FINAL - Lowering Column Tops Temperature to Improve

2014 OLI SIMULATION CONFERENCESESSION 4 – CORROSION - TECHNICAL PRESENTATIONOCT 22ND 2014

Lowering Column Tops Temperature to Improve

Product Yields, While Avoiding Penalty due to Salting

& Corrosion

Ricardo J. Prieto-Irizarry & Ashok K. Dewan

Shell Global Solutions (US) Inc.

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DEFINITIONS & CAUTIONARY NOTE

Reserves: Our use of the term “reserves” in this presentation means SEC proved oil and gas reserves.

Resources: Our use of the term “resources” in this presentation includes quantities of oil and gas not yet classified as SEC proved oil and gas reserves. Resources are consistent with the Society of Petroleum Engineers 2P and 2C definitions.

Organic: Our use of the term Organic includes SEC proved oil and gas reserves excluding changes resulting from acquisitions, divestments and year-average pricing impact.

Resources plays: our use of the term ‘resources plays’ refers to tight, shale and coal bed methane oil and gas acreage.

The companies in which Royal Dutch Shell plc directly and indirectly owns investments are separate entities. In this presentation “Shell”, “Shell group” and “Royal Dutch Shell” are sometimes used for convenience where references are made to Royal Dutch Shell plc and its subsidiaries in general. Likewise, the words “we”, “us” and “our” are also used to refer to subsidiaries in general or to those who work for them. These expressions are also used where no useful purpose is served by identifying the particular company or companies. ‘‘Subsidiaries’’, “Shell subsidiaries” and “Shell companies” as used in this presentation refer to companies in which Royal Dutch Shell either directly or indirectly has control, by having either a majority of the voting rights or the right to exercise a controlling influence. The companies in which Shell has significant influence but not control are referred to as “associated companies” or “associates” and companies in which Shell has joint control are referred to as “jointly controlled entities”. In this presentation, associates and jointly controlled entities are also referred to as “equity-accounted investments”. The term “Shell interest” is used for convenience to indicate the direct and/or indirect ownership interest held by Shell in a venture, partnership or company, after exclusion of all third-party interest.

This presentation contains forward-looking statements concerning the financial condition, results of operations and businesses of Royal Dutch Shell. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements are statements of future expectations that are based on management’s current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. Forward-looking statements include, among other things, statements concerning the potential exposure of Royal Dutch Shell to market risks and statements expressing management’s expectations, beliefs, estimates, forecasts, projections and assumptions. These forward-looking statements are identified by their use of terms and phrases such as ‘‘anticipate’’, ‘‘believe’’, ‘‘could’’, ‘‘estimate’’, ‘‘expect’’, ‘‘intend’’, ‘‘may’’, ‘‘plan’’, ‘‘objectives’’, ‘‘outlook’’, ‘‘probably’’, ‘‘project’’, ‘‘will’’, ‘‘seek’’, ‘‘target’’, ‘‘risks’’, ‘‘goals’’, ‘‘should’’ and similar terms and phrases. There are a number of factors that could affect the future operations of Royal Dutch Shell and could cause those results to differ materially from those expressed in the forward-looking statements included in this presentation, including (without limitation): (a) price fluctuations in crude oil and natural gas; (b) changes in demand for Shell’s products; (c) currency fluctuations; (d) drilling and production results; (e) reserves estimates; (f) loss of market share and industry competition; (g) environmental and physical risks; (h) risks associated with the identification of suitable potential acquisition properties and targets, and successful negotiation and completion of such transactions; (i) the risk of doing business in developing countries and countries subject to international sanctions; (j) legislative, fiscal and regulatory developments including potential litigation and regulatory measures as a result of climate changes; (k) economic and financial market conditions in various countries and regions; (l) political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities, delays or advancements in the approval of projects and delays in the reimbursement for shared costs; and (m) changes in trading conditions. All forward-looking statements contained in this presentation are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Readers should not place undue reliance on forward-looking statements. Additional factors that may affect future results are contained in Royal Dutch Shell’s 20-F for the year ended 31 December, 2013 (available at www.shell.com/investor and www.sec.gov ). These factors also should be considered by the reader. Each forward-looking statement speaks only as of the date of this presentation, Oct 22, 2014. Neither Royal Dutch Shell nor any of its subsidiaries undertake any obligation to publicly update or revise any forward-looking statement as a result of new information, future events or other information. In light of these risks, results could differ materially from those stated, implied or inferred from the forward-looking statements contained in this presentation. There can be no assurance that dividend payments will match or exceed those set out in this presentation in the future, or that they will be made at all.

We use certain terms in this presentation, such as discovery potential, that the United States Securities and Exchange Commission (SEC) guidelines strictly prohibit us from including in filings with the SEC. U.S. Investors are urged to consider closely the disclosure in our Form 20-F, File No 1-32575, available on the SEC website www.sec.gov. You can also obtain this form from the SEC by calling 1-800-SEC-0330.

Oct 22, 2014 2Copyright of Shell Global Solutions (US) Inc.

TABLE OF CONTENTS

Lowering Column Tops Temperature to Improve Product Yields, While Avoiding Penalty due to Salting & Corrosion � Introduction

� Typical Refinery Crude Tower Operation & Zones of Salting & Corrosion

� Improving Profitability Through Opportunity Crudes Selection

� Managing Risks for High Temperature Corrosion in Crude Tower Bottoms

� Managing Salting & Corrosion Risks in Crude Tower Tops

� Lowering Crude Tower Tops Temperature to Maximize Mid-Distillates (Kerosene, Diesel, Gas Oil) – Case Study

� Conclusions

Oct 22, 2014Copyright of Shell Global Solutions (US) Inc.

3

RESTRICTED

Hazard

CRUDE UNIT FAILURES HAPPEN BECAUSE ….

Corrosion InhibitionControls

Design/MetallurgyControls

Process T,P,x,yControls

Crude Quality/ QuantityControls

ExcessiveLeak

Basic Risk

Factors

Unsafe “acts”

(or: ‘Immediate

causes’) cause holes

in our controls

Underlying CausesBecause…

Oct 22, 2014 4

Crude Tower Safe Operating Procedures (CT-SOPs)

Copyright of Shell Global Solutions (US) Inc.

RISK FACTORS THAT TRIGGER CRUDE TOWER FAILURES

Oct 22, 2014 5

DesignDesign

HardWareHardWare

MaintMgtMaintMgt

Amine Amine

TPxyTPxyLabLab

DesaltDesalt

SlopsSlops

CrudeCrude

SteamSteam

WashWash

Design : Hot/Cold Drums Capacity, Incorrect Injection PointsHardWare : Incompatible Metallurgy,Vibrations, Shock CondensationsMaint. Mgt : Equipment Inspections Amine : Inhibitor (F,N) ProgramsTPxy : Column T, P x, y ProfilesLab : Laboratory Analyses (onsite)Desalt : Desalter EfficiencyWash : Wash Water Quality, Stripped Sour Water Quality(CN- scavenged by Ammonium Poly-Sulfide in SWS)Steam : Steam QualityCrude : Crude Quality/OpportunitySlops : Tramp Corrodents (spikes)

Basic Risk Factors (BRF):


Basic Risk Factors

CORROSION CONTROL FOR CRUDE TOWERS

Reduce precursors:Good desalting

Reduce precursors:Inject dilute caustic

Dilute the corrosives: Water Washing

Pros:•Reduces corrosion potential everywhere downstream•Reduces chemical costs

Pros:•Inexpensive and very effective for Atm OH (~order of magnitude drop in OH Cl-)

Pros:•Reduces need for chemicalsCons:•Sour water handling•Water removal from product and reflux

Notes• 0.3-4 lb NaOH / Mbbl• Prefer 2.5-5%w (4-7.7°Be’) for better mixing

Notes• 1 stage 90% salt removal• 2 stages 98%

Notes• Must inject enough WW to ensure 25-50+% of the water stays in the liquid phase

Cons:•Capital cost•Some electrical cost•Water/brine volumes

Cons:•Converts Cl to NaClwhich goes to heavy oil units


Oct 22, 2014 7

CRUDE TOWER OVERHEAD & BOTTOMS CORROSION


Aqueous Corrosion caused primarily by Amine Hydrochloride Salts, Carboxylic Acids, H2S, CO2, SOx

Naphthenic Acid Corrosion and Sulphidic Corrosion, influenced by Crude Blend TAN

Other Corrosion Mechanisms may also affect Crude Towers such as Under Insulation Corrosion, where corrodents may get trapped near the metal surface, Sheer-induced Corrosion, Incompatible Metallurgy, Vibrations, Shock Condensations, etc.

SOURCES:

Acids With Crude from Acid Stimulations, Wash Water, Refinery Slops, Steam , Oxygen from Sour Water Stripper Water

REFINERY CORROSION CHEMISTRIES

)(2

2

)()(2

gaqaq(s)HFeHFe +→+

++

−+

++→+)()(2

2

)()(22

aqgaqaq(s)ClHFeHClFe

=+

++→+)()(2

2

)()(2

aqgaqaq(s)SHFeSHFe

)()(

saq

2

(aq)FeSSFe →+

=+

Explained by Multiple Chemical reactions – Not simple Equilibria

−−

+→+)()(424)()(52

)()

aqaqaqaq4SCNSNHCNS(NH

)(

4

6)()(6

aqaq

2

(aq)CNFeCNFe

−−+

→+

Cyanide Scavenging by APS

FeS Film Destabilization by Cyanide Complexing (Prussian Blue precursor)

(Sulphide Layer protects from Blistering)

(Cyanide converted to thiocyanate)

)(2)(2

aqaq

2

(aq) FeClClFe →+−+


8

INCREASING PROFITS FROM OPPORTUNITY CRUDES

� Increases mid-distillate (Kerosene, Diesel, Gas Oil) yield and quantity.

� Converts High Sulfur Fuel Oil (HSFO) into Kerosene& Diesel.

� Boosts Propylene production.

� Mitigates Fouling and Corrosion (F&C) Op Expenses

� Reduces Carbon Footprint Operating Expenses (GHG Emissions reduction).

� Less dependence on volatile Middle East supplies, more domestic reserves in North America, meet tighter emission regulations.

MARGIN = F(Mid-Distillate Profit, HSFO Reduction, Propylene Profit) –G(F&C OPEX Reduction, GHG Emissions OPEX Reduction)

OPPORTUNITY CRUDES: Heavy Sour Crudes, Oil Sands / Bitumen, Oil Shale,Extra Heavy Oils, High TAN crudes, Biofuels, Unconventionals


9

SELECTING OPPORTUNITY CRUDES – RISK BASED APPROACH� Propensity for Naphthenic Acid Corrosion (NAC) and High-Temperature Sulphidic Corrosion, at temperatures above 400 deg. F

� Impact on Desalter Performance

� Increased Fouling

� Shortened hydrotreater run lengths

� Value / Price of available crude feed stocks, based upon margins to refinery for various fractions

� Wt % Sulfur limits of various crude fractions, not Total wt% Sulfur. Limits are based upon: Refinery product specifications, sulfur handling capacity of proprietary gas-treating amines, sulphur plant on-site, etc.

�Wt % Sulfur Limits in crude fractions depends upon: equipment metallurgy, process operating conditions, proprietary software to estimate corrosion rates, equipment life/condition, replacement cost, etc.

12

3


10

MANAGING RISKS FOR HIGH TEMPERATURE SULPHIDATION CORROSION & NAPHTHENIC ACID CORROSION

At Crude Tower Bottoms, Risks are managed through proper metallurgy, crude

selection, and Process Conditions.

Expected Corrodents:

� Organic sulphur compounds Acid Gases (H2S, CO2)Elemental SulphurMercaptansThiols

� Carboxylic AcidsNaphthenic acids (TAN)Naphthenates


METHODS TO INHIBIT CORROSION IN REFINERY CRUDE TOWERS , 1 OF 2

Reduce precursors to corrosives

Good Desalting and Caustic Injection:

NaClOHCaNaOHCl Ca 2)(2

22 +→+∆

NaClOHMgNaOHMgCl 2)(2 22 +→+∆

Rough rule of thumb:Ten pounds of “salt” produces about one pound of Hydrogen Chloride


12

13

METHODS TO INHIBIT CORROSION IN REFINERY CRUDE TOWERS, 2 OF 2

Dilute the Corrosives

Water Washing

Neutralize the Corrosives

Adjust pH with neutralizer amines or ammonia

Upgrade the Metallurgy

Alloy Steels versus Carbon Steel

NEUTRALIZER AMINES:

� NH3 : Ammonia

� DMEA : Di Methyl Ethanol Amine

� MEA : Mono Ethanol Amine

� MORP : Morpholine

� MMA : Mono Methyl Amine

� MOPA : Methoxy Propyl Amine

� EDA : Ethylene Diamine


FILMING & NEUTRALIZING AMINES FILMING AMINE:

� Form a barrier between the metal and the corrosive environment

� Adsorb onto the metal at the metal-liquid interface

� Generally are oil soluble and water dispersible

� Commonly used at a 2 –15 ppm level

� Injected into the overhead line: via an atomizing quill, or with a slotted quill, after

dilution in a slipstream

� Should be cautiously mixed with: Aqueous Ammonia solutions or neutralizing

amines, especially water based ones

� Films are unstable at low pH conditions

Note: Filming Amines contain the corrosion inhibitor, surfactants (demulsifier, defoamer,

dispersant) and carrier solvent (water, alcohol, aromatic or aliphatic HC)

NEUTRALIZING AMINE:

� Increase pH of Aqueous Dew Point - colligative properties effect

� Precipitate as dry hydrochloride salts, above aqueous dew pointOct 22, 2014

Copyright of Shell Global Solutions (US) Inc.14

OVERHEAD CORROSION CONTROL BEST PRACTICES, 1 OF 3� Filmer and Neutralizer must be stable (i.e., not decompose) below 300 0F (important for Crude Towers)

� Choice of Filming Inhibitor and Neutralizer aminemust be compatible with each other (important for several refinery units)

� Carrier fluids (e.g., water, alcohol, aromatic or aliphatic HC) should not react with the choice of filming/neutralizer chemicals – e.g., dissociation in water is O.K., but hydrolysis reactions forming alcohols is not O.K.

� Presence of surfactants in the filming inhibitor can cause downstream problems in columns, pump-around, etc. due to emulsified water

� For effective APS treating (Sour Water Stripper), keep pH > 8.0-8.5, do not inject in refinery streams > 230°F (APS can become insoluble/break down to elemental sulfur)


15

OVERHEAD CORROSION CONTROL BEST PRACTICES, 2 OF 3

� Use HC-soluble neutralizer amine, if practical, over water-based amine

� Should injection be neat or with carrier? Slip naphtha stream works best. For water-based amine, use atomized steam to disperse neutralizing amine in small droplets

� Should neutralizing amine be injected before filming amine? * Raise pH with neutralizer amine and then apply filmer amine* Do not recommend mixing filming amine and neutralizing amine in

common injection point

� Should the injection be done using a spray nozzle or quill? * Spray nozzle gives good dispersion but can plug. Also must have enough

pressure drop over the spray nozzle* Check strainers, pumps, flow meters, check valves to ensure that the amine

is not injected in pulses……….HCl comes into the overhead continuously


16

OVERHEAD CORROSION CONTROL BEST PRACTICES, 3 OF 3� Filmer and Neutralizer Additions must be closely monitored:

* Neutralizer Amine added on demand to meet hot/cold drum pH targets* Only “fit for purpose” dosages used; excess amines can cause issues

� Oxygen incursions from Water Wash & Sour Water Stripper Water should be minimized.

� Desalter Efficiency is Key Performance Index (KPI):* 90% efficiency for single stage desalting* 98% efficiency for 2-stage desalting

� Recycle only Hot Reflux to Crude Tower; Avoid recycling Cold Reflux.

� Hot Reflux Temp should be greater than the Aqueous Dew Point Temp.

� No Amines added to Hot Reflux to Crude Tower; slip stream may be used as carrier fluid to other parts of the crude overhead system.


17

RESTRICTED

SHOCK CONDENSATION IN HOT DRUM EXCHANGERS

VIBRATION FAILURES IN HOT DRUM EXCHANGERS:Caused by Water HammerCaused by Very High Velocity Flow

Oct 22, 2014Copyright of Shell Global Solutions (US) Inc.18

DATA ANALYSES QUALITY CONTROL –

pH Profile at Varying MORPHOLINE Injections

4

4.5

5

5.5

6

6.5

0 20 40 60 80 100 120 140

MORPHOLINE Injection (gal/day)

pH

Cold Drum (112 F, 21.7 psia)

Closed Cup (72 F, 115 psia)

Open Cup Ambient pH versus Closed Cup pH at Lab Conditions

Note: Significant degassing can occur for Hot Drum Samples- Differences in pH are even greater.


19

Lowering Column Tops Temperature to Improve Mid-

Distillate Yields, While Avoiding Salting & Corrosion

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CASE STUDY

Crude Tower Overhead With Hot & Cold Drums, with Ensure Safe Production (ESP) Column Tops Temperature of 300 deg F

CASE STUDY

OPPORTUNITY TO IMPROVE MARGIN

� Market Conditions favor production of mid-distillates (kerosene,

diesel) as compared to Naphtha.

� Opportunity to reduce naphtha make and increase mid-distillate

make, if the overhead temperature can be reduced from 300 (ESP

Limit) deg F to 290 deg F.

� The size of the prize is approximately 1-2 M$/deg F, per annum.

� Premise for Case Study is that crude feed to Crude Tower is

unchanged, identical corrosion inhibition program is being practised

in the Overhead system, and salting plus corrosion in overhead

system is safely managed.


BACKGROUND: METALLURGY & CORROSION INHIBITION

� Overhead line is Carbon steel with nominal corrosion allowance (1/8”)

� Prior to the first condensers, there is NO water wash, with dew point pH controlled via an amine corrosion inhibitor

� Overhead condensers are alloyed; downstream of OVHD condensers, the effluent piping is alloyed, but process equipment is carbon steel

� There is evidence of “entrainment” or carryover in Hot Drum Off-gas line, currently protected via water wash recycle from Cold Drum SW and neutralizer amine injection

� For this study, the aqueous dew point is ~261 deg F (Shell ionic model)

� Corrosion concerns (for 10 deg.F drop in column overhead) is due to: � Potential of Amine Hydrochloride (wet or dry) salt formation. � Acidic Water Dew Point


IMPACT OF A 10 DEG F DROP IN COLUMN OVERHEAD

Impact of a 10 Deg F drop in column overhead:

� 25% reduction in Hot Drum Sour Water make

� Increased HC Reflux - Aqueous Dew Point reduced due to increased HC Loading at Column Overhead (~255 deg F)

� Increase in relative Hot Drum SW Chloride level by 15 ppmw

� Increase in Amine Hydrochloride salting temperatures (3-5 deg F)

� MEA Hydrochloride salting is the “at risk” scenario that must be managed; MEA is NOT the neutralizer of choice but part of slops and crude acid treatment


MANAGING RISK: LOWER COLUMN OVERHEAD TEMP.

� For Lower Column Overhead Temperature operation, adjust Caustic Feed in Desalter, to maintain Chlorides in Hot Drum, below a threshold

� For Hot Drum Chlorides above threshold, MEA swings in Hot Drum, or caustic feed/pump issues: Raise Column Overhead temperature, based upon Chlorides and MEA levels in Hot Drum Water

� In case of increasing cold drum and brine water pH, with decreasing neutralizer demand, suspect “tramp” amine contamination

� When planning to process crudes which are suspected to have MEA contamination, target higher column overhead temperature

� If feasible, reduce charge rate of contaminated crudes

� Inspect overhead line at regular time intervals.


SUMMARY OF FINDINGS, 1 OF 2

� Study showed feasible operation at the 290 deg F overhead temperature operation. That is, the column tops can be cooled without jeopardy.

� Both Hot and Cold drum sour water compositions utilized for estimation of NH4Cl salt points, in this case study (deviation from using only Hot Drum Chloride & neutralizer levels to set guideline for ESP NH4Cl and Amine Hydrochloride Salting Criteria).

� Based upon this case study and currently observed sour water NH3 and neutralizer levels, the chloride levels could be set slightly higher than the original ESP limit.

� Current salt threat was not due to NH4Cl, or neutralizer amine hydrochloride salt, but due to presence of MEA from slop stream, steam and/or carried in by the crude.


SUMMARY OF FINDINGS, 2 OF 2

� MEA / MEA-triazine contamination should be avoided.

� ESP Hot Drum sour water Chloride level still applicable under current sour water make. However cooler tower tops makes less water in Hot Drum, hence relative composition can be slightly higher.

� Risk Mitigation strategies should be utilized to increase overhead temperature upon high chlorides (>ESP Limit) or MEA contamination.

� MEA Hot Drum Sour Water content should be monitored daily as part of analytical protcol.

� Hot Drum Sour Water Make expected to decrease by ~25% from current levels at Lower Tops Temperature (10 Deg F), while Cold Drum Sour Water make will increase by a similar amount.


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FINAL - Lowering Column Tops Temperature to Improve