1 mobil oil corporation - beaumont refinery pip progress review - management review ref: 4000321...

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MOBIL OIL CORPORATION - Beaumont Refinery

PIP PROGRESS REVIEW - Management Review

Ref: 4000321

March 3, 1998

MOBIL OIL CORPORATIONMOBIL OIL CORPORATIONBeaumont RefineryBeaumont Refinery

PROFIT IMPROVEMENT PROGRAMPROFIT IMPROVEMENT PROGRAMManagement ReviewManagement Review

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Ref: 4000321

March 3, 1998

Today’s AgendaToday’s Agenda

PIP Status

Opportunity development update Reformer and Aromatics Gasoline Blending Udex Hydrocracker Coker FCC Other

What’s next

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March 3, 1998

PIP StatusPIP Status

9 months into PIP program

Many opportunities screened Technical feasibility; Preliminary economics Reviewed with operations Actions taken on many operational opportunities

PETROfine refinery simulation Validated versus base month Refinery-wide economics to be determined

Especially stream management items Anticipate additional ideas will surface

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Ref: 4000321

March 3, 1998

Reformers/AromaticsReformers/Aromatics

Overview: Major drivers:

Benzene sales Octane-barrels

Undersized reformate splitter and UDEX result in blending of about 5 TBD of aromatics concentrate

Some improvements made PTR-4 rate and yields likely to increase

Some PTR-4 aromatics capacity “wasted” 10-20% C9+ in feed High IC6 content in feed Some recycle of PTR-3 products

Potential for additional xylene recovery Low-capital options for Afrac Economics currently poor

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March 3, 1998

Reformate Splitter OptionsReformate Splitter Options

Current Hardware & Specs Limit Benzene Production C7 IP spec in bottoms to MTPX requires high reboiler duty Increasing reflux to reduce toluene in overhead floods tower High concentrations of toluene in overhead (aromatics concentrate)

takes up UDEX capacity

Add Tower Capacity Refinery investigating use of out-of-service UDEX xylene tower Requires about one mile of piping and condenser/exchanger

replacements

Increase Depentanizer Pressure Results in higher splitter feed temperature Improves fractionation at constant tray loading Requires 400# steam to depent reboiler $1.2MM/yr potential

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March 3, 1998

Reformate Splitter (2)Reformate Splitter (2)

Modify Splitter Configuration Move feed tray up and replace 10 trays with 4-pass Improves fractionation Requires minor capital and tower shutdown/bypass $3.0MM/yr potential

Bypass Portion of Splitter Feed to Blending Unloads tower and allows improved fractionation Run down bypassed stream with aromatics concentrate to keep

benzene segregated for gasoline blending Bypass enough to reduce aromatics concentrate blending to zero Net result is improved benzene/toluene separation

+720 BPD benzene from UDEX (constant aromatics charge) Up to $3.0MM/yr potential if 5 TBD aromatics concentrate going to

blending Requires short jump-over ($50k rough cost)

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March 3, 1998

PTR-3PTR-3

Improve PTR-3 Debutanizer Fractionation Tower was losing C6+ in overhead during G-season (high unit rates) Resulted in recycle of PTR-3 C6+ to PTR-4 feed Current operation shows improvement even at high rates Profit improvement of $0.7MM/yr+

PTR3 Debutanizer Overhead Quality

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March 3, 1998

PTR-3 (2)PTR-3 (2)

Improve Stripper Fractionation/Control Stripper overhead LPG production has varied between zero and 2 TBD

Some feed quality variation Reflux on flow control; top temperature ranges between 150-250oF No LPG GC sample taken; performance test showed 35% C6+

C6+ in stripper overhead is reprocessed C5’s pretreated again at Isom; C6+ pretreated again at PTR-4

PTR-3 pretreater often limits reformer charge C6+ lost to stripper overhead is lost PTR-3 charge rate ($3/bbl)

Assuming roughly 1 TBD of C6+ in LPG can be charged to PTR-3 reformer, incentive is $0.7MM/yr

Recommend improved control/monitoring: Put reflux on top temperature control (done) Begin sampling stripper LPG; target <5% C6+

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March 3, 1998

PTR-3 (3)PTR-3 (3)

PTR3 Stripper Overhead Control

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March 3, 1998

PTR-4PTR-4

Process CHD-2 Naphtha CHD-2 naphtha has normally been processed in PTR-3

High C5/C6 content results in high LPG yields 15% of feed (750 BPD) to stripper LPG; takes up pretreater

capacity 25% of feed to debut overhead; aggravates debut flooding High nitrogen content (20 ppm) fouls debut trays and overhead

Processing in PTR-4 appears to make more sense Allows additional PTR-3 feed at constant pretreater capacity Reduces PTR-3 reformate benzene content

Accounts for 20% of benzene in full-range reformate Recently a blending constraint for RFG

PTR-4 debut has a water-draw tray to allow on-line washing for salts Refinery has implemented

All CHD-2 naphtha now going to PTR-4 Incentive of $0.4MM/yr +

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March 3, 1998

PTR-4 (2)PTR-4 (2)

Purchase Amoco Whiting Light Naphtha for PTR-4 Higher benzene yield than typical light naphtha

30% C6 N+A (Mobil Isom C6+ has 12%) <10% C7 N+A

Ideal PTR-4/UDEX feed for benzene production Term arrangement may be possible Reformate of this naphtha may also be available for UDEX feed

Segregated processing on Amoco reformer 32% Benzene, 8% Toluene (minimum) Typical UDEX Feed: 29% Benzene, 21% Toluene

KBC to evaluate incentives

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March 3, 1998

IsomIsom

Route Wharf Natural Gasoline to CUA Depentanizer Incentive exists to increase natural gasoline purchases

NC5 upgraded to IC5 at Isom C6+ upgraded to aromatics/reformate at PTR-4

Volume of purchases currently limited by Isom pretreater capacity Capital project under development by Mobil to repipe depentanizer

upstream of pretreater Alternative is to process natural gasoline at CUA depent

C6+ portion (40%) goes direct to PTR-4 pretreater C5- portion (60%) goes to GP5E/Isom

Some concern with GP5E depropanizer loading CUA depentanizer currently underutilized

Max 50% of tower flood now Roughly 1500 ft of 4” piping needed (about $150k capital) Ballpark incentive of $1.5MM/yr (+2.0 TBD natural gasoline

purchases during G-season)

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March 3, 1998

Aromatics FractionationAromatics Fractionation

Relocate Xylene Tower Feed Tray Xylene tower (“#1 debut”) bottoms typically contains >40% mixed

xylenes Feed point is currently too high in the tower for optimum operation

More trays between feed and overhead xylene product required Increased xylene purity at constant flow Increased xylene product at constant purity

Moving feed point from tray 17 to tray 11 increases xylene potential >300 BPD increase Nozzles exist on every tower tray Current incentive only $120k/yr with current economics

Should consider if xylene price improves An additional 1-2 TBD of xylene recovery from C9+ is possible

More reboiler and condenser duties needed “Uniflux” trays may need replacement with valve or high-capacity

trays

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March 3, 1998

Aromatics Fractionation (2)Aromatics Fractionation (2)

Produce “Crystal Clear” Reformate from Afrac Afrac xylene tower can be operated to make 30 Saybolt C8/C9+

Trial performed by Mobil to confirm Stock could be sold to Amoco during G-season for water-white

premium production May also be valuable to Mobil to reduce endpoint blending problems

Maximize xylene tower overhead while controlling FBP Minimize bottoms (high FBP)

Segregate to blending pool Route to FCC fractionator? Blend as jet or diesel?

Requires further evaluation

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March 3, 1998

Gasoline BlendingGasoline Blending

Increase RFG Sales PETROfine blending studies show incentive to increase RFG

production Up to $1MM/yr/TBD RFG increase Raffinate and MTBE for incremental RFG volume available Similar results to Mobil back-casts RFG production currently constrained by marketing

Increasing export volume also has favorable economics Price is close to incremental conventional Specs are not as tight (RVP, benzene) Opportunity to push sulfur & benzene to limits

RFG constraints/opportunities still under study

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March 3, 1998

Gasoline Blending (2)Gasoline Blending (2)

Many Gulf Coast refiners make more RFG than Mobil

% RFG TBDRFG

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% RFG TBDRFG

MobilRefinery ARefinery B

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March 3, 1998

UdexUdex

Strong economic drivers $ ~7 /bbl Benzene recovery; $ ~2 /bbl Toluene recovery Extract rate limited; Trading purity and recovery for more capacity

Serious corrosion problems due to chlorides from reformate Solvent regeneration helps; carbon beds not very effective Upstream water washing would minimize chlorides

Simulation confirms unit bottlenecks Stripper flooding in bottom section; Flash drum vapor overloaded

Debottleneck by reducing solvent flow Unloads stripper and flash drum; reduces energy

Simulation shows potential of 10% more capacity $ ~4 MM/yr Preliminary plan for test being review this week

Process highly integrated Sensitive to changes; slow to reach steady-state Path to new operation difficult but achievable

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March 3, 1998

HydrocrackerHydrocracker

Major economic drivers Improve yield selectivity

Increase LN and HN yield Reduce LPG yield

Improve fractionation Recover benzene processors to LN Recover HN/Kero from recycle oil (2nd stage feed)

Reduce catalyst deactivation; extend catalyst life

Process simulation model enhanced Rigorous tray-to-tray fractionation integrated with reactor models

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March 3, 1998

Hydrocracker (2)Hydrocracker (2)

Optimize second stage conversion - In Progress Maximize recycle feed to 2nd stage to minimize temperatures

Lower reactor temperatures, higher recycle rate improves selectivity

Increased LN and HN production Decreased light ends production benefits stabilizer fractionation

Hydrogen demand decreases with less light ends production Benefits

Increased high value product yields ( R3 - 5 F ) $ 2.2 million/yr Based on incremental gasoline value Aromatics recovery upgrade determined by downstream units

Decreased total hydrogen demand ( 67 SCFB ) Decreased purchase naphtha requirements

Costs Increased utilities at higher recycle rates; Reboilers limiting

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March 3, 1998

Hydrocracker (3) Hydrocracker (3)

Reduced Rx Temperature and Increased Recycle Rate

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Butane Gasoline Lt Naphtha HyNaphtha Kero Diesel

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March 3, 1998


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Constant RCOIncreased RCO

Dist TBD 1.1 1.1 0.4 0.4RCO TBD 29 33 29 35 R3 T Base -5 +2 -5

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March 3, 1998


Recover C6+ from gasoline stream - In Progress Stabilizer/splitter simulation confirms plant experience

Flooding in top of stabilizer with high light ends production Gasoline stream maximized to keep C5s out of splitter Poor fractionation below gasoline draw; dry trays Reboilers limiting for stabilizer and splitter

Improved fractionation from optimizing conversion Decreased light ends yield Gasoline pumparound could help control

Benefits Recover C6+ from gasoline (50% of C6+) $~2.0 million/yr Decreased purchase naphtha requirements (2-4TBD)

Notes Product upgrade based on incremental gasoline Potential aromatics recovery determined downstream

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March 3, 1998


Improved Stabilizer FractionationVolume % C6+ in Gasoline Stream

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~2 TBD benzene-rich C6+ recovered to PTR-4 feed

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March 3, 1998


Process 142 Extract vs. ALGO 142 Extract ( 2.78 TBD ) has extremely high hydrogen consumption

Additional 55 SCFB hydrogen on total feed 2 F Reactor temperature increase to maintain conversion 2 F Diligent PNA monitoring of recycle a must Benefits

Increased product yields vs ALGO $ 4.5 million / yr Improved FCC feed quality Decreased LCO production Increased FCC capacity

Costs Increased hydrogen consumption (at fuel cost) $ 1.4 million / yr. Catalyst deactivation ( -2 month run length) $ 0.2 million / yr. Facilities to segregate 142 extract to HDC

Worth further investigation

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March 3, 1998


Increase 1st stage recycle gas purity Purge recycle gas; increase make-up

Increased H2 partial pressure increases conversion and reduces catalyst deactivation

Purge rate high due to low purity make-up H2 ( 91.8%) One percent increase in recycle gas purity worth $ 700 / day in yields

Can increase now with higher purity hydrogen (94%) Benefits for 3 % increase in recycle gas purity

Increased conversion and yields $ .75 million/yr. Decrease catalyst deactivation $ .25 million/yr.

Costs Facilities to treat high H2S purge gas Same H2S Purge 0.43 MMSCFH ; Make up 0.5 MMSCFH Fuel vs. Fuel Operation of third make up compressor

Energy ( 3000 HP x $ 15,000/100 HP) $ .50 million/yr. Maintenance cost over cycle $ .25 million/yr.

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March 3, 1998


Hydrocracker Recycle H2 Purity and Purge

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First Stage Recycle Gas Purity % H2

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March 3, 1998


Increased splitter reboiler firing - In Progress Reboilers limiting HN removal from recycle Firing limit relaxed Product upgrade $ 90 /day less $ 50 /day fuel cost per 1 MMBTU/Hr

Benefits Increased splitter reboiler environmental limit and firing

(55 - 64 MMBTU/Hr ) $ 0.29 million/yr. Costs

Increased utilities $ 0.16 million/yr. Investigate heater options to increase duty

May be able to get duty from waste heat

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March 3, 1998

Hydrocracker - SummaryHydrocracker - Summary

Opportunity Status / Comments Net Value

($ million/yr.)

Second Stage Conversion In progress $ 2.2 +

Recover C6+ from Gasoline In progress ( 50% ) $ 2.0 +

Correct feed metering Implemented $ 1.0 - $ 2.0

Process 142 Extract at HDC Facilities Required $ 1.0 - $ 2.9

First Stage Recycle Purity Facilities Required $ 0.25 +

Increase Splitter Reboiler Firing In progress $ 0.13 +

Total $ 6.5 - $ 9.4

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March 3, 1998

Coker OpportunitiesCoker Opportunities

Warm Tar Circulation Line

Recirculates resid from tankage through CUB fin fan using current FCCU CSO line

Benefits Reduces cold tar production Postpones the need for a hot feed tank Reduces Hydrocracker feed from Coker Cutter fed to heaters is reduced from 1700 BPD to 1000 BPD

Economic Incentive Approximately $3 MM/year

Increases resid feed capacity by 600 BPD Reduces degradation of CUB kerosene by 2300 BPD

Postpones spending capital for a hot feed tank

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March 3, 1998

WARM-UP LINE CONFIGURATIONWARM-UP LINE CONFIGURATION

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March 3, 1998

Coker Opportunities (2)Coker Opportunities (2)

Controlled Recycle (with Warm Tar Circulation Line in service)

Flow Scheme Hot Feed is fed to Preflash Tower bottoms Cold Feed is fed to the top of the Preflash Tower for stripping of cutter Hot feed and stripped cold feed are fed to heaters

Benefits Debottlenecks heaters Cutter fed to heaters is reduced from 1000 BPD to 50 BPD More stable heater charge Longer heater run lengths between decokings are expected

Center radiant section used to preheat feed to approximately 716oF 10% reduction in radiant heat flux Maximum tubewall temperature lower by 15oF

Economic Incentive $6 - $7 MM/year due to increasing resid feed capacity by 2200 BPD

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March 3, 1998

WARM-UP LINE CONFIGURATIONWARM-UP LINE CONFIGURATION

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March 3, 1998

PREFLASH WITH NEW FURNACE PUMPPREFLASH WITH NEW FURNACE PUMP

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March 3, 1998

FURNACE CONFIGURATIONFURNACE CONFIGURATION

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March 3, 1998

TOWER AND PREFLASHTOWER AND PREFLASH

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March 3, 1998

FCC ALGO Test RunFCC ALGO Test Run

Purpose Evaluate yield change when average FCCU feed replaced with CUB

ALGO

Unit Mass Balance 94.4-96.8% after meter corrections Feed rate reduced for each case to 100% weight balance, 4-6 TBD

Note: Unit charge meter indicating 4 TBD rate after shutdown Balance includes Inerts from regenerator

FCCU charge rate, ~73 TBD; replaced 10 TBD

CUB ALGO Properties Pour Point +35 F Watson K 11.8 vs. 11.6 for Average FCC Feed

Cetane Index 50 Paraffinic Feed

API 32.8-33.0

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March 3, 1998

FCC ALGO Test Run (2)FCC ALGO Test Run (2)

Tests criteria Constant feed rate Constant riser top temperature Constant CO2/CO ratio Adjust feed preheat and/or air to regenerator Limited on upper and lower preheat temperature

Test Sequence Base Add LAGO, hold preheat temperature constant Constant Coke - Lower preheat temperature Constant Cat to Oil - Increase preheat temperature Return to Base Feed Rate plus 5 TBD of LAGO Return to Base Feed Rate, Base Conditions

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March 3, 1998

FCC Test Run ResultsFCC Test Run Results

Base Incremental ALGOConst C/O Const Coke LP Yields

C2- wt% 5.0 3.5 4.0C3= LV% 9.1 11.1 11.4 12.8C3 LV% 3.7 4.5 7.1 5.3IC4 LV% 6.6 9.2 14.8 10.4NC4 LV% 2.1 2.6 4.2 3.0C4= LV% 9.5 6.5 7.7 14.1C5-430 Gaso LV% 50.0 49.7 53.9 57.1LCO LV% 17.0 19.6 15.1 11.1CSO LV% 9.3 5.5 -2.7 -4.2

Coke wt% 7.2 2.3 6.5 7.2

Conversion LV% 73.7 74.9 87.6 93.1

Prod Value Summer $/bbl 24.36 25.56 25.70 Winter $/bbl 24.30 25.43 25.16 Delta to base Summer $/bbl 1.20 Winter $/bbl 1.13

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March 3, 1998

FCC Test Run Results (2)FCC Test Run Results (2)

Summer WinterC2- FOEB 11.46 14.58C3= 28.28 28.69C3 14.90 16.69IC4 18.27 19.90NC4 17.33 18.24IC4= 27.66 26.96C4= 17.61 13.67C5-430 Gaso 24.73 23.71LCO 21.98 23.49CSO 12.93 13.99

Pricing Basis:

Optimum ALGO disposition to be confirmed with refinery PETROfine simulation

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March 3, 1998

GP5W Propylene RecoveryGP5W Propylene Recovery

Current operation is to use reformate and LLO Simulation results

Increasing the sponge oil (reformate) rate recovers more C3+ material then increasing the LLO rate.

Reformate more effective sponge oil than FCC Gasoline Better recovery of C4+ molecules

Increasing Sponge Oil /LLO Rate will increase C3+ Recovery 1997 Depropanizer limits

Feed max. rate of 35 TBD Column maximum differential pressure

Worth $1.5 MM/yr during May and Third Quarter Optimum sponge oil and LLO rates depends on GP5W feed rates

Reduction in HP liquid and vapors from FCC require less sponge oil rate for high C3 recovery

Evident during last part of 1997 fourth quarter

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March 3, 1998

GP5W Propylene Recovery (2)GP5W Propylene Recovery (2)

GP5WEST DEPROPANIZER FEED/DP

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March 3, 1998

Increase Stripping of AHGO

Implemented shortly after November review

~ 500 bbl/day of Naphtha and Kero recovered Consumes capacity in FCC/Hydrocracker

Over 100 F improvement in IBP $200-300,000/yr @ $ 1-2+/bbl upgrade from FCC feed

Operations review/troubleshooting- first week of March Entrainment in AHGO

Test run being planned for March Vacuum resid cut point

Reduced slop to CUB Economics to be quantified

Crude Unit BCrude Unit B

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March 3, 1998

Lubes OpportunitiesLubes Opportunities

Opportunities Previously Presented: Reduce VI/Pour Point Giveaway Produce 6160 Raffinate at DuoSol with Modified FCC Mode

D/W Model Indicates Incentives for Shifting Diln Solv to Cold Wash Ketone-2 Analyzed Using Base Month Data -- 141, 142, 311 Operations Constant Total Solvent Circulation Assumed Shift 0.2-0.4 V/V Solvent from Dilution to Cold Wash

Increase Lean Filtrate Recycle to Maintain Wash Acceptance DWO Yields Improve by ~0.7-1.4 LV%

Shifts Oil from Soft Wax to DWO Product Worth 230-410 k$/yr, Based on Yield Credits Alone

Reflects DWO vs. Soft Wax at $9.56/B -- May be Higher Excludes Throughput Credits due to Reduced Soft Wax

Recovery Loading Increasing Lean Filtrate Recycle Increases Refrigeration Load

Credits Reflect 10% Discount on top of 90% Service Factor

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March 3, 1998

Lubes Opportunities -- What’s NextLubes Opportunities -- What’s Next

Complete Ketone Unit Solvent Optimization Studies

Continue Review of Selected MRTC-BMT Proposals for Hardware/Operational Improvements

Optimize/Standardize Ketone D/W Filter Hot Wash Procedures

Investigate Alternatives for Debottlenecking Ketone-2 Soft Wax Recovery

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March 3, 1998

Other Areas Being EvaluatedOther Areas Being Evaluated

Potential alkylate or raffinate sales

FCCU gasoline/LCO swing cut to hydrocracker vs. diesel blending during D-season

RFG blending strategy Overshooting conventional toxics limit during G-season and reducing

to make annual average during D-season

Diesel blending options HDC premium distillate as CARB diesel

MTBE conversion/catalyst activity

Utility systems

Heater limitations

Etc.

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Ref: 4000321

March 3, 1998

Beaumont - Major OpportunitiesBeaumont - Major OpportunitiesPotential

Description $MM/yr Status / CommentsIn Progress/Implemented

Optimize hydrocracker conversion 2+ Improve yield selectivityCorrect hydrocracker feed metering 1-2 Plus feed at RV limitRecover C6+ from HDC gaso 2+ Recover Bzn precursors to PTR4PTR4 Ref Splitter fractionation 1+ Increased benzenePTR3 Debut operation 0.7 Increases benzenePTR3 Stripper top temp control 0.7 Reduces C6+ lossCHD2 naphtha to PTR4 0.4 Reduces PTR3 BznIncrease HDC splitter reboiler firing 0.1Maximize GP5W lean oil rate 1-2 Increases C3= recoveryCustody transfer accounting 4-5** Hull transfers correctedCUB AHGO steam stripping 0.2-0.3 Recovers naphtha/kero

Operational - Recommended Udex operational improvements 2-4 Increased aromatics capacityIncrease RFG production 1 Marketing limitsKetone-2 Solvent Strategy 0.2-0.4+ Improved DWO yield

** One-time credit, procedures corrected

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March 3, 1998

Beaumont - Major Opportunities (2)Beaumont - Major Opportunities (2)Potential

Description $MM/yr Status / CommentsModifications Required PTR4 Debut btms bypass to gaso ~3 Requires jump-over

Modify Reformate splitter configuration ~3 Move feed trayIncrease PTR4 Depent pressure 1.2 Requires 400# steam to reboilerRoute Nat Gaso to CUA Depent 1.5 Requires pipingBypass Splitter feed to blending up to 3.0 Increases Bzn in Udex feed142 Extract to hydrocracker 1-3 Under evaluationIncrease HDC recycle purity 0.3 Yields/Reduced catalyst deactDebottleneck FCCU feed circuit 1+ Increases feed capacityProcess coker slop in coker 0.8-1.0 Project initiatedWarm tar circulation for Coker feed 3+ Postpones hot VTB tankCoker controlled recycle 6-7 Low cost heater debottleneck Optimize cutters for #6 oil blending 1.7Requires piping

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Ref: 4000321

March 3, 1998

SummarySummary

Opportunities identified total ~$ 40-48MM/yr $ 16-22 MM/yr immediate potential $ 13-16 MM/year partially or fully implemented

What’s Next Continued opportunity development

Refinery-wide economics Support implementation New ideas

Furnace/Heater operations review - this week Rotating equipment review - early April Utilities systems analysis Opportunity review - early May Potential of continuing support

Opportunities implementation - Scope to be discussed Measurement survey Maintenance and reliability program Refinery strategy studies using PETROfine site-wide simulation

1 mobil oil corporation - beaumont refinery pip progress review - management review ref: 4000321...

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