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

Transcription

1 2014 OLI SIMULATION CONFERENCE SESSION 4 CORROSION - TECHNICAL PRESENTATION OCT 22 ND 2014 Lowering Column Tops Temperature to Improve Product Yields, While Avoiding Penalty due to Salting & Corrosion Use this area for cover image (height 6.5cm, width 8cm) Ricardo J. Prieto-Irizarry & Ashok K. Dewan Shell Global Solutions (US) Inc.

2 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 and ). These factors also should be considered by the reader. Each forward-looking statement speaks only as of the date of this presentation, Oct 22, 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 , available on the SEC website You can also obtain this form from the SEC by calling SEC Oct 22,

3 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,

4 CRUDE UNIT FAILURES HAPPEN BECAUSE. Because Underlying Causes Hazard Crude Tower Safe Operating Procedures (CT-SOPs) Corrosion Inhibition Controls Design/Metallurgy Controls Process T,P,x,y Controls Crude Quality / Quantity Controls Basic Risk Factors Excessive Leak Unsafe acts (or: Immediate causes ) cause holes in our controls RESTRICTED Oct 22,

5 RISK FACTORS THAT TRIGGER CRUDE TOWER FAILURES Basic Risk Factors (BRF): Steam Wash Crude Desalt Slops Lab Design Basic Risk Factors HardWare TPxy Maint Mgt Amine Design : Hot/Cold Drums Capacity, Incorrect Injection Points HardWare : Incompatible Metallurgy, Vibrations, Shock Condensations Maint. Mgt : Equipment Inspections Amine : Inhibitor (F,N) Programs TPxy : Column T, P x, y Profiles Lab : Laboratory Analyses (onsite) Desalt : Desalter Efficiency Wash : Wash Water Quality, Stripped Sour Water Quality(CN- scavenged by Ammonium Poly-Sulfide in SWS) Steam : Steam Quality Crude : Crude Quality/Opportunity Slops : Tramp Corrodents (spikes) Oct 22,

6 CORROSION CONTROL FOR CRUDE TOWERS Pros: Inexpensive and very effective for Atm OH (~order of magnitude drop in OH Cl-) Notes lb NaOH / Mbbl Prefer 2.5-5%w (4-7.7 Be ) for better mixing Cons: Converts Cl to NaCl which goes to heavy oil units Reduce precursors: Inject dilute caustic Notes 1 stage 90% salt removal 2 stages 98% Notes Must inject enough WW to ensure % of the water stays in the liquid phase Dilute the corrosives: Water Washing Pros: Reduces need for chemicals Cons: Sour water handling Water removal from product and reflux Reduce precursors: Good desalting Pros: Reduces corrosion potential everywhere downstream Reduces chemical costs Cons: Capital cost Some electrical cost Water/brine volumes

7 CRUDE TOWER OVERHEAD & BOTTOMS CORROSION Aqueous Corrosion caused primarily by Amine Hydrochloride Salts, Carboxylic Acids, H2S, CO2, SOx 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 Naphthenic Acid Corrosion and Sulphidic Corrosion, influenced by Crude Blend TAN Oct 22,

8 REFINERY CORROSION CHEMISTRIES Explained by Multiple Chemical reactions Not simple Equilibria Fe (s) Fe (s) H Fe H ( aq) ( aq) 2( g ) Fe + + (s) HCl( aq) Fe( aq) + H 2( g ) + 2Cl ( aq) Fe + 2 = + H 2S ( aq) Fe( aq) + H 2( g ) + S ( aq) + 2 (aq) Fe + 2 (aq) + 2Cl( aq) FeCl 2( aq) + S = FeS ( aq) ( s) (Sulphide Layer protects from Blistering) FeS Film Destabilization by Cyanide Complexing Fe + 2 (aq) CN Fe ( CN ) ( aq ) 6 ( aq (Prussian Blue precursor) ) Cyanide Scavenging by APS (NH 4 SCN ) 2 S5( aq) + CN ( aq) ( NH 4 ) 2 S 4 ( aq) + ( aq) (Cyanide converted to thiocyanate) Oct 22,

9 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 Oct 22,

10 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. Oct 22,

11 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 Sulphur Mercaptans Thiols Carboxylic Acids Naphthenic acids (TAN) Naphthenates

12 METHODS TO INHIBIT CORROSION IN REFINERY CRUDE TOWERS, 1 OF 2 Reduce precursors to corrosives Good Desalting and Caustic Injection: MgCl NaOH Mg ( OH ) 2NaCl CaCl NaOH Ca( OH) 2NaCl Rough rule of thumb: Ten pounds of salt produces about one pound of Hydrogen Chloride Oct 22,

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 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 Alloy Steels versus Carbon Steel 13 Oct 22, 2014

14 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 point Oct 22,

15 OVERHEAD CORROSION CONTROL BEST PRACTICES, 1 OF 3 Filmer and Neutralizer must be stable (i.e., not decompose) below F (important for Crude Towers) Choice of Filming Inhibitor and Neutralizer amine must 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 > , do not inject in refinery streams > 230 F (APS can become insoluble/break down to elemental sulfur) Oct 22,

16 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 Oct 22,

17 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. Oct 22,

18 SHOCK CONDENSATION IN HOT DRUM EXCHANGERS VIBRATION FAILURES IN HOT DRUM EXCHANGERS: Caused by Water Hammer Caused by Very High Velocity Flow RESTRICTED Oct 22,

19 DATA ANALYSES QUALITY CONTROL Open Cup Ambient ph versus Closed Cup ph at Lab Conditions ph Profile at Varying MORPHOLINE Injections ph 5 Cold Drum (112 F, 21.7 psia) Closed Cup (72 F, 115 psia) MORPHOLINE Injection (gal/day) Note: Significant degassing can occur for Hot Drum Samples- Differences in ph are even greater. Oct 22,

20 Lowering Column Tops Temperature to Improve Mid- Distillate Yields, While Avoiding Salting & Corrosion CASE STUDY Use this area for cover image (height 6.5cm, width 8cm)

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

22 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. Oct 22,

23 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 Oct 22,

24 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 Oct 22,

25 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. Oct 22,

26 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. Oct 22,

27 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. Oct 22,

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