RCSA 103020A - Energy Analysis Report (Rev 5)

8/12/2019 RCSA 103020A - Energy Analysis Report (Rev 5)

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KBC ADVANCED TECHNOLOGIES, INC.

Final Report

Refinera de CartagenaModernization Project

Energy Analysis

Prepared for

RCSACartagena, Colombia

Prepared by:

Ref No: 103020A

March 2008


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KBC Advanced Technologies, Inc. 2007 All rights reserved

Proprietary Information

By accepting this document, the recipient confirms that all information contained herein will be keptconfidential, and this information will not be disclosed to third parties without the prior written agreement ofKBC Advanced Technologies, Inc.

KBC Advanced Technologies, Inc.

14701 St Mary's Lane

Suite 300

Houston, Texas 77079

USA

T +1 281 293 8200

F +1 281 293 8290


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REFINERA DE CARTAGENA MODERNIZATION PROJECT

KBC ADVANCED TECHNOLOGIES, INC. 3 RCSA CARTAGENA, COLOMBI

MARCH 2008 CONFIDENTIAL REFERENCE NO103020

Table of Contents

1.0

Executive Summary.................................................................................. 5

1.1 Executive Summary Recommendations ......................................................62.0 Introduction and Objectives ...................................................................... 73.0 Basis of the Study.....................................................................................7

3.1 Energy Prices ...............................................................................................73.2 Best Technology (BT) Energy Benchmarking ..............................................8

4.0 Actual Refinery ......................................................................................... 94.1 Energy Performance ....................................................................................94.2 Utility System..............................................................................................114.3 Cycle Efficiency and R-curve Analysis.......................................................12

5.0 Future Refinery Performance .................................................................135.1 Utility Balances...........................................................................................135.2 Energy Performance ..................................................................................155.3 First quartile performance justification........................................................17

6.0 Preliminary Utility System....................................................................... 176.1 Key Issues..................................................................................................176.2 Equipment List............................................................................................206.3 Control Philosophy .....................................................................................206.4 Sparing Philosophy ....................................................................................216.5 Interconnecting Philosophy ........................................................................216.6

Normal Operation (all equipment available)...............................................21

6.7 Operation with largest generator down ......................................................226.8 Operation with the two largest generators down........................................246.9 Cost Estimation ..........................................................................................25

7.0 Additional Cases.....................................................................................26


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7.1 Minimum Capex Case ................................................................................267.2 Power Export Case ....................................................................................287.3

Integration of Gas Turbine and Hydrogen Plant Case ...............................29

7.4 Propane as Marginal Fuel Case.................................................................307.5 165 KBPSD Case.......................................................................................317.6 190 KBPSD Case.......................................................................................33

8.0 Conclusions ............................................................................................36


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Final Report

Refinera de Cartagena Modernization Project Energy

Analysis

1.0 Executive Summary

Refinera de Cartagena SA (RCSA) is evaluating a project to expand and modernize the CartagenaRefinery. Acting as owners representative, KBC Advanced Technologies Inc. (KBC) defined a state-of-the-art integrated fuels refinery configuration and estimated the capital expenditure. This work is thebasis for the information to licensors for unit designs.

Based on the 2012 configuration, KBC subsequently carried out an Energy Analysis to produce apreliminary utility system design for the RCSA Modernization Project. KBC completed the analysis and

found that a 1stquartile energy performance is economically justified for the future system.

The configuration is suggested based on available information on process units steam, power and fueldemands. While Schedule A figures were available in some cases, typical literature figures andestimations from KBC database have been used for the other process units. The calculations should beupdated with data received from the licensors to further refine the quality of the configuration.

On the 150 KBPSD basis, the total power consumption is estimated to be 73.9 MW. Importantly, it isassumed that sufficient natural gas (NG) will be available to meet the projected total demand of 57MMSCFD.

The utility system features cogeneration consisting of four (4) frame gas turbines combined with two (2)

duct fired HRSG and two backpressure steam turbogenerators. The main equipment total installed cost(TIC) is estimated to be 240 MMUSD.

The five existing STGs are scrapped, yielding a substantial capital expenditure avoidance (2.0-2.5MMUSD per unit is needed to upgrade the machines).

The above system basis is sufficient for a case of operation of 190 KBPSD, using the existing CDU/VDU and increased crude run. The downstream assets would be pushed to ~ 10% overdesign.

The system is highly reliable. During normal operation (all equipment available) and also when thelargest generator is out of service, it operates in island mode, with enough steam and power reservecapacity to respond with no external support. This is required to achieve the 92% on line service factor

goal.

If the two largest generators are down, the system operates synchronized to the grid in power importmode. In this case, the grid acts as backup. In this scenario, a load shedding program or investment inadditional power import capacity infrastructure would be needed.

This report summarizes the work carried out in the Energy Analysis.


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1.1 Executive Summary Recommendations

KBC recommends the following equipment or equivalent for the ISBL:

Power system of the refinery (LLE):

Four (4) Frame Gas Turbines. Listed features as per General Electrics heavy duty MS5001(although this is not a recommendation to purchase that particular equipment):

o Power output ~ 21.6 MW at Cartagena conditions per turbine

Two (2) Duct Fired HRSG - Maximum steam generation (with GTs at maximum) = 520 klb/h

o 2 GT exhaust into 1 HRSG

o Duct fired to produce additional steam to meet the overall steam balance.

Two (2) Steam Turbo Generators

o Maximum power output = 9.5 MW each

o Isentropic efficiency = 65%

o Normal operating conditions:

Steam inlet at HPS (600 psig) = 534 klb/h

Extraction at MPS (50 psig) = 318 klb/h

Exhaust at LPS (150 psig) = 216 klb/h

Fuel Balance:

The amount of natural gas import ranges from 51-57 MMSCFD depending upon crude rate and

operational severity. The accuracy of this number depends heavily on the licensor data, and operatingfurnaces efficiencies. Therefore, the natural gas availability should be defined at 60 MMSCFD withrefining of this value as licensor data is provided.

Cooling Water:

The estimated cooling water load for the whole refinery is 120,000 GPM. This value encompasses theexisting refinery systems. Section 7.6 details the circulation rate per unit and can be used as a startingpoint for new cooling water systems layout and usage.


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2.0 Introduction and Objectives

Ecopetrol and Glencore International AG (Glencore) are joint owners of the Cartagena refinery inColombia. Refinera de Cartagena Sociedad Annima (RCSA) has defined a project to modernize andenlarge the distillation and conversion capacities at the Cartagena Refinery. KBC AdvancedTechnologies, Inc (KBC) defined a configuration for the new 150 KBPSD refinery. The work completedby KBC is the basis for the information to licensors for unit designs.

As part of this effort, KBC is also carrying out an Energy Analysis. After evaluating the current energyperformance and likely targets, the main objective of this portion of the work is to suggest a utilitysystem configuration for the RCSA Modernization Project, based on KBCs configuration. This energysystem must be reliable and energy efficient. An estimation of the main equipment total installed cost(TIC) for the suggested design is also provided.

At this stage, limited information is available from the licensors. With KBCs estimations as the maindata source for utilities consumption, the configuration presented in this report can only be regarded asa preliminary one.

3.0 Basis of the Study

3.1 Energy Prices

The energy analysis is based on the 2012 refinery configuration defined by KBC in the RefineryModernization Project Detailed Modeling Phase Basis for Engineering Process Design report.

The marginal mechanisms and energy prices are key to assess the economics of the proposedconfigurations. The prices used for the Energy Analysis are discussed below.

Power import. The average 2007 price was 150 COP/kWh (75 USD/MWh). Corrected for a 7% yearlyinflation, the 2012 price used for this study is 105.2 USD/MWh.

Power export. The estimated 2007 export price is 90 COP/kWh (45 USD/MWh). Corrected for a 7%yearly inflation, the 2012 price used for this study is 63.1 USD/MWh.

Natural Gas (NG). The average 2007 price was 3.75 USD/MMBTU. Corrected for a 7% yearly inflation,the 2012 price used for this study is 5.26 USD/MMBTU. The NG composition (% mol) is:

Methane CH4 97.94

Ethane C2H6 0.25Propane C3H8 0.06IsoButane iC4H10 0.03n-Butane C4H10 0.01IsoPentane iC5H12 0.01n-Hexane C6H14 0.02Nitrogen N2 1.46Carbon Dioxide CO2 0.22


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Propane. Current price is 46.24 USD/bbl. Corrected for a 7% yearly inflation, the 2012 price used forthis study is 18.0 USD/MMBTU. A Low Heating Value (LHV) of 3.61 MMBTU/BBL is used for propane.

Current NG import is 14 MMSCFD, the supply line being close to the maximum capacity of 20MMSCFD. It is assumed that a new 250 mile pipeline will be installed making enough NG available forboth fuel usage and hydrogen plant feed. However, there is some uncertainty this will happen andadditional NG gas price escalation could occur to cover capital recovery for the new pipeline. As a fallback position (i.e. in the event NG is late in coming), an alternative to provide the fuel to the refineryhas to be studied. This study considers NG is the marginal fuel, but a propane as marginal fuel caseis also analyzed.

A note of caution must be made on the uncertainty in identifying the marginal fuel and the oneassociated with fuel and power prices, as it will have a dramatic impact on the preferred utility systemconfiguration.

Typically, refineries marginal power is imported from the grid. KBC uses the Price Equivalent Efficiency(PEE) concept to calculate the energy equivalent of power. The PEE is defined as:

Cost of marginal fuel ($/MWh)PEE = ---------------------------------------------- * 100

Cost of marginal power ($/MWh)

For the prices described above, the PEE for NG is calculated as (5.26 x 3.41) / 105.2 = 17%

The PEE represents the cycle efficiency of the marginal power (typical PEE is ~35%). In this case,power is expensive relative to fuel. In other words, power generated on-site at efficiency higher than17% will be economic for the refinery. Even inherently inefficient condensing cycles would be more

economic to the refinery than importing power at the given prices.

Other parameters used in the evaluation are:

Exchange rate = 2000 COP/$ Operating period = 8400 h/y Ambient temperature = 100F

3.2 Best Technology (BT) Energy Benchmarking

To assist in their energy conservation studies within refineries and petrochemical plants, KBC havedeveloped a specific methodology encapsulated in the Best Technology (BT) energy efficiency

standards and associated energy valuation methods. These concepts are briefly described below.

The BT standards have been developed by fundamental analysis and design studies on individualprocess units and take into consideration key process parameters affecting energy consumption suchas feed quality, conversion and fractionation performance. Process units with an energy performance of100% BT would be supported by a highly efficient steam and power system and present the followingenergy efficiency features:


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Fired heater efficiency of 92% All power generated internally at 80% cycle efficiency by using combination of backpressure

turbines and gas turbine generators All rotating equipment operating at high efficiency

Preheat trains designed using Pinch technology methodology and featuring optimum approachtemperatures of 36F.

Optimized, energy-efficient process configurations

The Best Technology standards can be applied to individual process units or across a complete refineryand have been used in all of KBCs energy surveys (over 150 to date).

4.0 Actual Refinery

4.1 Energy Performance

The following process units and throughputs are utilized to asses the energy performanceof the existing refinery

The total energy consumption is 1,220 MMBTU/h split into:

Power import = 8 MMBTU/h (0.4 MW at 17% PEE)

Fuel Gas = 869 MMBTU/h

Coke = 343 MMBTU/h

The calculated Best Technology (BT) energy allowance is 572 MMBTU/h. By comparingthe actual and benchmark numbers, the BT index is 213%.

This figure is in line with reported Solomons Energy Intensity Index (EII). The two graphsbelow show that this corresponds to a 4 thquartile performance both in the global league(i.e. against all the refineries studied by KBC) and also when compared only to facilities inthe Americas.

An increase in cycle efficiency to a best-in-class figure of 75% would improve the BT indexdown to 177%, equivalent to a 2ndquartile performance.


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4.2 Utili ty System

The current utility system is defined as described in this section of then report afterdiscussion with RCSA.

Steam Balance. Based on Foster Wheeler study, the steam balance is defined asdepicted in the diagram below.

Power/Shaft Balance. The total demand of 22.5 MW is mainly provided by steam turbines(drivers and power generators) with a small power import ensuring the refinery stayssynchronized to the grid, as per the following table.

Fuel Balance.In addition to the generated off-gases and out of the 869 MMBTU/h of totalfuel gas burnt, 524 MMBTU/h of NG are imported. This is 14 MMSCFD of NG.


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Energy bill.As summarized in the below table, the energy operating cost for the studyprices is 24.1 MMUSD/y.

4.3 Cycle Efficiency and R-curve Analysis

There are three distinctive cycles generating power/shaftwork in the refinery.

Backpressure Steam Turbines (BPST) with boiler cycle efficiency, assumed to be 85%

Condensing Steam Turbines (CTS) with low cycle efficiency, assumed to be 20%

Power import with a Price Equivalent Efficiency (PEE) of 17%.

Rearranging the power balance presented in the previous section in a Cycle Efficiency manner, the

average cycle efficiency is calculated to be 25%, as shown below.

The calculated cycle efficiency is very low compared to industry standards. The large generation in

condensing cycles is the main reason for this inefficiency. Condensing cycles are inherently inefficient

as most of the energy contained in the fuel burnt ends up rejected against cooling water and only a

small fraction (i.e. the 20% above) is recovered as useful power.

The 25% average cycle efficiency is plotted alongside the calculated 0.6 power-to-heat ratio in the

below R-curve, and it is represented by the actual dot.

The comparison of actual operation to the targets shows significant scope for cycle efficiency

improvement for constant power-to-heat ratio:

Target of 51% without gas turbines installation (solid red line)

Target of 76% with gas turbines installation (solid blue line)


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The R-curve analysis reveals what the maximum achievable cycle efficiency is (76% for the

cogeneration case) while illustrates that the installation of gas turbines coupled with supplementary

fired waste heat boiler is probably the best route to become a pacesetter performer.

The potential for current cycle efficiency improvement through the installation of new backpressure

turbines is limited for existing steam levels due to the absence of letdowns.

5.0 Future Refinery Performance

5.1 Utili ty Balances

The estimated unit-by-unit power, fuel, steam and cooling water (CW) consumptions are summarized inthe table below. The essential totals are:

Power consumption = 73.9 MWe

NG import = 56.55 MMSCFD

Net process units steam consumption = 195 klb/h

CW circulation = 110,000 GPM (24,884 m3/h)


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5.2 Energy Performance

Translating the above balances into their equivalent MMBTU/h and including the utility system, the totalenergy consumption is estimated, as detailed in the following table:

From the above table, the total energy consumption including all fuels, power and steam is estimated tobe 3,134MMBTU/h

The Best Technology (BT) allowance is 1,929 MMBTU/h, resulting in a BT index 163%. As shown inthe graphs below, this is a first quartile performance both in the Americas region and globally.


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Future energy performance comparison against all sites studied by KBC

Future energy performance comparison against sites studied by KBC in the Americas


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5.3 First quartile performance just ification

With a relatively cheap marginal fuel (NG) price, the question may arise as to whether a first quartileenergy performance is economically justified. Three different scenarios have been compared: first,

second and third quartile operation, as shown in the comparative table below. The methodology usedfor the comparison is to select a representative BT for the quartile and attribute the difference inperformance to a change in cycle efficiency. To achieve the desired cycle efficiency, a utility systemconfiguration is selected that maintains a similar level of reliability.

To provide the refinery energy demands with a 3rdquartile energy performance (cycle efficiency of 25%,similar to the actual performance) requires an estimated investment of 95 MMUSD through acombination of new equipment and upgrades of existing STGs and results in an operating cost of 62MMUSD.

To move from 3rdto 2ndquartile (52% cycle efficiency) requires an additional investment of 26 MMUSD.Considering the operating savings, the simple Internal Rate of Return (IRR) is 35%.

Likewise, the jump from 2nd to 1st quartile (78% cycle efficiency) performance needs 27 MMUSD ofextra capex. The more efficient configuration reduces the operating cost by 9 MMUSD/y, resulting in asimple Internal Rate of Return (IRR) of 33%.

As a conclusion, and with a typical cost of capital in the 10% - 12% range (to be confirmed by RCSA),the calculated IRRs would justify the required investment to achieve a 1stquartile energy performance.

6.0 Preliminary Utility System

6.1 Key Issues

General Need to design a reliable system, able to operate when largest steam or power generator fails

during normal operation (all equipment available).

Operation with the largest generator out of service (e.g. scheduled maintenance) needs to bealso studied.

This study is based on process units steam, power and fuel demands from various sources:

o Schedule A (hydrocracker, ULSD HTs, NHT, reformer, butamer)


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o Typical figures from literature

o KBC database

The calculations should be revisited and fined-tuned as more Schedule A figures are receivedfrom the licensors.

Different designs (e.g. hydrogen plant) can have a significant impact on estimated demands and,in turn, this variability in demands can change the preferred configuration of the utility system

Power A key decision is whether to operate in island mode (i.e. not connected to the grid) or connected

to grid. Many refineries operate connected to the grid on import mode, while low grid reliability isthe overriding justification for those operating in island.

Reliability at this end of the national grid is very low, as the main generators in Colombia arehydroelectric plants remote from Cartagena. Furthermore, there is no obligation on the existingpower suppliers to guarantee reliability.

These considerations led to the consensus of the parties involved in the review meeting to

function in island mode during normal operation (i.e. all generators available). This isrequired to achieve the 92% on line service factor goal. When one of the largest generators is out of service (e.g. in scheduled maintenance), the

refinery operates synchronized to the grid in a minimum import mode, the grid acting as back-up.

The maximum power import with existing line is 10 MW.

Power reserve to react to unscheduled failure of the largest generator has to come from eithergas turbines or grid import. Steam turbines response is deemed sluggish and thus not reliableenough.

Existing steam turbine generators TG-1/2/3/4/5 are old and need an estimated 2.0-2.5 MMUSDinvestment each to bring them back to standards by replacing/upgrading/repairing stationaryparts. Also, maintenance/upgrading costs are high as the age of the machines means they nolonger are standard machines. This, alongside the low efficiency of condensing cycles, leads to

the consensus of the parties involved in the review meeting to scrap all five turbinegenerators .

Cogeneration cycles consisting of Gas Turbines (GT) plus Heat Recovery Steam Generators(HRSG) are needed to achieve the desired efficiency and reliability. There are two types of GT:

o Aero-derivative GT (e.g. MS5002E)

Low specific weight, streamlined shape, smaller footprint

Higher electric efficiency (40%), higher power/heat ratio

Higher maintenance costs (falls after long periods)

Higher investment cost ($ per kW)

o Heavy duty / frame GT (e.g. MS5001)

Robust unit for stationary duty and continuous operation

Lower efficiency (30-35%), lower power/heat ratio Lower maintenance costs (maintains performance)

Lower specific investment

It is assumed that a 9MW turboexpander will be installed in the FCC unit.

It is assumed that no Power Recovery Turbine (PRT) in will be installed in the hydrocracker

Driver selection.


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There are three existing 600 GPM (300 klb/h) demineralized water trains. Typical operation is 1operating, 1 regenerating and 1 in standby

Out of the two existing deaerators, one is in good condition and will be kept, will the other will bescrapped

A 60% condensate return is assumed in the future configuration. Current condensate recoveryappears too low and that no capital is included here to alleviate that

Current total raw water demand is approximately 2200 GPM. The line capacity is 2500 GPM

6.2 Equipment List

Gas Turbine 1 Frame GT. Listed features as per General Electrics heavy duty MS5001(although this is not a recommendation to purchase that particular equipment):

o Power output = 26.8 MW at ISO conditions, 21.6 MW at Cartagena conditions

o Heat rate = 12,687 kJ/kWh

o Electric efficiency = 28.4%

o Exhaust temperature = 901 F

o Pressure ratio = 10

Gas Turbine 2 same as Gas Turbine 1



Duct fired HRSG 1 - Maximum generation (GT at maximum) = 520 klb/h of HPS

Duct fired HRSG 2 Same as Duct fired HRSG 1

STG 1o Maximum power output = 9.5 MW

o Isentropic efficiency = 65%

o Normal operating conditions:

Steam inlet at HPS (600 psig) = 534 klb/h

Extraction at MPS (50 psig) = 318 klb/h

Exhaust at LPS (150 psig) = 216 klb/h

STG 2 Same as STG 1

6.3 Control Philosophy

The system is designed to operate in island mode (i.e. not connected to the grid) during both normaloperation and when the largest generator is down for maintenance. This makes the system very robustand reliable. If the second largest generator is also out of service, the system operates synchronized tothe grid, which provides the power backup within the constraints of the existing infrastructure.


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The three steam headers will be balanced as follows:

HPS (600 psig), balanced by the HRSG steam generation

MPS (50 psig), balanced with the STG extraction

LPS (150 psig) , balanced with the STG extraction

6.4 Sparing Philosophy

The goal is to operate with a N+1 boiler philosophy, where N boilers are operating and one (1) is downfor maintenance. The studied scenarios require a maximum of one boiler operating. This suggests that3 of the existing boiler could be scrapped. SG104 is the first choice to be taken out of service.

Special situations like start-up and large steam generation units shutdown should be analyzed in moredetail before a final decision can be taken on the number of boiler to be scrapped.

6.5 Interconnecting Philosophy

With the same pressure levels, the system is an expansion of the current HPS and MPS network andworks interconnected to it. The LPS header is new and has no connections to the existing pipework.

6.6 Normal Operation (all equipment available)

Key items during normal operation are:

Operation in island mode

Equipment operating:

o GTs = 4x10.9 MW (51% of max.)

o HRSGs = 2x194 klb/h

o STGs = 2x8.7 MW

o Boilers = 0x0 klb/h

Make-up Boiler Feed Water (BFW) = 430 klb/h

Total BFW = 1,217 klb/h

Power reserve

o Required = 10.9 MW

o Actual = 32.6 MW

Cycle efficiency = 78%

NG (fuel) = 25.5 MMSCFD

Energy operating cost = 43.9 MMUSD/y (excludes NG raw material)


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The demineralized water make-up requirement increases from current 142 klb/h to 430 klb/h. Thisdemand is above the existing demineralized water trains capacity (600 GPM or 300 klb/h each). Thereare two options available to alleviate this:

Challenged current philosophy where out of the 3 trains, 1 is operating, 1 is regenerating and 1

is in standby. Install a 4thtrain

The total Boiler Feed Water (BFW) demands jumps from current 510 klb/h to 1217 klb/h. Information onthe existing deaerators capacity is needed before a recommendation can be made on whether and howmuch investment is needed on this area.

6.7 Operation with largest generator down

When a GT is down, the other three cogeneration sets increase their loads and the system andoperating philosophy remains essentially unchanged. One conventional boiler is started and operated

at minimum turndown to procure the required steam reserve. The system is just marginally less efficientand more expensive to operate than during normal operation. The system reliability is not affected.



o GTs = 3x14.6 MW (67% of max.)



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o STGs = 2x8.7 MW




Power reserveo Required = 14.6 MW

o Actual = 14.6 MW





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6.8 Operation with the two largest generators down

When 2 GTs are down, the other two cogeneration sets maximize their loads. The operating philosophychanges from island mode to synchronized, with the national grid acting as backup. One conventional

boiler is still operated at minimum turndown to ensure an adequate steam reserve. The system is justmarginally less efficient and more expensive to operate than during normal operation. The systemreliability decreases.

Operation synchronized, grid as power backup. Power import = 0.5 MW


o GTs = 2x21.6 MW (100% of max.)


o STGs = 2x8.7 MW



Total BFW = 1,217 klb/h Power reserve provided by grid. Load shedding program would be required.


o Actual = 10.0 MW (max power import)





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7.0 Additional Cases

7.1 Minimum Capex Case

To try and minimize the required capital investment, the case is studied where only three (3)cogeneration sets are installed. The features listed below correspond to General Electric aeroderivativeMS5002E gas turbine.

Power output = 32.0 MW at ISO conditions, 27.7 MW at Cartagena conditions

Heat rate = 10,000 kJ/kWh

Electric efficiency = 36.0%

Exhaust temperature = 951 F

Pressure ratio = 17

The GTs are coupled to duct fired HRSGs with a maximum generation capacity of 220 klb/h of HPS.

The same two STGs are installed (power output 9 MW, isentropic efficiency 65%).

During normal operation, with all installed equipment available, the key operating items are:



o GTs = 3x14.6 MW (53% of max.)


o STGs = 2x8.7 MW


Make-up Boiler Feed Water (BFW) = 430 klb/h Total BFW = 1,217 klb/h

Power reserve


o Actual = 26.8 MW





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.

This less capital intensive scheme is also more economic to operate, in part due to the higherpower/heat ratio of the aeroderivative gas turbines. But reliability should be also factored in.

When the largest generator (GT plus associated HRSG) is out of service, the other two cogenerationsets increase their loads (2 x 21.9 MW, 79% of max) while the other equipment operation remainsunchanged. The limited power reserve (6.4 MW vs. required 21.9 MW) makes island operation notviable and the refinery would need to work connected to the grid. In short, the system efficiency andoperating cost remains low but the reliability is compromised.

If the second largest generator (GT plus associated HRSG) was also out of service, the remainingcogeneration sets would maximize its operation. The lost power need to be purchased. The requiredimport power is 16.0 MW, above the existing maximum of 10 MW. Several options could help alleviatethis situation:

Power boost steam injection in GTs. It is estimated that approximately 0.1 MW of additionalpower can be generated for each klb/h of injected steam. Therefore, 60 klb/h of steam would berequired. This may be feasible, but probably too tight on both GT injection and power importlimits.

Invest in additional power import capacity. Probably an expensive option.

Install condensing section in the new STGs. Under-utilized capex and lower efficiency duringnormal operation as the condensing section need to be operated continuously at minimum flow.


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Generate higher pressure steam in the HRSG to maximize the backpressure STG generation.Additional 2.4 MW could be generated in the STG if the HRSG steam was at 900 psig and840F. This is probably not enough potential to justify the added complexity (higher pressuresystem, multiple, STG inlets, etc)

It is to note that this system would have a lot less flexibility to work under other scenarios like start-up or190 KBPSD case.

7.2 Power Export Case

While oil refining is the core RCSA business, additional profit may be at hand by becoming a powerexporter. The scenario where the refinery operates in power export mode (as opposed to island mode),selling the excess power is discussed in this section. Obviously, the economics will be heavilydependant on the export price. The break-even power export price is calculated to be 63 COP/kWh(todays price, scaled up for inflation).

It is understood the there are two possible power export modes:

Qualify as a power exporter (minimum requirement is 10 MW) and go through a daily bidprocess to sell in the spot market. RCSA may find it difficult to compete as this marketmechanism seem to be best exploited by the low-cost hydroelectric plants, predominant inColombia.

Supply under a two-party contract to a dedicated customer. Ecopetrol-owned Propilco could bea good candidate to exploit this option.

For the given prices, the PEE when power export is the marginal power is (5.26 x 3.41) / 63.1 = 28%.This means that if power can be generated on-site at a higher-than-PEE efficiency, it will be beneficialto export.

A step-out case from the preliminary configuration is presented below. Normal operation at the highestpossible GT load within the steam balance constraints results in a potential form power export of 20.7MW. There is still enough power reserve available to operate with the largest generator down whilekeeping a similar export amount.

The economics summarized in the table below show that for given prices, the benefit would beapproximately 3.3 MMUSD/y. Importantly, this mode would add 4.7 MMSCFD to the total NG demand.


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As the power export comes from the higher load of already purchased equipment, the benefits wouldcome at no additional capital cost. If additional equipment needed to be installed to generate the exportpower, the simple payback on large equipment TIC only is anticipated to be on the 10 years range.

7.3 Integration of Gas Turbine and Hydrogen Plant Case

To date, Technip and Air Liquide have installed at least six large SMRs integrated with cogenerationunits in Europe and the USA (The Large Hydrogen Plant Challenge, reprinted from HydrocarbonEngineering, July 2005), as illustrated in the below block flow diagram.

Given RCSAs hydrogen plant size, it is estimated that an exact match would be achieved through theinstallation of a 33 MW Gas Turbine (~ Frame 6). In addition, a 15 MW turbogenerator could expand1500 psig steam to 600 psig. While the operating cost advantage is relatively small, one of the mainadvantages would be the capital avoidance of the associated HRSG as the reformer furnace is used to

raise the steam from the hot GT exhaust gases.

The size of the exact match GT, significantly larger than the standard cogeneration sets discussed inthe previous sections, presents reliability problems (i.e. the largest generator would be larger now andin turn, the power reserve would need to increase) on the power system. If the GT is sizedindependently of the reformer (i.e. GT with similar size to the other cogeneration sets), this problemwould be alleviated but the benefits diluted.


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Integrated systems are typically supported by both a reliable power grid and a hydrogen network. Noneof those is in place in RCSA, compromising the reliability of the system.

7.4 Propane as Marginal Fuel CaseThe NG supply line is close to maximum capacity for current import of 14 MMSCFD. This studyassumed that new infrastructure will be installed and sufficient NG will be available for both fuel usageand hydrogen plant feed. In the event NG is not available for fuel usage, an alternative fuel has to beburnt. The use of Propilcos propane as marginal fuel is analyzed in this section.

Propanes price is much higher than NG (18.0 vs. 5.26 USD/MMBTU). This will have a major impact onthe economics. For the given prices, the PEE when propane is the marginal fuel is (18.0 x 3.41) / 105.2= 58%. This means it is still beneficial to generate power on-site using high efficiency cycles (i.e. above58% efficiency), but the incentive with respect to power import will be diminished. In essence, we gofrom a situation where fuel is inexpensive relative to power to one in which fuel is expensive even

relative to fairly costly power.In normal operation, the utility system uses 25.5 MMSCFD of NG as fuel, with two distinctive users:

Gas Turbines ~ 16.2 MMSCFD NG ~ 606 MMBTU/h ~ 4,000 BPSD propane FG system makeup ~ 9.3 MMSCFD NG ~ 347 MMBTU/h ~ 2,300 BPSD propane

Reportedly, 2500 BPSD of propane are available from Propilco. These can be used for FG systemmakeup, but there is no sufficient propane to be used in the GTs.


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During normal operation, with all installed equipment available, the operation would be very similar tothe preliminary case, with the following key operating parameters:



o GTs = 4x11.3 MW (52% of max.)o HRSGs = 2x205 klb/h

o STGs = 2x8.8 MW




Power reserve


o Actual = 31.3 MW





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The considerations for operation when the largest generator or the two largest generators are out ofservice are analogous to the ones described in the preliminary case. The main equipment installed costwould also remain unchanged.

7.6 190 KBPSD CaseThe case where the old CDU2/VDU2 unit is operating is analyzed in this section. The estimated unit-by-unit power, fuel, steam and CW consumptions can be found in the below table. The highlights are:

Power consumption = 85.8 MWe

NG import = 52.5 MMSCFD

Net process units steam consumption = 254 klb/h

CW circulation = 119,000 GPM (27,132 m3/h)


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When the largest generator is out of service, the three remaining GTs can increase their load to 17.7MW (82% of max). The power reserve (7.9 MW) is not enough to meet the reserve requirement (17.7MW), making island operation unfeasible.

If the second largest generator is also down, the required power import would increase up to 9.8 MW,close to the existing line maximum capacity of 10 MW.


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8.0 Conclusions

A preliminary utility system configuration has been suggested based on available information forprocess units steam, power and fuel demands. Schedule A figures were available for some units

(hydrocracker, ULSD HTs, NHT, reformer, butamer) and typical figures from literature or from KBCdatabase have been used for the other process units. It is anticipated that the calculations should berevisited and fined-tuned once more quality data is received from the licensors.

150 KBPSD 165 KBPSD 190 KBPSDPower consumption 73.9 MWe 75.4 MWe 85.8 MWeNG import 56.55 MMSCFD 48.6 MMSCFD 52.5 MMSCFDNet steam consumption 195 klb/h 220 klb/h 254 klb/hCW circulation 110,000 GPM 107,000 GPM 119,000 GPM

Four frame gas turbine (MS5001 parameters used, 26.8 MW ISO) and two duct fired HRSG are needed.

In addition, two 9.5 MW backpressure STGs would be installed. The estimated Capex (main equipmentinstalled cost only) is 240 MMUSD. The estimated Opex for given prices is 44 MMUSD/y.

The five existing STGs are scrapped, yielding an additional capital expenditure avoidance (2.0-2.5MMUSD per unit is needed to upgrade the machines).

The system is highly reliable. During normal operation (all equipment available) and also when thelargest generator is out of service, it operates in island mode with enough steam and power reservecapacity to respond with no external support.

If the two largest generators are down, it needs to be operate in import mode and synchronized to agrid that acts as backup. In this scenario, a load shedding program or investment in additional powerimport capacity infrastructure would be needed.

The utilities system design is likely to be a schedule-driven project, as the steam and power systemneeds to be in place before the process units are. As a guideline, the estimated delivery time inColombia for a Gas Turbine (GT) is 18-20 months while for a package boilers (not needed in thesuggested design) is 24-30 months.

There are two main outstanding items:

Carbon footprint. There may be a possibility for RCSA to play a role in the carbon credits tradingthrough Clean Development Mechanism (CDM). As an example, en efficient steam and powersystem in the current refinery saves approximately 100,000 t CO2/y. Assuming a CO2 cost of

10 USD/tCO2, this would be equivalent to 1.0 MMUSD/y H2 plant design. Different designs can have a significant impact on the energy balances and, in

turn, on the utility system design.

Documents

RCSA 103020A - Energy Analysis Report (Rev 5)