Fre

sh F

eed

100

90

80

70

60

50

40

30

20

10

0

FIGURE 3: DCR Yield Structure of Starting Feeds andCracked Products for Straight Run Bakken and Mid-Continent VGO (970°F Riser Outlet Temperature)

FIGURE 4: Product Yields as a Function of Riser Outlet Temperature and Feed

Conversion, wt.%

10

8

6

4

10.0

12.5

15.0

17.5

20.0

50

55

60

65

70

1

2

3

4

75.0 77.5 80.0 82.5 85.0 75.0 77.5 80.0 82.5 85.0

C/O Ratio

LCO (430-650˚F), wt.% Coke, wt.%

C5+ Gasoline, wt.%

Bakken 900˚F

Bakken 935˚F

Bakken 970˚F

VGO 970˚F

10 Issue No. 114 / 2014

FIGURE 5: Gasoline Properties as a Function of Riser Outlet Temperature and Feed

Bakken 900˚FBakken 935˚FBakken 970˚FVGO 970˚F

95

90

85

80

15

20

25

30

35

G-Con RON EST G-Con MON EST

G-Con I, wt.%G-Con O, wt.%

75

80

75

70

20

22

24

26

65

Conversion, wt.%

75.0 77.5 80.0 82.5 85.0 75.0 77.5 80.0 82.5 85.0

FIGURE 6: Effect of Conversion Level and Feed Type on LCO Yield and Quality

Bakken 900˚FBakken 935˚FBakken 970˚FVGO 970˚F

22

20

18

16

LCO (430-650˚F), wt.%

14

Conversion, wt.%

75.0 77.5 80.0 82.5 85.0 77.5 80.0 82.5 85.0

Diesel Index

75.0

12

10

50

40

30

20

10

0


Diesel quality is of great interest to refiners. Synthetic crude

produced in the circulating riser pilot plant runs was distilled to

recover the 430°F to 650°F LCO fraction. Aniline point and API

gravity of the LCO were then measured to allow calculation of the

diesel index, a measure of LCO quality [diesel index = (aniline

point x API Gravity)/100]. Figure 6 presents data for LCO yield

and LCO quality as a function of conversion. As seen in the data,

increasing conversion lowers LCO quality as a result of increased

cracking of the LCO range paraffins to lighter hydrocarbons. As

seen in prior work22, LCO quality follows LCO yield and did not

appear to be influenced by reactor temperature at constant

conversion. Diesel index values of the LCO produced by cracking

whole tight oil were significantly higher than those obtained when

cracking the reference mid-continent VGO. At a conversion of 78

wt%, the whole Bakken gave a LCO with a diesel index of 40,

compared to a diesel index of 10 obtained for the LCO produced

from the mid-continent VGO.

This study of the effect of operating variables shows that whole

shale oil responds to FCC operating conditions similarly to

conventional oils. However, the product yield slate is substantially

different in that good quality (high diesel index) LCO is produced in

the FCC and large amounts of low octane gasoline are made.

Processing ChallengesLight sweet crudes are generally easy to process, although

challenges arise when these crudes are the predominant feedstock

in refineries designed for heavier crudes. Tight oils, like other light

sweet crudes, have a much higher ratio of 650°F- to 650°F+

material when compared to conventional crudes. Bakken tight oil

has a nearly 2:1 ratio, while typical crudes such as Arabian Light,

have ratios near 1:1. A refinery running high percentages of tight

oil could become overloaded with light cuts, including reformer

feed and isomerization feed, while at the same time short on feed

for the fluid catalytic cracking unit (FCCU) and the coker. Many

refiners report that while they are benefitting from favorable crude

prices they often are struggling to keep downstream process units

full. At low FCC utilization rates, oftentimes the alkylation unit is

unconstrained, leading to an octane shortage.

Unconstrained downstream units are just one of the challenges

faced by North American refiners. Unconventional oils can vary

wildly in composition from cargo to cargo. Receiving crude in

batches via rail, truck or barge can result in FCC feed changing

rapidly over the course of several weeks or several days. To

increase utilization rates, heavier crudes may be blended with

lighter tight oils, resulting in a “barbell” crude, which has a lot of

material boiling at each end of the boiling point curve, but little in

the middle, reducing VGO yield for the FCC. As previously

discussed, some refiners have tried charging whole crude to the

FCCU in order to boost utilizations, to the detriment of other key

yields such as FCC naphtha octane.

At the FCCU, the challenges range from difficulty maintaining heat

balance when the feed is very light, to unexpected coke make

when contaminant metals rise rapidly. When operating with highly

paraffinic light tight oil feeds that crack easily and produce little

coke, the FCC may become circulation constrained due to low

regenerator temperatures. Refiners report spikes of both

conventional (sodium, nickel and vanadium) and unconventional

metals (iron and calcium) when running tight oil derived feeds.

Sodium and vanadium deactivate zeolite and suppress activity;

nickel promotes dehydrogenation reactions, leading to high gas

make. Unconventional metals such as iron and calcium deposit on

the catalyst surface and cause a loss of diffusivity, which leads to a

loss in conversion and an increase in coke and bottoms. To

maximize profitability with rapidly changing feed quality, catalyst

flexibility is key.

Catalytic Solutions Flexible catalyst functionality is critical for processing

unconventional feeds and mitigating the associated processing

challenges. Grace’s newest FCC catalyst family, that of

ACHIEVE™ catalysts, is designed to provide refiners that flexibility.

Figure 7 summarizes the challenges posed by tight oils and the

catalyst technology solutions for mitigating them.

ACHIEVE™ features an optimized matrix technology to provide

coke-selective bottoms conversion without a gas penalty. The

technology in the high diffusivity matrix of the ACHIEVE™ catalyst

is based on technology embodied in the popular MIDAS® catalyst,

which has been commercially proven to be more iron tolerant than

competitive offerings. ACHIEVE™ incorporates best-in-industry

metals traps for nickel and vanadium, which are highly effective to

minimize coke and gas formation from these conventional metals.

ACHIEVE™ FCC catalyst also contains ultra-stable zeolite that

retains activity in the face of contaminant metals spikes.

ACHIEVE™ can be formulated over a range of activity, rare-earth

exchange, and isomerization activities, to deliver an optimal

balance of gasoline yield to LPG while maintaining an optimum

level of butylenes for the alkylation unit. Increasing catalyst activity,

via zeolite or rare-earth exchange can alleviate a circulation

constraint and restore the heat balance to a comfortable level.

ZSM-5 based additives can be used to boost octane, but the

associated yield of propylene is not always desirable. A better

solution is to boost zeolite isomerization activity within the catalyst

to selectively increase the yield of FCC butylene and iso-butane,

keeping the alky unit full and maintaining refinery pool octane. The

following examples illustrate how the flexibility of the ACHIEVE™

catalyst family can address the challenges posed by tight oil.

12 Issue No. 114 / 2014

Iron and Calcium ToleranceIron and calcium have a negative effect on catalyst performance.

While particulate tramp iron from rusting refinery equipment does

not have a significant detrimental effect on catalyst, finely

dispersed iron particles in feed (either as organic compounds or as

colloidal inorganic particles) can deposit on the catalyst surface,

reducing its effectiveness23,24. The iron deposits combine with

silica, calcium, sodium and other contaminants to form low melting

temperature phases, which collapse the pore structure of the

exterior surface, blocking feed molecules from entering the

catalyst particle and reducing conversion25. Iron in combination

with calcium and/or sodium has a greater negative effect on

catalyst performance than iron alone. The symptoms of iron and

calcium poisoning include a loss of bottoms cracking, as feed

particles are blocked from entering the catalyst particle, and a drop

in conversion.

Catalyst design can be optimized to resist the effects of

contaminant iron and calcium in tight oil feedstocks. High alumina

catalyst, especially catalyst with alumina-based binders and

matrices, such as Grace’s MIDAS® catalyst, are best suited to

process iron- and calcium-containing feeds due to their resistance

to the formation of low-melting-point phases that destroy the

surface pore structure26. Optimum distribution of mesoporosity

also plays a role in maintaining performance because diffusion to

active sites remains unhindered, despite high-contaminant metals.

The resistance of MIDAS® catalyst to iron and calcium poisoning

has been demonstrated in many commercial applications26,27.

Figure 8 presents data from the application of Grace’s MIDAS®

638 catalyst in an operation running 100% tight oil and high levels

of iron. The switch to MIDAS® 638 catalyst reduced bottoms yield

even when iron contamination increased.

FIGURE 7: Challenges Posed by Tight Oil Feedstocks, Their Consequences, and the Catalytic Solutions

Challenge Consequence Catalyst Solution

Fe and Ca Poisoning Loss of Bottoms Cracking and Conversion Employ a High Porosity Matrix

Unpredictable Swings in Contaminant Metals

Loss of Surface Area Leads to Lower MAT and

Conversion

Utilize Traps for Ni and V with High Stability Zeolites

FCC Heat Balance Low Regenerator Temps, Circulation Constraints Increase Catalyst Activity

Refinery Imbalances Lower Severity to Control LPG Reduces Octane

Boost Zeolite IsomerizationActivity

0.90

0.95

1.00

1.05

1.10

1.15ECAT Fe, wt%

5.5

6.5

7.5

8.5

9.5

10.5Bottoms Yield, wt%

Apr-12 Jul-12 Nov-12 Mar-13 Jul-13 Nov-13 Mar-14

Apr-12 Jul-12 Nov-12 Mar-13 Jul-13 Nov-13 Mar-14

Base MIDAS® 638

FIGURE 8: MIDAS® 638 Catalyst Maintains Selectivity in 100% Tight Oil Operation


Nickel and Vanadium ToleranceGrace has a long history of incorporating both nickel and vanadiummetals trapping into the catalyst system, mitigating the negativeimpacts of the metals. Nickel is trapped where it is initially crackedonto the catalyst with a proprietary Grace alumina. The aluminaabsorbs the nickel into the catalyst particle, forming a stable nickelaluminate that is no longer active for dehydrogenation reactions.Grace has been highly successfully in utilizing this technique.Currently 65+% of our worldwide customers are taking advantageof this technology.

For vanadium trapping, incorporation of a trap in the catalystsystem can provide widely dispersed trapping capability, moreeffectively reducing the negative impacts of the contaminant.Grace’s IVT-4 is an integral rare-earth based vanadium trap thatconverts contaminant vanadium into an inert rare-earth vanadate,greatly reducing zeolite deactivation and coke and gas production.Grace is currently using IVT-4 in 60%+ of our worldwide catalystformulations.

An example of the excellent metals trapping performance of theACHIEVE™ catalyst system is shown in Figure 9, which plots Ecatselectivities of ACHIEVE™ catalyst versus a competitive base.The refiner was processing tight oil along with a shifting mix ofopportunity crudes and needed a catalyst with better metals

tolerance. At the same Ecat nickel equivalents, the ACHIEVE™catalyst resulted in lower coke, lower gas and lower hydrogen thanthe competitive base. Figure 10 presents box plots based onrefinery operating data from the reformulation showing thatACHIEVE™ catalyst resulted in higher gasoline yields and lowerhydrogen, delta coke and slurry yield. The superior metalstolerance of the ACHIEVE™ catalyst allowed the refiner toincrease conversion without increasing catalyst addition rate. Thechanges in operating conditions and yields after moving toACHIEVE™ catalyst are summarized in Table VII. Applying typicalGulf Coast economics, the increase in gasoline yield and drop inslurry resulted in a benefit of ~$0.70/bbl for the refinery.

Maintaining Heat BalanceWhen processing very light tight oil derived feedstocks, insufficientcatalytic activity requires that the catalyst circulation rate increaseso that conversion, and thus the coke yield from the catalyst,increases to satisfy the FCC heat balance. If the FCCU cannotphysically circulate enough catalyst, it will be necessary to eitherreduce the unit charge rate or the reaction severity to stay withinthe FCC catalyst circulation limit. Alternatively, refiners can satisfythe heat balance by blending in a heavier feedstock, recyclingslurry, burning torch oil, increasing regenerator air preheat, or

FIGURE 9: ACHIEVE™ Catalyst Delivers Superior Metals Tolerance Compared to a Competitive Base

Competitive Base

ACHIEVETM Catalyst

2.0

1.8

1.6

1.4

200

240

280

320

360

1.2

4

5

6

Ecat Ni Equivalents, ppm

2400 2550 2700 2850 3000

2400 2550 2700 2850 3000

Gas FactorCoke Factor

H2 Yield, SCFB

14 Issue No. 114 / 2014

derating the stripping steam. However, these options often have a

detrimental effect on the operation28,29. Table VIII summarizes the

operating changes that can be made to maintain heat balance and

the potential issues of each change. The best way to satisfy the

heat balance with a very light feedstock is via proper application of

catalyst technology.

As an example of the role of catalyst activity in maintaining heat

balance, consider an FCC unit operating on standard VGO that is

contemplating a move to lighter tight oil feed type. Figure 11

presents pilot plant data of catalyst-to-oil ratio as a function of coke

and conversion on the two feedstocks. The base case catalytic

coke of 2.5 wt.% requires a C/O of about 5.5 and results in 74%

conversion. In order to keep the 2.5% coke yield with the lighter

tight oil feed, a C/O ratio of over 8.0 is necessary with an increase

in conversion to about 77%. Most FCC units are not capable of

this dramatic increase in the catalyst circulation rate and the

catalyst circulation hydraulics will likely limit the unit severity or

throughput.

FIGURE 10: Unit Data Demonstrating Improved Performance of ACHIEVE™ Catalyst Versus the Competitive Base

2.0

0

-20

-40

-3.0

-1.5

0.0

1.5

3.0

CompetitiveBase

Hydrogen, SCFB Conversion, vol.% Gasoline, vol.%

Gasoline + LCO, vol.% Slurry, vol.% Delta Coke

CompetitiveBase

CompetitiveBase

ACHIEVETM

CatalystACHIEVETM

CatalystACHIEVETM

Catalyst

2

4

6

2

-2

0

-2

0

2

4

0.2

-2

0

-0.2

0.0

Operating Parameters Delta (ACHIEVE™-Competitive Base)

Relative Fresh Feed Rate -4%

Feed Temp, °F -72˚F

Feed API Same

Reactor Temp, °F +6˚F

Regen Dense, °F -1˚F

Regen Dilute, °F +3˚F

Catalyst Additions, lbs/bbl Same

Yields

Coke, wt.% +0.1

Delta Coke, wt.% -0.06

430°F Conversion, vol.% +3.8

H2, SCFB -20

Dry Gas, vol.% Same

C3, vol.% +1.2

C4, vol.% +1.4

Gasoline, vol.% +2.1

LCO, vol.% -1.7

Slurry Yield, vol.% -2.1

TABLE VII: ACHIEVE™ Yield Shifts Deliver$0.70/BBLBenefit


FIGURE 11: C/O Ratio Must Increase to Satisfy Heat Balance, After Shift to Light Tight Oil

Coke, wt.% Conversion, wt.%

9.0

8.0

7.0

6.0

3.0

4.0

5.0

9.0

8.0

7.0

6.0

3.0

4.0

5.0

64.0 68.0 72.0 76.0 80.01.0 2.0 3.0

Base - VGO Feed Light Tight Oil Feed

Cat

-to-O

il R

atio

Option Potential Issues

Blend in heavier feedstock Availability of heavier feedstock. Crude incompatibility and asphaltene precipitation. High metals in heavier crudes.

Increase feed preheat Increased energy consumption. Metallurgical limits. Increase in non-selective thermal cracking and dry gas production.

Slurry recycle Feed system fouling. Catalyst erosion. Increased dry gas yield.

Burning torch oil in the regenerator Accelerated catalyst deactivation. Burning of a high value stream.

Reduce stripping steam rate Wear of stripper steam rings. Stripper steam plugging. Accelerated catalyst deactivation.

Increase preheat of regenerator air Increased catalyst and air grid nozzle attrition.

Increase FCC catalyst activity Best and most profitable option for maintaining heat balance.

TABLE VIII: Options for Maintaining Heat Balance with Light Feeds

16 Issue No. 114 / 2014

In this same example, we consider a catalyst reformulation to a

more active catalyst with a different coke to conversion relationship

as seen in Figure 12. Here, Catalyst A is applied and a much more

modest C/O of 6.5 is required to satisfy the coke yield, due to the

inherent catalyst activity of Catalyst A. Because of the coke to

conversion relationship of Catalyst A, higher conversion is

achieved.

Using a high activity catalyst is required to counter the effects of

low delta coke, but it is important to select a catalyst with the

proper coke selectivity (coke to conversion relationship).

ACHIEVE™ catalyst can be formulated with ultra-high activity

zeolite to counter the effects of low delta coke, while delivering the

proper coke selectivity. Grace has had multiple experiences with

reformulations for processing lighter feeds from tight oil or

traditional hydrotreated FCC feed. In one commercial application,

a refiner switched from a competitive catalyst designed for high

activity to Grace’s ACHIEVE™ catalyst. Feed and catalyst

properties are presented in Table IX. The feed was light and

paraffinic with an API of 29.5. Table X presents yields at constant

conversion based on testing of feed and equilibrium catalyst from

the unit. At constant conversion, the switch to ACHIEVE™ catalyst

resulted in higher activity, higher gasoline, higher LCO, lower

bottoms, and improved coke selectivity. Table XI presents yields at

constant coke. At constant coke, the switch to ACHIEVE™ catalyst

resulted in higher activity, higher gasoline and lower bottoms and

an economic uplift of ~$0.40/bbl.

Maintaining Refinery Pool OctaneA common challenge reported by refiners operating on

unconventional feeds, such as shale or tight oil, is a loss of

gasoline pool octane, caused by reduced volume of alkylation

feedstock. Within the ACHIEVE™ catalyst family, ACHIEVE™ 400

catalyst is formulated with multiple zeolites with tailored acidity, to

deliver an optimum level of butylenes to keep the alkylation unit full

and maintain refinery pool octane. Incorporation of isomerization

activity into the catalyst particle itself results in a more desirable

yield pattern than would be realized by use of a traditional octane

boosting FCC additive. In addition, ACHIEVE™ 400 has been

shown to increase the octane of FCC naphtha.

An example of the yield shifts that are possible with this technology

is found in Table XII, which presents yields based on DCR™ pilot

plant testing of base MIDAS® catalyst, MIDAS® catalyst with added

conventional ZSM-5 based OlefinsMax® additive, and ACHIEVE™

400 catalyst with multiple zeolite technology. The physical

properties of the fresh catalysts in the study are given in Table XIII.

With traditional ZSM-5 technology, cracking of gasoline olefins

continues past C7 into the C6 and generates a disproportionate

amount of propylene relative to butylenes as shown in Figure 13.

Figure 14 presents the difference in olefins yields by carbon

number versus the base case for the ACHIEVE™ catalyst and the

MIDAS® catalyst with OlefinsMax® additive. Olefins cracking for

the ACHIEVE™ 400 catalyst stopped at C7 olefins (as seen by the

ACHIEVE™ 400 catalyst producing the same level of C6 olefins as

FIGURE 12: Effect of Change in Catalyst Activity on Catalyst to Oil Requirements to Maintain Constant Coke

Coke, wt.% Conversion, wt.%

9.0

8.0

7.0

6.0

3.0

4.0

5.0

9.0

8.0

7.0

6.0

3.0

4.0

5.0

64.0 68.0 72.0 76.0 80.01.0 2.0 3.0

Base - VGO Feed Light Tight Oil Feed

Cat

-to-O

il R

atio

Catalyst A


Feed PropertiesAPI Gravity, ˚F 29.5

CCR, wt.% 0.29

K-factor 12.19

n-d-m AnalysisCa, Aromatic Ring Carbons, % 13.9

Cn, Naphthenic Ring Carbons, % 16.9

Cp, Paraffinic Carbons, % 69.2

Equilibrium Catalyst Properties

TABLE IX: Feed and Catalyst Properties for Commercial Application of High Activity Catalyst with Light Feed

Competitive Base ACHIEVETM Catalyst

Zeolite Surface Area, m2/g 164 154

Ni, ppm 176 203

V, ppm 892 1022

Competitive Base

ACHIEVETM

CatalystC/O Ratio 6.9 5.8

Conversion, wt.% 76.0 76.0

H2 Yield, wt.% 0.05 0.04

Dry Gas, wt.% 1.0 1.0

Propylene, wt.% 4.5 4.4

Total C3's, wt.% 5.6 5.5

Total C4='s, wt.% 5.5 5.5

Total C4's, wt.% 12.7 12.4

Gasoline, wt.% 54.2 54.9

LCO, wt.% 17.2 17.6

Bottoms, wt.% 6.8 6.4

Coke, wt.% 2.7 2.5

TABLE X: ACHIEVE™ Catalyst Outperforms Competitive Technology in a Light Feed Application - Yields at Constant Conversion

Competitive Base

ACHIEVETM

Catalyst

Coke, wt.% 2.7 2.7

C/O Ratio 6.9 6.4

Conversion, wt.% 76.0 77.4

H2 Yield, wt.% 0.05 0.05

Dry Gas, wt.% 1.0 1.0

Propylene, wt.% 4.5 4.5

Total C3's, wt.% 5.6 5.7

Total C4='s, wt.% 5.5 5.5

Total C4's, wt.% 12.7 12.9

Gasoline, wt.% 54.2 55.3

LCO, wt.% 17.2 16.9

Bottoms, wt.% 6.8 5.7

TABLE XI: ACHIEVE™ Catalyst Outperforms Competitive Technology in a Light Feed Application - Yields at Constant Coke

FIGURE 13: ACHIEVE™ 400 Catalyst Preferentially Cracks Gasoline Olefins at C7 and Above

Reactant SelectivityRelative

Selectivity C3=/C4=

C8=2 C4=C3= + C5=

44%56% 100 0.64

C7=C3= + C4=C2= + C5=

95%2% 12 1.0

C6=2 C3=C2= + C4=

83%16% 1.5 11

ACHEIVETM 400 Catalyst

ZSM-5 Additive

Buchanan, et. al., Ref. 30

18 Issue No. 114 / 2014

the base case), while the use of ZSM-5 additive resulted in

cracking of C6 olefins, as seen by the drop relative to the base

case. The newly developed dual-zeolite technology in ACHIEVE™

400 works synergistically with Grace’s high diffusivity matrix, to

selectively enhance olefinicity, preferentially cracking gasoline

olefins at C7 and above into butylene. The result is a higher ratio

of C4 to C3 olefin yield than separate light olefins additives. Figure

15 illustrates the butylene selectivity improvement of ACHIEVE™

400 catalyst compared to a system using conventional ZSM-5

based additive.

At constant conversion, ACHIEVE™ 400 catalyst delivers higher

gasoline octane and higher LPG olefins, with preferentially more

butylenes over propylene. The net result is higher total octane

barrels for the refinery. Figure 16 presents plots of RON and MON

versus conversion, showing that the ACHIEVE™ 400 catalyst

results in higher gasoline octane than the base MIDAS® catalyst

and the MIDAS® catalyst with added conventional ZSM-5 based

OlefinsMax® additive. As seen in Figure 17, coke and bottoms are

equivalent between the base case and the ACHIEVE™ 400

catalyst, demonstrating that the increased butylenes selectivity

was realized without compromising the bottoms conversion activity

of the catalyst. The distribution between different butylene isomers

is the same with ACHIEVE™ 400 catalyst as with the MIDAS®

catalyst with added conventional ZSM-5 based OlefinsMax®

additive, as seen in Figure 18.

Carbon Number

0 1 2 3 4 5 6 7

1.5

0.5

0

-0.5

-1

1

Base MIDAS® Catalyst + OlefinsMax® Additive ACHIEVETM 400 Catalyst

Ole

fins,

wt.%

FF

FIGURE 14: Incremental Olefin Yields by Carbon Number at Constant Conversion Demonstrate thatACHIEVE™ 400 Catalyst Does Not Crack C6 Olefins as ZSM-5 Based Additives Do

0.7 0.8 0.9 1 1.1 1.2 1.3 1.40.6

C3=

C4=

1.4

1

0.8

0.6

1.2

Base MIDAS® Catalyst + OlefinsMax® Additive ACHIEVETM 400 Catalyst

FIGURE 15: At Constant Conversion ACHIEVE™ 400Delivers a Higher Ratio of C4 to C3 Olefins than Use ofa Separate ZSM-5 Based Olefins Additive

94.6

93.8

93.4

93.0

94.2

94.0

93.6

93.2

94.4

80.6

79.8

79.4

79.0

80.2

80.0

79.6

79.2

80.4

70 72 74 76 78

70 72 74 76 78

Conversion, wt.%

Conversion, wt.%

MO

NR

ON

Base MIDAS® Catalyst + OlefinsMax® Additive

ACHIEVETM 400 Catalyst

Base MIDAS® Catalyst

FIGURE 16: ACHIEVE™ Delivers Higher RON and MON


The octane number of gasoline is determined by the hydrocarbon

types present in the gasoline. While there are complex blending

interactions between the different hydrocarbon types, the general

effect of hydrocarbon type on octane can be seen in pure

component octane data. Figure 19 presents pure component RON

and MON values by carbon number for different hydrocarbon

families based on data from API Technical Project 4531. In cases

where more than one isomer is present, an average of the octane

values for the different isomers was used. As seen in the figures,

aromatics and olefins have roughly equivalent octanes, while

naphthenes, iso-paraffins and normal paraffins have lower octane

numbers. The octane numbers of olefins and aromatics are

relatively unchanged with carbon number, while those of

naphthenes, iso-paraffins and normal paraffins drop as the chain

length grows. In addition to hydrocarbon type (olefin, paraffins,

aromatic, etc.), the degree of branching within a molecule affects

10

6

6 6.5

8

7

55.5

9B

otto

ms,

wt.%

7.5 87.0

Coke, wt.%




FIGURE 17: Coke to Bottoms is Maintained withACHIEVE™ 400 Catalyst

tC4=cC4= 1-C4=iC4=



40%

0%

20%

10%

30%

% T

otal

C4=

FIGURE 18: Distribution of Butylene Isomers forACHIEVE™ 400 and Base Midas® + OlefinsMax®

Res

earc

h O

ctan

e N

umbe

rM

otor

Oct

ane

Num

ber

140

-20

60

20

100120

-40

40

0

80

-80-60

-20

60

20

100120

-40

40

0

80

-80-60

2 4 6 8 10 12 14

2 4 6 8 10 12 14

Aromatics Olefins Naphthalenes

monomethyl-iso-paraffins n-paraffins

Carbon Number

Carbon Number

FIGURE 19: Pure Component RON and MON as a Function of Hydrocarbon Type and Carbon Number(Based on API Research Project 45)

octane. As an example, for C6 olefins, the straight chain molecule

1-hexene has a RON of 76, the single branched molecule 2-

methyl-1-pentene has a RON of 94, and the doubly branched

molecule 2,3-dimethyl-2-butene has a RON of 9731. The octane

enhancement from the ACHIEVE™ 400 catalyst is from increased

gasoline olefins and from increased olefins isomerization. In Table

XII, the PIANO data shows that the ACHIEVE™ 400 catalyst has a

higher olefins concentration in the gasoline than the MIDAS®

catalyst base case or the MIDAS® catalyst with OlefinsMax®

additive. The degree of olefins branching of gasoline in the DCR™

study is presented in Figure 20. The gasoline olefins produced by

the ACHIEVE™ 400 catalyst were more highly branched, resulting

in higher naphtha octane.

The increased butylene selectivity of ACHIEVE™ 400 catalyst can

help refiners address the potential octane debits associated with

light paraffinic tight oil feeds. Figure 21 presents plots of the

annualized value of improved butylene selectivity for a 50,000

BBL/day FCCU based on several butylene to gasoline value

differentials. For a hypothetical case where butylene is valued at

$45/bbl over gasoline, each 0.1 wt.% increase in butylene

selectivity results in >$0.8MM/yr more value.

20 Issue No. 114 / 2014


Base MIDAS® Catalyst+

OlefinsMax® Additive


Cat to Oil 8.7 9.2 8.3

Dry Gas, wt.% 2.84 2.78 2.75

C3=, wt.% 4.3 5.1 5.3

Total C4's, wt.% 9.3 10.2 10.6

iC4, wt.% 1.5 1.7 1.6

nC4, wt.% 0.4 0.4 0.4

Total C4=, wt.% 7.3 8.1 8.5

C4=/C3=, wt.% -- 0.89 1.1

Gasoline, wt.% 50.8 49.1 48.7

LCO, wt.% 18.4 18.2 18.2

Bottoms, wt.% 6.6 6.7 6.7

Coke, wt.% 6.9 6.8 6.7

G-Con RON 93.50 93.53 94.12

G-Con MON 79.69 79.80 80.07

G-Con P, wt.% 3.0 3.0 2.8

G-Con I, wt.% 18.5 18.5 17.9

G-Con A, wt.% 31.3 32.2 31.9

G-Con N, wt.% 10.9 10.7 10.2

G-Con O, wt.% 36.3 35.6 37.2

TABLE XII: ACHIEVE™ 400 Catalyst Provides Higher Octane and More C4 Olefins than Using ZSM-5 Additive


Base MIDAS® Catalyst+

OlefinsMax® Additive


Al2O3, % 55.9 55.3 54.5

RE2O3, % 1.4 1.4 1.4

ABD, g/cm3 0.70 0.67 0.70

APS, microns 78 76 75

ZSA, m2/g 134 140 145

MSA, m2/g 140 142 143

TABLE XIII: Fresh Catalyst Properties

ConclusionThe tight oil boom has resulted in a renaissance in the North

American refining industry. While tight oils are generally light and

sweet and easy to crack, quality can vary greatly and tight oil

derived feeds can contain sediments with high levels of iron and

alkali metals. The light nature of these feeds can result in difficulty

maintaining heat balance, and the paraffinic nature of the feed

slate can result in octane debits in the refinery. Proper catalyst

choice allows refiners to most fully exploit the opportunity of tight

oil while minimizing the detrimental impacts. Grace’s newest

catalyst family, ACHIEVE™ catalyst, is designed with the flexibility

to enable refiners to proactively respond to the opportunity of tight

oil. The ACHIEVE™ catalyst family is currently in commercial

testing.

In addition to catalyst selection, an equally critical component to

minimizing risks and challenges associated with processing

unconventional feeds is solid technical service support. Grace has

been providing industry-leading technical service to the refining

industry since 1947. Grace retains qualified, experienced

engineers to support FCC customers by providing application and

operations expertise, as well as start-up and optimization

assistance and industry benchmarking. With the backing of

advanced R&D facilities and high throughput testing labs, let

Grace’s technical service team help you assess potential

challenges before they occur in your FCCU via feed

characterization, feed component modeling, and pilot plant

studies. Understanding feed impacts earlier allows opportunity to

optimize the operating parameters and catalyst management

strategies, enabling a more stable and profitable operation.


AcknowledgementsThe authors thank colleagues at Grace for assistance with the

testing and analysis for this paper. The many contributions of

Olivia Topete and Jeff Koebel to this paper are gratefully

acknowledged.

References1. U.S. Energy Information Administration, “January 2014

Drilling Productivity Report for Key Tight Oil and Shale Gas

Regions,” released January 14, 2014.

2. U.S. Energy Information Administration, “Annual Energy

Outlook 2014 Early Release Overview,” December 16, 2013.

3. U.S. Energy Information Administration, “Technically

Recoverable Shale Oil and Shale Gas Resources: An Assessment

of 137 Shale Formations in 41 Countries Outside the United

States,” June 2013.

4. BP, “BP Energy Outlook 2035,” January 2014.




0.63

0.6

0.57

0.55

0.61

94.0

0.58

0.56

0.62

0.52

0.48

0.46

0.44

0.5

0.49

0.47

0.45

0.51

0.42

0.43

70 72 74 76 78Conversion, wt.%


C5=

Bra

nche

d/C

5 Tot

alC

6= B

ranc

hed/

C6 T

otal

FIGURE 20: ACHIEVE™ 400 Catalyst Results in Increased C5 and C6 Olefins Branching

FIGURE 21: Annualized Value of Improved ButyleneSelectivity for a 50,000 BBL/day FCCU

0 0.1 0.2 0.3 0.4 0.5 0.6

$45/BBL

Uplift from Gasoline to C4= (%)

$6,000,000

$5,000,000

$4,000,000

$3,000,000

$2,000,000

$1,000,000

Value Differentialbetween C4= andGasoline

$60/BBL

$15/BBL$30/BBL

5. Marfone, P.A., “Refiners Have a New Learning Curve with

Shale Oil,” Hydrocarbon Processing, March 2013.

6. Kremer, L., “Shale Oil Issues and Solutions,” AFPM Principles

and Practices Session, Salt Lake City, Utah, October 2012.

7. Haynes, D., “Tight Oil Impact on Desalter Operations,” Crude

Oil Quality Association Meeting, New Orleans, Louisiana,

November 2012.

8. Ohmes, R., Routt, M., “Characterizing and Tracking

Contaminants in Opportunity Crudes,” 2013 AFPM Annual

Meeting, San Antonio, Texas.

9. D. Hill, “North Dakota Refining Capacity Study Final Technical

Report,” DOE Award No.: DE-FE0000516, January 5, 2011.

10. Platts Methodology and Specifications Guide, “The Eagle

Ford Marker: Rationale and Methodology,” October 2012.

11. “Effects Of Possible Changes In Crude Oil Slate On The U.S.

Refining Sector’s CO2 Emissions,” prepared for the International

Council On Clean Transportation by MathPro Inc., March 29, 2013.

12. Haas, A., McElhiney, G., Ginzel, W., Buchsbaum, A.,

“Gasoline Quality- The Measurement of Compositions and

Calculation of Octanes,” Petrochem./Hydrocarbon Technol. 1990,

43, 21-26.

13. Cotterman, R. L., Plumlee, K. W., “Effects of Gasoline

Composition on Octane Number,” ACS Meeting; Miami Beach,

Florida, 1989.

14. Savage, G., “Crude Preheat Management for Challenged and

Unconventional Crudes,” Crude Oil Quality Association Meeting,

San Antonio, Texas, March 2013.

22 Issue No. 114 / 2014

15. Holubnyak, et. al., “Understanding the Souring at Bakken Oil

Reservoirs,” SPE International Symposium on Oilfield Chemistry,

The Woodlands, Texas, April 2011.

16. Cioppa, M.T., “Spatial Variations in Magnetic Components of

the Devonian Birdbear Formation, Williston Basin,” presented at

the Geofluids VII Conference, Rueil-Malmaison, France, June

2012.

17. Keyser, J.C., “Versatile Fluidized Bed Reactor,” US Patent

6,069,012, assigned to Kayser Technology, 2000.

18. Fitzharris, W.D., Ringle, S.J., Nicholes, K.S.,“Catalytic

Cracking of Whole Crude Oil,” U.S. Patent 4,859,310 (1989),

assigned to Amoco Corporation.

19. Masologites, G.P., Beckberger, L.H., “Low-sulfur Syn Crude

via FCC,” Oil and Gas Journal, 71 (1973), pp. 49-53.

20. Bryden, K., Weatherbee, G., Habib, E.T., “Flexible Pilot Plant

Technology for Evaluation of Unconventional Feedstocks and

Processes AM-13-04,” 2013 AFPM Annual Meeting, San Antonio,

Texas.

21. Chapter 6, “FCC Operation,” in The Grace Davison Guide to

Fluid Catalytic Cracking, 1993.

22. Ritter, R.E., “Light Cycle Oil from the FCC Unit AM-88-57,”

1988 NPRA Annual Meeting, San Antonio, Texas.

23. Cheng, W.-C., Habib, E.T., Rajagopalan, K., Roberie, T.G.,

Wormsbecher, R.F., Ziebarth, M.S., “Fluid Catalytic Cracking,” in

Handbook of Heterogeneous Catalysis, 2nd. Ed., 2008, pp. 2741-

2778.

24. Yaluris, G., “The Effects of Fe Poisoning on FCC Catalysts:

An Update,” Catalagram® 91, W.R. Grace & Co., 2002.

25. Yaluris, G., Cheng, W.-C., Boock, L.T., Peters, M., Hunt, L.J.,

“The Effects of Fe Poisoning on FCC Catalysts, AM-01-59” 2001

NPRA Meeting, New Orleans, Louisiana.

26. Bryden, K.J., Habib, E.T., Topete, O.A., “Processing Shale

Oils in FCC: Challenges and Opportunities,” Hydrocarbon

Processing, September 2013.

27. Cher, Y.-Y., Koebel, J., Schiller, R., “Enhanced Bottoms

Cracking and Process Flexibility with Midas® FCC Catalyst,”

Catalagram® 112, W.R. Grace & Co., 2012.

28. Answers to Question 113, 2006 NPRA Q&A and Technology

Forum, October 8-11, 2006, Phoenix, AZ.

29. Answers to Question 42, 2009 NPRA Q&A and Technology

Forum, October 11-14, 2009, Fort Worth, TX.

30. Buchanan, J.S., Santiesteban, J.G., Haag, W.O.,

“Mechanistic Considerations in Acid-Catalyzed Cracking of

Olefins,” Journal of Catalysis, Volume 158, January 1996, Pages

279-287.

31. Knocking characteristics of pure hydrocarbons, Developed

Under American Petroleum Institute Research Project 45, Special

Technical Publication No. 225; American Society for Testing and

Materials: West Conshohocken, PA, 1958.

32. Schipper, P. H., Dwyer, F.G., Sparrell, P.T., Mizrahi, S.,

Herbst, J.A., “Zeolite ZSM-5 in Fluid Catalytic Cracking:

Performance, Benefits, and Applications.” In Fluid Catalytic

Cracking, edited by Mario L. Occelli, 375:64–86. Washington, DC:

American Chemical Society, 1988.


Tight Oil Distillate in ULSD Production, What To Expect?

Greg RosinskiHydrotreating TechnicalService Engineer

Brian WatkinsManager,Hydrotreating PilotPlant and TechnicalService Engineer

Charles OlsenDirector, Distillate R&Dand Technical Service

Advanced Refining TechnologiesChicago, IL, USA

Global growth in distillate demand has driven refiners to maximize their middle distillate yield while trying

to manage final product properties such as cold flow properties, color, and cetane. This has been coupled

with the availability of new domestic and unconventional crude oil sources and the global disparity in

hydrogen cost and availability. This has given some refiners a unique opportunity to exploit different

catalytic routes to maximizing middle distillate production. Catalytic solutions to increase middle distillate

yield while controlling final product properties include hydrotreating, hydrocracking, and hydrodewaxing.

Each of these routes present challenges in terms of hydrogen consumption, yield shifts, changes in cycle

life, and the chemistry involved.

In addition to new sources of crude, the price of natural gas in the North America has decreased and is

significantly lower than the rest of the world (Figure 1). This has given North American refiners an

incentive to pursue volume gain due to the reduced cost of hydrogen derived from natural gas.

Furthermore, worldwide demand for distillates has grown, and the U.S., while still a net importer of crude

oil, has become a net exporter of refined products due in part to a competitive cost advantage in

hydrogen (Figure 2). ULSD comprises the largest amount of net exports, with most of the balance being

gasoline and jet fuel. Thus, U.S. Refiners have been utilizing their competitive advantage in fuels

production as the relative price of natural gas has fallen.

In the last decade new sources of crude have also come on the market (Figure 3). Most of the increase

has come from bitumen derived synthetic crudes from Canada or more recently from shale oil formations,

principally Bakken and Eagle Ford. Since 2007 almost one million barrels of new synthetic crude from

Canada has become available and shale formations have provided over two million barrels of additional

crude to the North American market. Almost all of the new crude to come to market is captive to North

America. Refiners have eagerly tried to utilize these new sources of crude due to pricing and availability,

which has lead to enhanced profitability for refiners who have access to these new crude sources.

24 Issue No. 114 / 2014

The rapidly increasing availability of tight oils like Bakken and

Eagle Ford have given rise to questions about the impact these

crudes may have on processing units in the refinery. The

questions include concerns regarding the cold flow properties,

ease of processing and hydrogen consumption implications. With

these questions in mind, Advanced Refining Technologies

completed a study which investigated the effects of tight oil

compared to a conventional crude diesel cut. The study also

included LCO blends, to gain an understanding of the differences

this would have on distillate hydrotreater performance.

Table I summarizes the properties of the various feeds used in the

study. Notice that the cloud point of the Bakken feed is not very

different from other light sweet crude blends in the mid-continent

region of the U.S. Also, note that the aromatics content is similar

to other straight run (SR) material with similar gravity. This would

indicate that the heat release should be similar to other light sweet

crudes such as WTI or Brent (Table II). The sulfur content of the

Bakken feed is low, and the fraction of hard sulfur is higher than

expected. Furthermore, the cetane index is similar to the reference

SR which is expected from similarities in API gravity and aromatics

content. The analytical testing showed trace amounts of silicon in

the Bakken diesel; all other contaminants were below the detection

limit.

ART used its newest high activity nickel molybdenum (NiMo)

catalyst, 545DX for this study. 545DX is made using a new

proprietary alumina technology which enhances the activity derived

from ART’s DX metals technology platform. This has resulted in a

substantial increase in HDS, HDN, and aromatic saturation, over

the previous generation of NiMo catalysts. NiMo was chosen for

this study as many refiners have shown a preference for volume

swell over the concern of increased hydrogen cost.

The test was conducted at 1050 psi hydrogen partial pressure and

1.1 LHSV with 2800 scfb H2/Oil. The LCO used in both blends was

from the same source. The Bakken diesel cut was from a refiner

who was processing a high percentage of Bakken crude in the

refinery. The straight run (SR) and LCO both came from a mid-

continent refiner processing crudes from Canada.

Figure 4 shows the HDS activity for each feed. At these

conditions, both the SR and Bakken SR met the 10 ppm product

sulfur specification at relatively low temperatures. Notice that the

SR is significantly more difficult to treat requiring 20-30°F higher

WABT compared to the Bakken diesel. Interestingly, the addition

of LCO to the Bakken SR had a much greater impact on HDS

catalyst performance than the LCO addition to the reference SR.

The difference in required temperature narrows substantially to

only about 20-25°F with the addition of 30%LCO. The reference

SR/LCO blend required about 30°F higher temperature to achieve

10 ppm sulfur compared to the SR alone, while the Bakken/LCO

blend required about 50°F higher temperature compared to the

Bakken SR. As typical for many ultra low sulfur diesel (ULSD)

1/1/

2004

7/1/

2004

1/1/

2005

7/1/

2005

1/1/

2006

7/1/

2006

1/1/

2007

7/1/

2007

1/1/

2008

7/1/

2008

1/1/

2009

7/1/

2009

1/1/

2010

7/1/

2010

1/1/

2011

7/1/

2011

1/1/

2012

7/1/

2012

1/1/

2013

7/1/

2013

1/1/

2014

USB

/MM

BTU

8

16

20

0

12

4

Germany, NG Japan, LNG United States, NG

FIGURE 1: World Natural Spot Natural Gas Prices

Jan-

04Ju

l-04

Jan-

05Ju

l-05

Jan-

06Ju

l-06

Net Crude Oil Imports Net Refined Product Imports

Jan-

07Ju

l-07

Jan-

08Ju

l-08

Jan-

09Ju

l-09

Jan-

10Ju

l-10

Jan-

11Ju

l-11

Jan-

12Ju

l-12

Jan-

13Ju

l-13

Jan-

14

14000

12000

10000

8000

6000

4000

2000

0

-2000

-4000

FIGURE 2: Net US Imports of Crude Oil and RefinedPetroleum Products

May-05

Bakken Eagle Ford

Oct-06 Feb-08 Jul-09 Nov-10 Apr-12 Aug-13 Dec-14

Lt. Synthetic Oil Sands Heavy

1,600

1,400

1,200

1,000

800

600

400

200

0

Mbb

ls/D

ay

FIGURE 3: Canadian Synthetic Crude Supply and U.S.Tight Oil Production


1000

100

10

1

0.1

Prod

uct S

ulfu

r, w

ppm

0 20 40 60 80 100 120 140 160

Increase in WABT, ˚F

SR SR + LCO Bakken Bakken + LCO

FIGURE 4: Comparison of HDS Activity

SR SR + 30% LCO Bakken Bakken + 30% LCO

Gravity, ˚API 35.50 27.10 34.80 28.90

Sulfur, wt.% 1.200 1.868 0.113 0.831

Nitrogen, wppm 157 423 116 307

Total Aromatics, vol.% 25.1 39.7 23.6 33.8

PNA (2 + ring), vol.% 8.7 23.2 7.2 17.5

Cloud Point, °F 34.9 22.8 19.2 14.5

Cetane Index (D976) 53.9 41.3 53.6 44.4

ASTM Color L1 L5 L5 L3

Distillation (ASTM D86)

IBP, ˚F 378 392 410 411

10, ˚F 455 473 500 499

30, ˚F 525 536 555 553

50, ˚F 575 579 589 588

70, ˚F 622 624 620 621

90, ˚F 686 680 668 667

FBP, ˚F 738 730 720 715

Sulfur Speculation

Gasoline Range Sulfur, wppm 94 64 0 2

Benzothiophene, wppm 8 118 0 79

C1-Benzothiophene, wppm 168 824 0 526



C4+Benzothiophene, wppm 1834 2101 10 595

Dibenzothiophene, wppm 132 290 148 226

C1-Dibenzothiophene, wppm 2050 2618 337 1103

C2-Dibenzothiophene, wppm 1768 2909 330 1447

4,6-Dibenzothiophene, wppm 180 228 73 117

C3+Dibenzothiophene, wppm 3618 4594 206 1589

% Hard Sulfur 46.4 41.4 54.0 37.9

TABLE I: Feedstock Properties

Bakken Brent

Cut Range See Table 1 445-705

API 34.8 34.9

Sulfur, wt.% 0.113 0.263

TABLE II: Properties of Brent and Bakken Diesel

26 Issue No. 114 / 2014

units, the product nitrogen was low. Even at modest temperatures,

all the feeds were below 10 wppm nitrogen, and once the 10 wppm

sulfur specification was met, all were <0.5 wppm nitrogen.

Figure 5 compares the total aromatic saturation of the Bakken

feeds. The temperature for maximum aromatic saturation of the

straight run Bakken is slightly lower compared to the Bakken/LCO

blend, and the conversion is significantly higher. As shown in

Table I, the nitrogen content of the LCO blend is nearly three times

higher than the SR Bakken which inhibits aromatic saturation

reactions. Also, the LCO blend has a higher aromatics content,

which reduces the outlet H2 partial pressure due to the higher

hydrogen consumption, which affects equilibrium and limits

conversion. The overall effect is the maximum saturation

conversion occurs at 10-15°F lower temperature and is almost

twice as high with the SR Bakken.

Figure 6 compares the aromatics saturation on all the feed blends.

The reference SR and Bakken SR both exhibit similar aromatics

saturation curves as temperature is increased. The Bakken SR

appears to have higher conversion in the kinetically controlled

regime, probably due to the lower nitrogen and sulfur content n the

feed. The SR/LCO blend behaves similar to the Bakken/LCO

blend in terms of aromatic saturation although there are some

differences at higher temperature perhaps indicative of different

aromatic species.

Figure 7 compares the PNA saturation in the Bakken feeds. The

PNA conversion on the SR Bakken is nearly 100% until

thermodynamic equilibrium is reached and limits conversion. The

PNA conversion on the Bakken/LCO is always lower and reaches a

maximum of about 94%. Once the aromatic conversion

thermodynamic equilibrium is reached, there is a fairly rapid drop

off in conversion as temperature is increased. This is what is

expected near the end of run in a commercial ULSD unit, and often

leads to product color problems.

Figure 8 compares the PNA conversion on all the feeds tested. It

is interesting to note that the PNA conversion when processing the

Bakken feeds decreases more rapidly and approaches equilibrium

sooner than the other feeds. This is likely due to a difference in

the PNA distribution in the Bakken crude.

It is generally accepted that PNA conversion has an influence on

product color, and in particular, three ring aromatics have been

shown to significantly impact product color1. Since the PNA

conversion decreases faster with increasing temperature when

processing the Bakken blends, the product color achieved from

each of the blends was also investigated. Figure 9 summarizes

the product color for each of the feeds that were tested. As

observed with the PNA conversion, both the Bakken straight run

and the reference SR show a similar change in product color with

increasing reactor temperature. However, the Bakken SR product

0 20 40 60 80 100 120

Bakken Bakken + LCO

140 160

Increase in Temperature, ˚F

70.0%

Tota

l Aro

mat

ic C

onve

rsio

n, v

ol.% 60.0%

50.0%

40.0%

30.0%

20.0%

10.0%

0.0%

-10.0%

-20.0%

FIGURE 5: Total Aromatics Saturation on BakkenDiesel

0 20 40 60 80 100 120 140 160


70.0%

Tota

l Aro

mat

ic C

onve

rsio

n, v

ol.% 60.0%

50.0%

40.0%

30.0%

20.0%

10.0%

0.0%

-10.0%

-20.0%


FIGURE 6: Total Aromatic Saturation for All Feeds

0 20 40 60 80 100 120

Bakken Bakken + LCO

140 160


PNA

Con

vers

ion,

vol

.%

110%

100%

90%

80%

70%

60%

50%

FIGURE 7: PNA Conversion on Bakken Diesel


color begins to increase at a lower temperature compared to the

reference SR. This is consistent with the PNA conversion shown in

Figure 8. Adding LCO to the SR feeds results in higher product

colors even for lower temperatures. The temperature at which the

product color begins to degrade further is also lower for the LCO

blends consistent with the behavior described for PNA conversion.

Figures 10 and 11 show the API gain and the cetane lift

respectively. As might be expected, the Bakken SR shows the

lowest API and cetane lift, which is due in part to the lower sulfur

level which is about 10% of that in the reference SR. Even though

the total aromatic content of the Bakken feedstock is similar to that

of the reference SR feed, the lower feed sulfur is a driving force for

lower API upgrade and volume swell.

Interestingly, the API increase and cetane lift of the reference SR

and the Bakken/LCO blend are almost the same. This is due in

part to a greater shift in distillation shift caused by the LCO, as

cetane is a function of both API and distillation. The LCO blend

also has much higher PNA content which plays a role in API and

cetane improvement as well.

For the most part, hydrotreating does not change the cloud point

substantially. This testing confirms that over the typical operating

range, the cloud point stays within a fairly narrow window of +/- 5°F

of the feed. Both LCO blends have products with cloud points a

few degrees above the feed. The LCO blends must contain

naphthenic type species that have a higher cloud point than the

feed. All the feed blends show a decrease in cloud point as the

temperature increases substantially from start of run. This may be

indicative of some cracking that occurs at high temperatures

converting molecules with higher cloud points to molecules with

lower cloud points. This data does show that the cold flow

properties of Bakken are not significantly different than the other

feeds in this study.

With the concern over the cold flow properties of tight oils it is

worthwhile to examine how they compare to other crudes,

including some synthetic crudes (Table III). Looking at the assays

of several well known crudes, the cloud points of the diesel

fractions vary between 15-30°F depending on the source, and the

Bakken appears to be no different. The interesting thing to note is

the low cloud points of the Canadian synthetic crudes. Canadian

synthetic crudes are typically produced with some form of

hydroprocessing and or coking so they have higher amounts of

naphthenes; thus, these crudes have lower cloud points, compared

to conventional crudes. If it made sense for the refiner and they

were cloud point constrained, then switching to some synthetic

crude may be a sound choice, as opposed to using a dewaxing

catalyst which will increase naphtha yield at the expense of

distillate yield3. This would have to be balanced against the

economics of the refinery as a whole.

PN

A C

onve

rsio

n, v

ol.%

110%

100%

90%

80%

70%

60%

50%0 20 40 60 80 100 120 140 160



FIGURE 8: PNA Conversion on all Four Feed Blends

0 20 40 60 80 100 120 140


AST

M P

rodu

ct C

olor

3.0

2.5

2.0

1.5

1.0

0.5

0.0


FIGURE 9: Comparison of Product Color ProcessingVarious Feed Blends

0 20 40 60 80 100 120 140


160

API

Gai

n

12.0

10.0

8.0

6.0

4.0

2.0

0.0


FIGURE 10: Difference in API Increase

28 Issue No. 114 / 2014

Table IV compares the product properties from all the feeds at a

product sulfur of 10 wppm . As expected, the Bakken diesel has a

very low temperature for 10 wppm product sulfur. This is primarly

due to the low feed sulfur, which is approximately 0.1 wt.%,

whereas the other feeds have sulfur levels closer to 1 wt.% or

greater. The cetane lift and API gain of the Bakken are also

noticeably lower compared to the other feeds . All of these indicate

lower hydrogen consumption for the Bakken SR compared to the

other feeds.

A breakdown of the hydrogen consumption at constant product

sulfur by compound type is shown in Figure 13. The lower required

temperatures shown in Table III result in much lower total aromatic

and PNA saturation for the Bakken SR feed. This, combined with

the very low sulfur conversion required to achieve 10 ppm product

sulfur, contributes to the lower overall hydrogen consumption. It is

expected that most refiners will be blending in LCO and/or light

coker gas oil which will increase the hydrogen consumption over

the Bakken SR feed. The Bakken/LCO blend appears to behave

Crude Cutpoints (˚F) Cloudpoint (˚F)

Conventional

Bonny Light 445-705 23.0

Brent 445-705 23.0

Dubai 445-705 28.4

Forties 445-705 26.6

Ural 445-705 17.6

Southern Green Canyon Blend 480-650 3.2

Maya 480-650 17.0

Canadian Synthetic

Cold Lake 480-650 -36.0

Kearl 480-650 -31.0

Western Canadian Select Blend 480-650 -38.0

Synbit SHB (Surmont Heavy Blend) 45-705 -25.6

TABLE III: Cloud Point of the Diesel Fractions of Various Crudes

SR SR/LCO Bakken Bakken/LCO

WABT Base +33˚F -41˚F +10˚F

API Change 4.5 9.1 1.1 5.6

Sulfur, wppm 10 10 10 10

Nitrogen, wppm 0.2 0.3 0.2 0.3

Total Aromatics, vol.% 14.7 25.6 18.2 27.1

PNA, vol.% 0.3 1.6 0.7 1.5

Cetane Lift 5.4 10.4 1.9 6.9

Delta Cloud -0.5 5.2 0.0 1.7

H2 Consumption, SCFB 380-410 670-700 160-200 370-400

TABLE IV: Comparison of Product Properties at 10 wppm Sulfur

0 20 40 60 80 100 120 140


160

API

Gai

n

12.0

10.0

8.0

6.0

4.0

2.0

0.0


FIGURE 11: PNA Comparison of Cetane Uplift


much like the reference SR feed in terms of SOR temperature and

hydrogen consumption.

The lower hydrogen consumption with the Bakken SR feed may

cause a heat balance issue if the unit was originally designed for

processing feed from a heavier crude slate, and the Bakken

displaced some of the heavy crude. Figure 14 compares the heat

release for the different feeds. Consistent with the hydrogen

consumption just discussed, the heat release from the Bakken is

significantly lower than that for the other feeds, and the

Bakken/LCO looks similar to the reference SR feed.

As with any crude change, Bakken can present some challenges

depending on the refinery configuration. However, diesel derived

from Bakken crude appears from this analysis, to be similar to

other light sweet crudes in terms of feed characteristics and its

behavior during hydrotreating. If the refiner is prepared for crudes

similar to Bakken, then there should be minimal problems in

processing Bakken crude. There may be opportunities for catalyst

selection to help maximize performance when processing this or

other opportunity crudes. Advanced Refining Technologies LLC®

has the ability to conduct detailed customer-specific pilot plant

testing to provide the refiner the confidence and understanding of

the various options available when considering a catalyst change.

Both the hydrotreating catalyst system and the operating strategy

for the ULSD unit are critical for providing the highest quality

products. Use of tailored catalyst systems can optimize the ULSD

hydrotreater in order to produce higher quality products while

utilizing the greatest flexibility of feedstocks. The complex

relationship between hydrotreater operation and catalyst kinetics

underscores the importance of working with a catalyst technology

supplier that can tailor product offerings for each refiner’s unique

operating conditions. This knowledge enables ART to meet the

refiner’s objectives and maximize revenue.

References1. Rosinski, G., C. Olsen and B. Watkins, “Factors Influencing

ULSD Product Color, Advanced Refining Technologies”;

Catalagram® 105, 2009

2. Watkins, B., Olsen, C., “Custom Catalyst Systems for Higher

Yields of Diesel” AFPM Annual Meeting, Paper AM 13-10

3. Watkins, B., Lansdown, M., “Understanding Cloud Point and

Hydrotreating Relationships” Catalagram® 112, 2012

0 20 40 60 80 100 120 140



160

Clo

ud P

oint

Cha

nge

(Pro

duct

- Fe

ed),

˚F 8.0

6.0

2.0

-2.0

-6.0

-10.0

-12.0

4.0

0.0

-4.0

-8.0

FIGURE 12: Change in Cloud Point of the Various FeedBlends

SR

Sulfur

SR/LCO Bakken Bakken/LCO

Nitrogen Total Aromatics PNA

Estim

ated

Hyd

roge

n C

onsu

mpt

ion,

SC

FB

800

700

500

300

100

600

400

200

0

FIGURE 13: Comparison of Hydrogen Consumption at10 ppm Sulfur

SR

Sulfur

SR/LCO Bakken Bakken/LCO

Nitrogen Total Aromatics PNA

Estim

ated

Hea

t Rel

ease

, BTU

/bbl

45000

35000

15000

5000

25000

10000

0

40000

20000

30000

FIGURE 14: Heat Release at 10 ppm Sulfur

30 Issue No. 114 / 2014

Two Companies Joined to Developa Catalytic Solution for BottomsUpgrading to Diesel in the FCC Unit

William MoralesHipolito RodriguezLuis Javier HoyosTania Chanaga Luis Almanza

Ecopetrol-InstitutoColombiano delPetróleo (ICP)Colombia

Uriel Navarro Larry HuntClemencia MarinHongbo Ma Rick WormsbecherTom Habib


SummaryThe objectives for this project were developed after an in-depth analysis of the local and world situation of

the refining opportunities for diesel production, and of the existing catalyst technologies in the market.

The project’s team considered the following objectives:

1. Develop an FCC catalyst to increase the LCO (light cycle oil) yield by 3 vol.%

2. Increase the Cetane Index (CI) of the LCO by 4 numbers

3. Maximum gasoline loss of 2 vol.%, while maintaining the Octane number.

All of these results were required at constant coke when compared to a base catalyst of adequate zeolite

and matrix surface areas. The catalyst results in one of the commercial FCC units of Ecopetrol in the

Barrancabermeja refinery were:

• Increase of 2.3 vol.% in the LCO yield

• Increase of 3 numbers in the CI

• Decrease of 1.5 vol.% in gasoline yield, while maintaining octane number.

IntroductionThe largest company in Colombia, Ecopetrol, and the world leader of FCC catalysts, Grace, joined their

efforts, talents and resources in a technology innovation project to mitigate the deficit of diesel fuel in

Colombia. Local and global market trends showed that the growth in the demand for diesel is greater

than for gasoline. Several factors were key in developing the project’s objective to maximize LCO

production, such as:

1. The conversion capacity of Ecopetro’s refineries, based upon FCC technology;

2. An increase in crude oil slates that are steadily richer in heavy oils;

3. The absence of specific catalyst solutions to meet the diesel objectives;

4. LCO is an important component in the streams being sent to diesel hydrotreating units.


This article presents the following stages of this joint development

project:

1. The experimental design to obtain the best formulations for

the catalysts

2. Laboratory testing

3. Development of the deactivation and simulation

procedures for equilibrium catalyst (Ecat)

4. Evaluation in the DCR Circulating Riser pilot

plant and the scale-up using a simulation model

5. Commercial evaluation in an FCC unit at Ecopetrol’s

refinery in Barrancabermeja.

In the catalysts design phase, the following factors were

considered: the impact of the type and quantity of the zeolite and

matrix; the concentration of Rare Earths (RE2O3); as well as the

catalyst stability and selectivity in a high contaminant metals’

environment (>10,000 ppm of Ni+V). The best formulations

evaluated in the ACE reactors showed increases of 4.0 wt.% in

LCO yield and nearly 4 numbers of CI. The evaluation of catalysts

in the DCR pilot plant showed an incremental LCO yield of 3.0

wt.% with an improvement in CI of 3 numbers. Recognizing that in

resid cracking the coke selectivity of the catalyst is one of the most

important properties, great efforts were made for its optimization.

The industrial plant scale-up allowed us to corroborate the

excellent coke selectivity of the developed catalyst, and the

simulations performed confirmed the incremental LCO yields and

quality derived from the best formulation. The most important

stage of a catalyst development project is its evaluation in the real

world of a commercial plant. A commercial trial was started in April

2013 maintaining an average of 25% of resid in the feed

throughout the test. The main goal for both companies was to

corroborate the lab and pilot plant results in Ecopetrol’s

commercial unit, as well as to reach the objectives programmed for

the project. These were confirmed. Improved coke selectivity was

also evident in the commercial FCC unit, which provided a better

heat balance and increased operational flexibility.

Experimental DesignThe first step of this project was to identify the catalyst’s

parameters that affect LCO selectivity (distillation range 221-370°C

[430-700°F]) while minimizing any gasoline yield loss. These were:

1. High surface area matrix with good bottoms cracking

selectivity1.

2. Moderate activity to improve LCO conversion while

avoiding excessive LCO cracking.

3. Good coke and gas selectivity in resid cracking (fraction

550°C+[1022°F+]).

Figure 1 shows a diagram of the experimental design for this project.

To select the matrix, 8 different commercial catalysts were

evaluated in a fluidized bed micro-reactor (ACE) unit2. The ACE

unit was run at the following conditions: RxT: 505°C [941°F]; C/O

ratios of 4, 6 and 8; reaction time 30 sec. The variables that will be

optimized are: zeolite content, RE2O3 concentration in the catalyst,

and matrix level. Twenty different catalyst formulations were

prepared. To deactivate fresh catalysts and simulate the Ecat, two

methods were used; Grace CPS-13 method and a method

developed for this project by ICP (called IDM)4,5. To develop this

IDM method, an Ecat sample that contained the selected matrix

was taken from a commercial unit. Then, in the lab, the effect of

operating variables such as residence time, deactivation

temperature and steam flow were determined, until the optimal

conditions were defined that would simulate the physical-chemical

properties, the activity and the selectivity of this Ecat. After the

catalyst deactivation by the IDM method at 12,000 ppm of Ni+V

equivalent, the pilot plant (DCR) studies were run. These studies

were performed at the Colombian Petroleum Institute (ICP)

[Instituto Colombiano de Petróleo] in isothermal conditions5, at RxT

of 525°C [977°F] and C/O ratio between 4 and 17. For coke

optimization it was necessary to optimize the proportion and the

type of V and Ni traps. With the results obtained from the DCR unit,

a scale-up was performed to a commercial unit, using a

commercial model for simulation and optimization. Finally, the

commercial trial was performed in an FCC Orthoflow Unit at the

1 1Matrix

Selection

2Variable

Optimizationsin ACE Unit

3Ecat

Simulation

4DCR StudyOptimum

Formulations

5Coke

Optimization

6Pilot PlantScale-up

7Commercial

Trial

FIGURE 1: Experimental Methodology

32 Issue No. 114 / 2014

Ecopetrol refinery in Barrancabermeja. The feed used by the

laboratory for the entire project is a blend of 70 vol.% VGO

(vacuum gasoil) and 30 vol.% DMO (demetalized oil, obtained in

the DEMEX unit of the Barrancabermeja refinery). This blend has

the following properties: 18.5°API Gravity, 2.5 wt.% sulphur, 2.3

wt.% CCR (Conradson Carbon Residue) and 10 ppm of Ni+V.

Results and DiscussionShown in Figure 2 are the results of the ACE tests (LCO yield as a

function of the conversion) to select the catalyst’s matrix. These

eight (8) catalysts were previously deactivated by the CPS-1

method. This chart shows that catalyst 2 presents higher LCO

performance within a reasonable operational range for an FCC

unit. In addition, it showed the best bottoms conversion and a good

coke selectivity in metals-free testing.

Based on these results, this matrix platform was selected as the

most appropriate to meet the project objectives, and then the other

catalyst variables were optimized. Shown in Figure 3 is the

experimental design of this phase of the project, where the

aforementioned variables were evaluated in the following ranges:

zeolite content (5-30 wt.%), RE2O3 concentration (0-6 wt.%) and

the matrix level (20-40 wt.%). In this three-dimensional chart we

observe that the maximum LCO performance is in the range of 30-

33 wt.% matrix. Based on the different formulations that were

studied, the best catalysts were selected for later studies.

The two best formulations, among the 20 prepared, were used to

study coke selectivity in a high metals environment, where it was

necessary to optimize the V and Ni traps. We also needed to

investigate the effect of the deactivation mode on the coke

selectivity of the FCC catalysts in order to handle resid feedstocks.

We did this because it was observed that the deactivation methods

used had been developed for catalyst technologies designed for

gasoline mode operations. Therefore, ICP developed the IDM

deactivation method to simulate the properties of this type of

catalyst technology to maximize LCO.

Table I shows the activity and coke selectivity results for the two best

catalysts comparing the two different deactivation procedures, ICP

(IDM method) and Grace (CPS method) at constant conversion (50

wt.%). These results allow us to conclude that the IDM method, at

similar metals levels (Ni+V), completely changed the relative activity

and coke selectivity of the two deactivated catalysts. The catalyst

deactivated by the IDM method required lower C/O ratio to reach the

same conversion level with lower coke production. That is, after the

hydrothermal deactivation, these catalysts were more active with

better coke selectivity, since the IDM method produced a better matrix

deactivation (higher Z/M ratio), hence minimizing the catalytic coke

produced in the matrix structure. The higher activity (lower C/O) is

related to the higher zeolite surface area. The better coke selectivity

is related to the lower matrix area and the higher zeolite area, which

means higher zeolite/matrix ratio, as is shown in Table I. This

important result shows once more that all investigations can benefit

from developing its own methods and analytical techniques that allow

for correctly evaluating and studying new catalyst technologies. In this

case, it can be concluded that the IDM method better simulated the

catalyst technologies containing high levels of an active matrix that is

designed to increase bottoms conversion to LCO.

The results obtained in the DCR pilot plant were used to perform

the scale-up to the commercial plant using a proprietary model of

ICP, which is tuned with the commercial plant data. This scale-up

allows us, through information from the pilot plant, to calculate

kinetic parameters that are associated with the catalyst of origin.

Once obtained, these parameters are fed to the simulator to

proceed under optimization mode to find the optimal operational

conditions for the commercial unit. The FCC process model from

LCO

, wt.%

34

32

30


53 57 61 65 69 73 77

28

26

24

22

20

18

1 2 3 4 5 6 7 8

FIGURE 2: LCO Selectivity Defines Test Matrix

Rare Earths Zeolite Content

LCO

Yie

lds,

wt.%

33.5

33

32.5

32

31.5

31

30.5

30

29.5

FIGURE 3: Optimization of Catalyst Formulation


the scale-up of pilot plant data allows us to perform the heat

balance of the commercial unit for each evaluated catalyst.

Additionally we are able to perform optimizations toward specific

products based upon the needs of the refinery, taking into

consideration the operational restrictions of the unit.

Table II shows the scaled-up results. There are two base cases

shown, reflecting that during the project timeline, the base catalyst

was changed as well as the FCC unit where the commercial trial

was performed. The original base case was used to define the

project’s objectives, while the second base case was established

from the FCC unit where the newly developed catalyst was tested.

In these simulations there is a recycle effect, since it was

considered that recycling heavy cycle oil (HCO) was a good

practice for maximizing LCO production. The operating conditions

allow us to conclude that the developed catalyst (ICP-4C) is more

coke selective, since it produces a drop between 7-8°C [12.6-

14.4°F] in the regenerator temperature at constant operating

conditions. The yields reported with ICP-4C allow us to conclude

that there is an increase of 4.3 vol.% in LCO yield compared to the

first base case, and of 2.3 vol.% compared to the second base

case, with an increase in the cetane index of 2.8 numbers. On the

other hand, the decrease in gasoline yield was 1.1 vol.%. These

results allowed us to meet the project�s objectives and to start

preparations for the commercial trial.

The commercial trial in one of the FCC units of Barrancabermeja

refinery started on April 23, 2013. In Table III, we present the main

results from that trial, where the new catalyst (ICP-4C) had an 80%

turnover in the Ecat inventory. The feed during the trial was 77

vol.% of VGO and 23 vol.% of DMO, which was 8% more resid

(DMO) than the respective base case; so it was a slightly heavier,

more refractory feedstock. The obtained yields, compared to the

second base case, allowed us to corroborate that the developed

catalyst maintained the main operating conditions while processing

a slightly heavier feedstock. It was observed that ICP-4C provided

TABLE II: Operating Conditions and Yields for the DCR Pilot Plant Scale-up

Operating Conditions Original Base Case New Base Case ICP-4C

Total Feed Rate, BPD 20.200 20.200 20.200

Recycle of HCO, BPD 1.400 1.600 1.900

Reaction Temperature, ˚C 516 516 516

Feed Preheat Temperature, ˚C 216 216 216

Cat/Oil Ratio 6.3 6.2 6.4

Regenerator Temperature, ˚C 729 728 721

Product Yields

Conversion, vol.% 72.4 70.9 69.0

Dry Gas (H2, C1, C2, C2=, H2S), vol.% 4.76 4.82 4.80

LPG (C3, C3=, C4, C4=), vol.% 26.1 21.8 19.4

Gasoline (C5-221˚C), vol.% 52.7 53.7 52.6

LCO, (221-343˚C), vol.% 18.4 20.4 22.7

HCO, (343-427˚C), vol.% 1.5 1.4 1.5

Bottoms, 427+˚C, vol.% 7.7 7.3 6.7

Coke, wt.% 7.0 7.0 7.2

LCO Cetane Index 20.6 23.4

Cat 1 Grace CPS NCat 1 ICP IDM Cat 2 Grace CPS

Cat 2 ICP IDM

Conversion, wt.% 50 50 50 50

C/O Ratio 7.9 4.6 8.75 5.5

Coke, wt.% 9.0 7.4 9.7 8.3

Zeolite/Matrix Ratio 0.24 0.64 0.15 0.59

Ni, ppm 3669 3896 3558 3363

V, ppm 6190 6500 6300 6400

TABLE I: Effect of the Catalyst Deactivation Procedure on the Catalyst Properties

34 Issue No. 114 / 2014

a significant decrease in the dry gas production. LCO production

was increased by 2.3 vol.% while the cetane index increased by 3

numbers. The decrease in gasoline yield was only 1.5 wt.%.

According to the economic evaluation, the ICP-4C catalyst

operation achieved an economic benefit for the refinery of 0.34

USD/bbl. The most important conclusion of this project was that

the successful strategic alliance of Ecopetrol and Grace to develop

a catalyst provided valuable benefits for both companies, while

achieving the objectives initially set for the project.

References1. Larry Hunt, “Maximize bottoms upgrading with MIDAS”,

Davison Catalagram® 98, 2005.

2. J. C. Kayser, US Patent 6 069 012 - Versatile fluidized bed

reactor, assigned to Kayser Technology, 2000.

3. D. Wallenstein, R.H. Harding, J.R.D. Nee, and L.T. Boock,

Recent advances in the deactivation of FCC catalysts by cyclic

propylene steaming (CPS) in the presence and absence of

contaminant metals. Appl. Catal. A: General 204 (2000): 89-106.

Grace Davison, Guide to Fluid Catalytic Cracking, Part three,

Chapter 11.

4. Luis O. Almanza, “Simulation of FCC equilibrium catalyst age

distribution by using a deactivation model”, Studies in Surface

Science and Catalysis. Vol. 166, 2007. Edited by Dr. M. L. Occelli.

5. Luis O. Almanza, Irreversible deactivation model of the FCC

catalyst, XII Colombian Chemical Engineering Congress,

Manizales, August 2005.

6. Grace Davison, Guide to Fluid Catalytic Cracking, Part one,

Chapter six.

Base Case Evaluation 80% Turnover

Composition (VGO-DMO), vol.% 85-15 77-23

Metals Content (Ni+V), ppm 6.9 8.7

Basic Nitrogen, ppm 569 621

Conradson Carbon Residue, wt.% 1.8 2.0

Sulphur Content, wt.% 1.03 1.09

API Gravity, ÅPI 20.0 18.6

Ecat Ni+V, ppm 9379 9623

Operating Conditions

Total Feed Rate 23000 20000

Reaction Temperature 523 521

Feed Preheat Temperature 200 199

Dense Phase Regenerator Temperature 734 734

Dilute Phase Regenerator Temperature 743 741

Cat/Oil Ratio 7.3 7.4

Fresh Catalyst Addition Rate 2.5 2.7

Product Yields

Dry Gas (H2, H2S, C1, C2, C2=), wt.% 4.46 3.63

Total LPG (C3, C3=, C4, C4=), vol.% 21.03 19.38

Naphtha (C5-221˚C), vol.% 48.53 47.06

LCO, (221-343˚C), vol.% 21.3 23.6

HCO, (343-399˚C), vol.% 7.0 7.5

Slurry (399˚C), vol.% 13.9 15.1

Coke, wt.% 6.4 6.7

Conversion, vol.% 57.8 53.8

LCO Cetane Index 23 26

Net Economical Benefits, USD/bbl +0.34

TABLE III: Yields and Operating Conditions of the Commercial Trial


People on the Move

Bob Gatte has been named Vice Presidentand General Manager, Refining Technologies.

Reporting directly to Bob will be Dennis

Kowalczyk, General Manager Americas; Andre

Lanning, General Manager EMEA; Jim Nee,

General Manager Asia Pacific; Wu-Cheng

Cheng, Director R&D.

Kevin Burton has been promoted to theposition of National Technical Sales Leader,

reporting to Dennis Kowalczyk. In this role,

Kevin will serve as a commercial technical

sales and service team leader in the North

America Refining Technologies business. He

will be the primary contact for key global

refining accounts and will be responsible for strategy development

and implementation within the Western region of North America.

Kevin will continue to be based in California.

Gary Cheng, who joined Grace in January2014 as FCC Technical Service

Representative will report to Kevin.

Refining Technologies EMEA has announced

the following sales/service organization:

Middle East and CIS countries will be led by

Nagib Haidar as General Sales Manager ME& CIS. Vladimir Jegorov and Nathan Ergonul

will continue reporting directly to Nagib in his

new role.

Europe and Africa will be led by Michel Melinas General Sales Manager Europe & Africa. In

this new role, Gilles Bourdillon, Matthias

Scherer and Ivo Peros will report directly to

Michel. Michel will also keep his current role as

Director Technical Service with Stephane

Montmasson continuing to report to Michel as

well. Simon Reitmaier joined this team as Technical Sales Manager

in December 2013.

Kathy Chrien has been named RT GlobalDemand Leader. Prior to her new role, Kathy

held the position of S&OP Leader, Refining

Technologies

Jason Zhou joined Grace in January 2014 as Sales Director,China, based in Shanghai, China

Ljubica Simic has joined Grace as theTechnical Sales and Service Manager, Refining

Technologies (RT). In this role, Ljubica is

responsible for Sales and Technical Service for

RT Catalysts to our current and prospect

customers in Central and Eastern European

countries.

Congratulations to former Catalagram editor,

Tom Habib, on his retirement from Grace with

34 years of service. Tom has served on the

AFPM panel and is the author or co-author of

numerous AFPM and industry technical

presentations.

36 Issue No. 114 / 2014

Meeting Tier 3 Gasoline Sulfur Regulations

Almost one year after first proposing the stricter vehicle emissions standards known as Tier 3, the US

Environmental Protection Agency (EPA) finalized the new regulations on March 3, 20141. Tier 3 requires

the U.S. oil industry to reduce the average sulfur level in gasoline by more than 60 percent, to just 10

parts per million (ppm) in 2017, from the current 30 ppm. Unlike regulations in parts of Europe and

Japan, the U.S. regulations allow for refinery gate sulfur levels as high as 80 ppm so long as the volume

weighted average is maintained at or below 10 ppm.

Based on Tier 2 compliance experience, the EPA projects that an average standard gasoline target,

combined with a higher cap will allow refiners batch-to-batch flexibility while reducing the overall sulfur

level. The EPA also believes that this system will allow refiners to minimize operating costs. Tier 2

experience supports these assumptions. In 2012, under Tier 2, the national gasoline average pool

sulfur was 26.7 ppm, 3.3 ppm below the target of 30 ppm.

Tier 3 continues the Tier 2 credit trading plan, where credits are generated for gasoline produced below

the average target gasoline sulfur. Also, credits accumulated under Tier 2, which have a five year life, can

be carried over for Tier 3 compliance.

At current gasoline sulfur levels, if refiners continue to accrue credits at the current rate until 2017, Tier 3

implementation could potentially be delayed 1 year. By averaging 20 ppm for 2.5 years leading up to

2017, refiners could delay implementation of Tier 3 standards until mid 2019. Adding the 3.3 ppm of

credits accumulated in 2012, 2013, and the first quarter of 2014, refineries could possibly delay

investments in capital to meet Tier 3 compliance until 2020. Also, small volume refineries, representing

approximately 1/3 of U.S. refineries, are exempted from compliance until 2020.

Credit trading is described by the EPA as “robust and fluid”. According to EPA data, 56% of 2012 credits

were transferred intercompany and 44% of 2012 credits were traded intracompany, that is, traded outside

the company where they were generated. Credits allow refiners to delay capital spending, and in some

cases may allow refiners to minimize capital spending.

To meet Tier 3 targets, the EPA predicts that average FCC gasoline sulfur will have to be equal to or

lower than 25 ppm, compared to the current average FCC gasoline sulfur of 80 ppm, assuming that FCC

gasoline represents 36% of the total gasoline pool.

Much of the Tier 3 gasoline sulfur compliance focus is on FCC gasoline. With the exception of the

combined Light Straight Run (LSR) and Natural Gas Liquids (NGL) stream, which currently represents

5.2% of the gasoline pool with a current average sulfur level of 15 ppm, the FCC stream is the only

stream that does not meet the new Tier 3, 30 ppm average sulfur target.

Compliance with Tier 3 regulations will require adjustments to operating strategies and, most likely,

capital investment for new or upgraded equipment. Hardware options available to reduce FCC gasoline

sulfur include FCC feed pre-treatment or gasoline post-treatment.

Brian WatkinsManager,Hydrotreating PilotPlant and TechnicalService Engineer

Advanced Refining TechnologiesChicago, IL, USA

John HaleyDirector,Marketing & BusinessDevelopment

Rosann SchillerMarketing Director,FCC Commercial Strategy



FC

C G

aso

line

Su

lfu

r, p

pm

100,000

10,000

1,000

100

1010 100 1000 10,000 100,000

FCC Feed Sulfur, ppm

FIGURE 1: Relationship between FCC Gasoline Sulfurand FCC Feed Sulfur

FCC Feed Pre-Treatment FCC feed hydrotreating typically lowers FCC feed sulfur by 70-

90%. FCC units running hydrotreated feedstocks produce

gasoline in the range of 200 to 500 ppm. If the hydrotreater is

operated at high severity – high temperature and pressure – the

resulting FCC gasoline sulfur level would typically be in the range

of 75 to 100 ppm. Operating at higher severity requires more

frequent catalyst change outs, increased hydrogen, and increased

maintenance, and, therefore, increased operating cost. And to

meet Tier 3 levels, other changes in the pre-treater operation might

need to be considered.

To address these needs, Advanced Refining Technologies LLC

(ART) utilizes the ApARTTM catalyst system for FCC pre-treatment.

This technology is designed to provide significant increased HDS

conversion while at the same time providing significant upgrading

of FCC feedstock quality and yields. In essence, an ApARTTM

catalyst system is a staged bed of high activity NiMo and CoMo

catalysts where the relative quantities of each catalyst are

optimized to meet individual refiner’s goals and constraints. ART

continues to develop a better understanding of the reactions and

kinetics involved in FCC pre-treating, and through its relationship

with Grace, a detailed understanding of the effects of hydrotreating

on downstream FCC performance.

The hydrotreating catalyst system and the operating strategy for

the pre-treater are critical to providing the highest quality feed for

the FCC.

FCC pre-treating plays an important part in reducing the sulfur

content of FCC products. ART has completed many studies

looking into the effects of hydrotreating on FCC performance and

the quality of the FCC products. This work confirms that increased

severity of the pre-treater operation results in a reduction in FCC

gasoline sulfur.

Figure 1 shows the relationship between FCC feed sulfur and the

resulting sulfur of the FCC gasoline. This presented in Figure 1

was generated using a variety of FCC feeds that had been

hydrotreated over several types of catalysts and catalyst systems.

The results demonstrate good correlation between FCC feed sulfur

and the corresponding FCC gasoline sulfur.

However, increasing the severity of the pre-treater operation to

reduce product sulfur will tend to move the catalyst towards more

of a poly nuclear aromatic (PNA) mode of operation. The PNA

mode of operation, while beneficial to the FCC in many ways, can

shorten the cycle length of the pre-treater catalyst due to the

increased temperatures.

Operating the hydrotreater to remove nitrogen and PNA's improves

FCC product value when targeting gasoline production, but this

needs to be balanced against the increased costs of higher

hydrogen consumption and shorter cycle. Tailored ApARTTM

catalyst systems with 586DX and AT795 optimizes the production

of high quality feeds to the FCC and production of lower sulfur

FCC gasoline, providing additional benefit if the FCC gasoline

sulfur is low enough to be blended directly into the gasoline pool

without additional post treating, or requires less severe post

treating.

Post-Treating FCC GasolineHydrotreating FCC gasoline can have a dramatic, negative effect

on the gasoline octane due to the additional olefin saturation that

occurs when removing the last amount of sulfur. The impact of

gasoline post treatment on gasoline octane is related to the

severity of the post treater operation. In the range of 96-99%

sulfur removal, the impact on octane and hydrogen use is

exponential. The impact on gasoline octane across all

technologies, operated at moderate severity, is approximately

0.8 R+M/2.

Undercutting GasolineThe EPA estimates that 22% of FCC gasoline was undercut to

distillate in 2009 and expects that to increase to 68% by 2018.

With much of the FCC gasoline sulfur concentrated in the high

boiling point tail, undercutting can significantly lower gasoline

sulfur. The EPA predicts that if the naphtha swing cut is fully cut

into the distillate pool, that FCC gasoline volume could be reduced

by 16%, and that FCC gasoline sulfur could be reduced by 50%.

However, the EPA believes that market forces will drive

undercutting gasoline to diesel, as diesel demand increases amid

decreasing gasoline demand.

38 Issue No. 114 / 2014

FCC Catalytic Gasoline SulfurReductionRefiners around the world have demonstrated that use of gasoline

sulfur reduction catalysts and additives is a cost-effective

component of their clean fuels strategy.

Grace GSR® technologies: D-PriSM®, SuRCA®, and GSR® 5, are

the result of almost two decades of innovation. Grace’s gasoline

sulfur reduction products have been used in over 100 FCC

applications worldwide to provide 20%-40% sulfur reduction in

FCC naphtha, including applications in Japan and Europe, where

gasoline sulfur is already regulated to a 10 ppm cap.

With much of Tier 3 compliance focused on the high sulfur FCC

gasoline stream, in-unit reduction of FCC gasoline sulfur with

Grace’s patented gasoline sulfur reduction technologies creates a

variety of opportunities and options for refiners to drive profitability

while meeting Tier 3 gasoline requirements.

Grace’s clean fuels solutions create economic advantages around

feedstock blending and asset optimization to:

• Preserve octane

• Maximize throughput

• Extend pre-treatment and/or post-treatment hydrotreater life

• Provide more flexible gasoline stream blending options

• Provide operating flexibility during hydrotreater outages

• Generate gasoline sulfur ABT credits to defer capital

investment

The benefits of in-unit catalytic FCC gasoline sulfur reduction are

specific to the refinery’s configuration, yield targets, and financial

goals. However, some examples can be drawn from current

applications.

Commercial Application of GraceFCC Gasoline Sulfur ReductionTechnologies In the mid 2000’s, Japan committed to lower gasoline sulfur. As

early adopters of more stringent gasoline quality regulations,

Japanese refiners faced similar challenges that US refiners face

today in meeting Tier 3. Since 2005, Japanese refiners have

successfully utilized Grace’s gasoline sulfur reduction products to

maintain compliance and meet the 10 ppmw gasoline

specifications2.

Most refiners in Japan have elected to heavily hydrotreat FCC

feedstocks and therefore base gasoline sulfur levels are extremely

low by worldwide standards. The sulfur content of FCC gasoline

blended into the gasoline pool typically must be 15 ppm or less, but

varies with each refinery.

Most refiners in Japan have also elected to install FCC gasoline

hydrotreaters and have taken steps to modify FCC feed properties

to meet the stricter gasoline sulfur limits.

The sulfur content of hydrotreated FCC feed is typically in the

range of 700 ppm to 3000 ppm. The severity of the hydrotreating

operation needed to achieve these levels limits the life of the

hydrotreating catalyst to 1-2 years.

SIMDIST Gasoline T99, ˚F

Gas

olin

e Su

lfur/F

eed

Sulfu

r, %

1.0%

1.2%

1.4%

1.6%

1.8%

2.0%

2.2%

2.4%

2.6%

2.8%

3.0%

410 415 420 425 430 435 440 445 450 455 460

SuRCA® Reduced Gasoline SulfurSelectivity by 40% at ConstantGasoline Cut Point

Base SuRCA®

FIGURE 2: SuRCA® Performance at Japanese Refiner


The use of SuRCA® in the FCC unit reduces gasoline sulfur levels

by 20-40 percent. By using SuRCA®, FCC feed sulfur could be

increased and the refiner would achieve the same FCC gasoline

product sulfur as was produced on the lower sulfur feed.

Increasing FCC feed sulfur accomplished by reducing the severity

of the upstream FCC feed hydrotreater will extend the life of the

FCC feed hydrotreater catalyst.

SuRCA® catalyst technology can also be used to reduce the

severity of FCC gasoline hydrotreaters. Lower sulfur in the feed to

the gasoline hydrotreater allows lower severity operation to

achieve a given product sulfur level. Lower severity has the

benefit of reducing octane loss across the gasoline hydrotreater.

Other benefits of FCC gasoline sulfur reduction technology include

the potential to increase cut point (T90) of the FCC gasoline,

which increases gasoline yield. Some refiners in Japan are also

hydrotreating only a portion of the FCC gasoline stream and using

SuRCA® catalyst to optimize overall refinery production of low

sulfur gasoline.

Case Study: Japanese Refiner(Ongoing User)This FCC unit processes 100% hydrotreated VGO feed. The unit

charge rate is 40,000 barrels per day and it is operated in full burn.

Using SuRCA, the refinery realized a 40% reduction of HCCG

(gasoline) sulfur at constant feed sulfur. The ratio of gasoline

sulfur to feed sulfur at constant gasolineT99 is shown in Figure 2.

SuRCA was applied over a base Grace catalyst. No shifts in

product selectivities or gasoline octane were observed. Yields and

selectivities of any SuRCA catalyst can be adjusted through

reformulation of the catalyst.

This refiner continues to use SuRCA today to allow them to either

blend high sulfur coker gasoline into their gasoline pool or extend

the catalyst life of their FCC feed VGO hydrotreater.

D-PriSM® GSR® 5 SuRCA®

Sulfur Reduction Range 20%-30% 20%-35% 20%-40%

Operating Mode Full or Partial Burn Full Burn Full Burn

Usage Rates (% of Inventory) 10%-15% 25% 100%

ConclusionsGrace’s multiple product offerings allow for a truly custom clean

fuels solution for your refinery’s Tier 3 compliance plan. Grace’s

current range of FCC gasoline sulfur reduction products is shown

in Table I.

In challenging environments like Japan, where gasoline sulfur

specifications are more severe than the new U.S. Tier 3

regulations, refiners use Grace products to realize 20-40%

reductions in gasoline sulfur, and provide feedstock and operating

flexibility. With the new Tier 3 regulations in the U.S., Grace’s

gasoline sulfur reduction products can also be used to generate

credits to optimize investment options. Additionally, ART, Grace’s

JV with Chevron, provides a full slate of FCC feed pretreatment

products to optimize product sulfur levels and yields.

Ask your Grace representative which solution is best for your

operation.

References1. Assessment and Standards Division, Office of Transportation

and Air Quality, U.S. Environmental Protection Agency, “Control of

Air Pollution from Motor Vehicles: Tier 3 Motor Vehicle Emission

and Fuel Standards Final Rule, Regulatory Impact Analysis”,

Washington, D.C., U.S.A., March 2014.

2. L. Blanchard, T. Oishi, B. Teo, J. Haley, "SuRCA® Catalyst

Reduces Gasoline Sulfur at Three Japanese Refineries",

Catalagram® 98, 2005.

TABLE I: Grace GSR® Family of Products

40 Issue No. 114 / 2014

Members of the Refining Technologies (RT) team welcomed 29 Oman Oil Refineries and Petroleum Industries Company

(Orpic) employees to Grace's fourth Orpic RFCC Technology Seminar February 11-13, 2014 at the Crowne Plaza, Sohar

Conference Centre in Oman. Orpic is a valued Grace customer and the highly interactive program was supported by Orpic

senior management.

The event was lead by senior members of Grace's RT EMEA team including Michel Melin, General Sales Manager and

Director of Technical Service; Stefan Brandt, Director R&D; Nathan Ergonul, Technical Services and Sales Manager, Middle

East; and Talal AI-Rawahi, Technical Service Manager, Middle East.

Attendees were provided with a comprehensive training program and presentations about the fundamentals of FCC

technology, as well as the most recent advances in FCC catalyst and additive technology. Some topics discussed included

the chemistry of FCC, heat balance, unit monitoring and optimization, pressure balance, resid processing, and an extensive

session on troubleshooting. The final session included an informal quiz to reinforce the learning experience, and was

concluded with a certification ceremony.

Orpic, which is owned by the government of the Sultanate of Oman and by Oman Oil Company SAOC, is one of Oman's

largest companies and is one of the most rapidly growing businesses in the Middle East's oil industry. It has refineries at

Sohar and Muscat, as well as aromatics and polypropylene production plants in Sohar.

The RT team periodically provides technical programs such as this around the world to customers and others in the industry.

Refining Technologies Team Holds Tech Seminar for Orpic

Advanced Refining Technologies 7500 Grace Drive Columbia, MD 21044 USA+1.410.531.4000

www.artcatalysts.com

Global leader in hydroprocessing catalysts offering the complete range of catalysts and services

[email protected] www.e-catalysts.com

GRACE®, MIDAS®, CATALAGRAM®, D-Prism®, GSR®, G-CON®, OLEFINSMAX®, OLEFINSULTRA® and SuRCA® are trademarks, registered in the United States and/or other countries, of W. R. Grace & Co.-Conn.

ACHIEVE™ and DCR™ are trademarks of W.R. Grace & Co.-Conn.

ART®, and Advanced Refining Technologies® are trademarks, registered in the United States and/or other countries by Advanced Refining Technologies, LLC. ApART™ and 545DX™ are trademarks of Advanced Refining Technologies, LLC.

Chevron Lummus Global™ is a trademark of Chevron Intellectual Property, LLC.ACE™ is a trademark of Kayser Technology. This trademark list has been compiled using available published information as of the publication date of this brochure and may not accurately reflect current trademark ownership or status. GRACE CATALYSTS TECHNOLOGIES is a business segment of W. R. Grace & Co.-Conn., which now include all product lines formerly sold under the GRACE DAVISON brand.

© Copyright 2014 W.R. Grace & Co.-Conn. All rights reserved.

The information presented herein is derived from our testing and experience. It is offered, free of charge, for your consideration,investigation and verification. Since operating conditions vary significantly, and since they are not under our control, we disclaim any and all warranties on the results which might be obtained from the use of our products. You should make no assumption that all safety or environmental protection measures are indicated or that other measures may not be required.

catalagram - w. r. grace and company · provides details on cracking these feedstocks and the...

Documents