SCOT ULTRA: The Next Generation SCOT Application to Existing Assets - - PowerPoint PPT Presentation

Shell Global Solutions International B.V.

SCOT ULTRA: The Next Generation SCOT

Application to Existing Assets

Gary Bowerbank Manager Gas Processing Technology, Shell Global Solutions

1 October 2017

4th Annual Middle East Sulphur Plant Operations Network Abu Dhabi, 15-17 October 2017

Michael Turley Process Engineer, Gas Processing, Shell Global Solutions

Shell Global Solutions International B.V.

Definitions & cautionary note

October 2017 2 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 (SPE) 2P + 2C definitions. Resources and potential: Our use of the term “resources and potential” are consistent with SPE 2P + 2C + 2U 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. Shales: Our use of the term ‘shales’ 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 legal 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 over which Royal Dutch Shell plc either directly or indirectly has control. Entities and unincorporated arrangements over which Shell has joint control are generally referred to as “joint ventures” and “joint operations” respectively. Entities over which Shell has significant influence but neither control nor joint control are referred to as “associates”. 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

• f 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’’, ‘‘goals’’, ‘‘intend’’, ‘‘may’’, ‘‘objectives’’, ‘‘outlook’’, ‘‘plan’’, ‘‘probably’’, ‘‘project’’, ‘‘risks’’, “schedule”, ‘‘seek’’, ‘‘should’’, ‘‘target’’, ‘‘will’’ 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

• f doing business in developing countries and countries subject to international sanctions; (j) legislative, fiscal and regulatory developments including regulatory measures addressing

climate change; (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. There can be no assurance that future dividend payments will match or exceed previous dividend payments. 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 risk factors that may affect future results are contained in Royal Dutch Shell’s 20-F for the year ended December 31, 2015 (available at www.shell.com/investor and www.sec.gov ). These risk factors also expressly qualify all forward looking statements contained in this presentation and should be considered by the reader. Each forward-looking statement speaks only as

• f the date of this presentation, October 2017. Neither Royal Dutch Shell plc 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. With respect to operating costs synergies indicated, such savings and efficiencies in procurement spend include economies of scale, specification standardisation and operating efficiencies across operating, capital and raw material cost areas. We may have used certain terms, such as resources, in this presentation that United States Securities and Exchange Commission (SEC) strictly prohibits us from including in our 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.

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Agenda

• 1. Drivers for a Tail Gas Treatment Unit (TGTU) Catalyst & Solvent Swap
• 2. The Swap: Process & Practical Considerations
• 3. Relevant Aspects to Catalyst and Solvent Swap
• 4. What Shell Can Provide - The Next Generation TGT: SCOT ULTRA
• 5. Possible Additional Benefits
• 6. Case Studies
• 7. Experience
• 8. Conclusions

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Drivers for a Tail Gas Treatment Unit (TGTU) Catalyst & Solvent Swap

1

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• 1. Drivers for a TGTU Catalyst & Solvent Swap

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A “lower for longer” climate A clear market trend to focus

• n maximising the profitability
• f existing assets, through

increased focus on

• perations and selective

investment in smaller scale Brownfield projects. TGTU swaps are small scale Brownfield projects with minimal or no capital investment OPERABILITY PROFITABILITY CAPACITY OPEX SULPHUR EMISSIONS 2017 Onwards

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Middle East Opportunities

Existing Amine based TGTUs

 Saudi Arabia

5

 UAE

14

 Bahrain

3

 Oman

3

 Kuwait

8

 Qatar

20 Notes

 Excluding projects in development  Non-exhaustive list, likely to be more

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Lebanon Syria Israel Jordan Iraq Kuwait Iran Bahrain Qatar Saudi Arabia Egypt U.A.E. Oman Yemen

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The Swap: Process & Practical Considerations

2

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Reboiler turndown? If the reboiler specific duty is reduced, sufficient reflux must still be maintained to ensure regenerator stability

• 2. Process Considerations

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Solvent flow turndown? Reduced circulation risks tray weeping

• r loss of down-comer sealing (trays)
• r dry sections (packing)

Turndown of in-direct or direct heater? Too much turndown decreases dP and velocity across burner. The resulting reduced flame lift may damage the burner Does the reboiler have sufficient surface area? Solvents with higher boiling points will require more area to provide the sensible heating

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• 2. Practical Considerations

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Part of the TGTU Swap Management of Change

“On the run” or “offline” On-site storage

• f new and

existing solvents and water wash Reconfiguration

• f flow and level

instruments due to new solvent properties Logistics for cleaning the unit New heat and material balance resulting from change in column temperature profile and solvent Update of site hazard register and chemical safety datasheets Disposal of existing catalyst and solvent Update of

• perating

manuals and

• perator

training Risk assessments Shutdown planning

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Relevant Aspects to Catalyst and Solvent Swaps

3

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• 3. Relevant Aspects to Catalyst and Solvent Swaps

11 October 2017

Efficient Execution

• A. Feasibility Study
• 2. Implementation

Review of materials of construction and instrument calibration

• B. Update of site

specific procedures

• C. Other key checks
• 1. Preparation

Updated H&MB, Hazard Register (Safety Datasheets) and operating guidelines Adequacy checks (tray hydraulics, exchanger & pump capacity, turndown) Effluent disposal, storage and supply of new solvent Update of operating manuals Cleaning procedures Detailed solvent analysis (potential reuse)

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• 3. Relevant Aspects to Catalyst and Solvent Swaps

12 October 2017

Efficient Execution

• A. Logistics
• 2. Implementation

Procurement, supply and storage of new solvent

• B. Supervision and

monitoring of the process

• C. Long term support
• 1. Preparation

Disposal of effluent Operator and Technology Provider Sampling and testing of the solvent and gases Test-run to demonstrate performance Monitoring and routine checks to assure that new process being operated at optimum conditions

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What Shell Can Provide The Next Generation TGTU: SCOT ULTRA

4

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• 4. The Next Generation TGTU: SCOT ULTRA

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GENERIC AMINE TGTU SCOT ULTRA

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• 4. The Next Generation TGTU: SCOT ULTRA

 Improved hydrolysis and hydrogenation

activity

 Delivers significantly higher performance

than previous generation LT catalysts for CO, COS and CS2 conversion at lower temperature Maintains 3.2-mm trilobal shape:

 Low loading density (relatively lower reactor

fill costs)

 Low pressure drop characteristics

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Greater destruction of organic sulphur compounds Criterion 834: Low-temperature TGT catalyst

Source: Shell Analysis

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• 4. The Next Generation TGTU: SCOT ULTRA

16

GENERIC AMINE TAIL GAS TREATING UNIT SCOT ULTRA

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Reduced flame temperature Low levels of CO2 slip High amount of CO2 recycled to SRU

✓

Flame temperature at or above target

✓

Deeper H2S removal

✓

High levels of CO2 slip

✓

Lower SO2 emissions

✓

Lower steam consumption

✓

High COS conversion Relatively high utility costs Chilling required in the Middle East

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Potential Additional Benefits

5

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• 5. Potential Additional Benefits

 Air demand imbalance can increase

SCOT H2S by multiples

 Lower capacity solvents are more

likely to slip H2S during a spike event

 JEFFTREAT ULTRA solvent resists

H2S spikes of 3x normal concentrations

 Environmental impact of SRU air

demand fluctuations is minimised

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Solvent is resilient in handling H2S spikes compared with MDEA (H2S spikes up to x3)

Source: Shell Analysis

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• 5. Potential Additional Benefits

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• JEFFTREAT ULTRA requires:
• No wash trays/ section
• No chilling package

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Solvent has been de-risked and its operability is proven

Deployed in commercial gas plant with ~2 year continuous operation

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Reduced solvent degradation Reduced foaming Comparable corrosion rates

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Case Studies

6

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• 7. Case Study 1: Converting to SCOT ULTRA

Unlocking Value from TGTU

100% 89% 83%

0% 20% 40% 60% 80% 100% 120%

Formulated MDEA no Cooling Formulated MDEA with Cooling SCOT ULTRA no Cooling

Relative CAPEX 100% 102% 50%

0% 20% 40% 60% 80% 100% 120%

Formulated MDEA no Cooling Formulated MDEA with Cooling SCOT ULTRA no Cooling

Relative OPEX 100% 82% 66%

0% 20% 40% 60% 80% 100% 120%

Formulated MDEA no Cooling Formulated MDEA with Cooling SCOT ULTRA no Cooling

Relative Solvent Circulation 100% 93% 71%

0% 20% 40% 60% 80% 100% 120%

Formulated MDEA no Cooling Formulated MDEA with Cooling SCOT ULTRA no Cooling

Relative Life Cycle Costs  Location: EMEA  Refinery

 Scope: TGTU

 Basis

 SRU capacity = 1 x 220 MTPD  Cooling: 42°C  No-Cooling: 60°C  TGTU absorber feed gas  2.5 mol% H2S,  0.8 mol% CO2  SO2 emissions target = 500

mg/Nm3; absorber treated gas H2S = 200 ppmv

 Case Study Economics

 LP steam: 3.6$/ton  HP steam: 5.8$/ton  Cooling: 0.05$/m3  Power: 0.035$/kWh  Plant life = 25 years

Source: Shell Analysis

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• 7. Case Study 2: A refinery had operability issues owing to low reaction

furnace temperatures



Target flame temperature for ammonia (NH3) destruction = 1,250°C



Actual flame temperature for NH3 destruction (SRU 7) ~1,150–1,170°C



SRU 7 has come down multiple times recently through ammonium salt deposition



SCOT recycle has an enormous quenching effect on the flame temperature



High quantities of CO2 recycle have previously been observed in test runs

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SRU 2 SRU 3 SRU 4 SRU 5 SRU 6 SRU 7 SCOT

CATO X

Amine acid gas Sour water acid gas Claus tail gas SCOT recycle gas

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• 7. Case Study 2: Switching to SCOT ULTRA can improve performance,

with a lower solvent flow compared to MDEA and DIPA

24 October 2017

Solvent swap can reduce CO2 in the recycle gas, increase the flame temperature and has potential to increase tail gas treating unit capacity while achieving emission targets.

DIPA MDEA JEFFTREAT ULTRA

H2S in treated gas, ppmv 621 611 240 Relative solvent circulation rate, % 100 102 57 H2S in recycle gas flow, mol% 32.5 65.4 76.4 CO2 slip, % 47 79 88 SRU flame temperature, °C 1,180 1,245 1,265

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Experience

7

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• 7. Experience in Gas Processing

1960

Removal of carbon dioxide, carbonyl sulphide (COS) and hydrogen sulphide (H2S). More than 500 ADIP units designed and operated since 1959

ADIP 1959

The industry’s most widely selected tail gas clean-up process. More than 300 units have been licensed

SCOT 1970s

Second-generation solvent that can lead to process line-up simplification

SULFINOL-M 1980

Leading post-combustion CO2 removal technology applied at Lanxess in 2012 and SaskPower in 2014

CANSOLV CO2 2012

Sulfinol-X employs a next-generation solvent that can lead to process line-up simplification

SULFINOL-X 2004

A biological gas desulphurisation process that integrates gas purification with sulphur recovery. 16 reference units since first commercial plant

THIOPAQ 2002

The enhanced version of ADIP uses accelerated reaction kinetics for better CO2 and COS removal from gases

ADIP-X 2000

Removal of H2S, CO2, COS, mercaptans and

• ther sulphur compounds. More than 220

Sulfinol units designed and operated since 1964

SULFINOL 1964

CANSOLV* SO2 Scrubbing System and TGT+ - industry leading, regenerable sulphur dioxide control

• technologies. First commercial application in 2002; 15

units are now operational

CANSOLV SO2 2002

New catalyst and new solvent introduced with the potential to lower costs and improve

• perational flexibility while

meeting stringent emission limits

SCOT ULTRA 2017

More than 1,200 Shell-operated plants and third party licensees worldwide,

• f which over 220 are Sulfinol units and more than 300 are SCOT units.

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*Trademark owned by the Shell Group of companies

Reducing capital and operating expenditure through continuous improvement. Significant reductions in:

• Solvent circulation rates
• Absorber size
• Regeneration energy

ADIP ULTRA and Shell Turbo Trays 2017

1970 1980 1990 2000 2010

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Experience varies from on-the-

run to offline

Justification ranges from

increased capacity, lower

• perating costs, changing feed
• r treated gas specifications

In addition there are several

examples where solvents were changed during the detailed engineering phase, including

 Middle East Region

Recent Shell Solvent Swap Experience

# Region Type of Feed Solvent Swap 1 EU Natural gas MDEA to Sulfinol-X 2 APAC Natural gas Sulfinol –D to Sulfinol-X 3 APAC Hydrogen manufacturing unit Sulfinol-D to ADIP-X 4 AMERICAS Hydrogen manufacturing unit Sulfinol-D to ADIP-X 5 APAC Natural gas- LNG Sulfinol-D to ADIP-X 6 EURASIA Natural gas- LNG Sulfinol-D to ADIP-X 7 ME Natural Gas- LNG Sulfinol-D to ADIP-X 8 Australia Natural Gas- LNG Sulfinol-D to ADIP-X 9 Americas Natural gas DEA to Sulfinol-X

• 7. Experience in Solvent Swaps

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Conclusions

8

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• 8. Conclusions

 Tail Gas Treatment Unit swaps are low-cost solutions for the “lower for longer” market and can:

 Increase capacity and profitability and reduce OPEX and sulphur emissions with no hardware

change

 Working in collaboration, Licensors should provide ongoing guidance and support from the initial

Preparation stage to the final Implementation of a Catalyst and Solvent swap

 SCOT ULTRA is a proven process design that can lower costs for new and existing facilities, and

can improve operational flexibility whilst meeting more stringent regulations.

 Shell offers extensive TGT Catalyst and Solvent swap experience gained from within, its joint-

venture partners and third-party customers

October 2017 29 Shell Global Solutions International B.V.

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For additional information please contact: Gary Bowerbank

Manager Gas Processing Technology Shell Global Solutions, Amsterdam, NL

G.Bowerbank@shell.com

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