I

Pinch Technology/ Process Optimization

Volume 8: Case Study - United Refining Company

CEC Report CR-105239

Prepared by TENSA Services, Inc. 6200 Savoy Drive, Suite 540 Houston, TX 77036-331 5 May 1995

CPe 0521

INTEREST CATEGORIES Industrial Demand-side Planning

KEYWORDS Pinch technology Heat recovery Energy efficiency Heat pumps End use Industry

REPORT SUMMARY PINCH TECHNOLOGY/PROCESS OPTIMIZATION Volume 8: Case Study - United Refining Company

The case study of United R e f i g Company's fuel oil refinery at Warren, PA demonstrates how process integration or pinch technology can identify practical and cost-effective ways to substantially reduce energy costs. Suggested cost-saving measures include steam and power system improvements, optimum heat exchanger network design, furnace system improvements and use of a heat pump. The mechanical vapor recompression heat pump would save 11,000 pounds per hour of steam. Replacement of steam drives with electric motors would add about 2 MW in electricity usage.

BACKGROUND Improved industrial process efficiency is of great importance to electric utilities. It enhances customer competitiveness and profitability, thereby fostering load retention and strategic load growth. By understanding the energy use pattems and options at an industrial site, the utility can work together with its customer to define mutually beneficial investment and operating options. The technique of choice is pinch analysis, an innovative and effective method for analyzing industrial sites. Since 1988, EPRI and member utilities have cosponsored over twenty such studies around the country in various industries, with a high degree of success.

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OBJECTIVES To identify opportunities for energy savings using pinch technology; to develop technically and economically viable projects to achieve these targets. --- - -- APPROACH Project team was formed consisting of consultants, plant and electric utility representatives. The team visited the plant to define and collect process, utility and economic data. The consultants developed appropriate material, heat and steam balances, and using pinch technology, characterized each refinery's

heating and cooling needs. After quantifying the scope of potential improvements, the site was screened for specific projects based on processing changes, heat recovery and heat pump applications.

RESULTS The study indicates that substantial operating cost savings could be achieved using conventional technologies and investment payback criteria(typical1y two years or less). Projects were identified to reduce energy cost, switch from steam to electric drives, use heat pumps and reduce NOx.

EPRI PERSPECTIVE The study shows that process integration or pinch technology is an effective tool to improve industrial energy efficiency. Utilities can use pinch methodology to promote load stability in their service territories. Information on energy use options and interactions and their sensitivity to economic factors can also be used to foster successful demand-side management programs.

EPRI has published additional case studies of pinch technology on a variety of industries. These are documented in reports TR- 101 147, Volumes 1 through 5. Other related work is documented in EPRI reports EM-6057, CU-6334, CU-6775, CR105237, and CR105238. An EPRT brochure on pinch technology is numbered BR-102466.

PROJECTS RP3879-01 EPRI Project Manager: K. R. Amamath Customer Systems Division Contractor: Tensa Services, Inc.

For further information on EPRI research programs, call EPRI Technical Information Specialists (415) 855-241 1.

r A

PINCH TECHNOLOGY/PROCESS OPTIMIZATION

Volume 8: Case Study -- United Refining Company

Final Report, March 1995

Prepared by TENSA Services, Inc. 6200 Savoy Drive, Suite 540 Houston, Texas 77036-3315

Prepared for Electric Power Research Institute 3412 Hillview Avenue Palo Alto, CA 94304

For technical information, contact:

EPRl Chemicals & Petroleum Office 1775 St. James Place, Suite 105

Houston, Texas 77056

Fax: (71 3) 963-8341 (71 3) 963-9307

For ordering information, contact:

EPRIAMP Customer Assistance Center (ECAC) 1 -800-4320-AMP

Disclaimer of Warranties and Limitation of Liabilities

NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, NOR ANY PERSON OR ORGANIZATION ACTING ON BEHALF OF ANY OF THEM:

(A)MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED,

(I)WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS REPORT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR

(1I)THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR

(1II)THAT THIS REPORT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR

(B)ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRl OR ANY EPRl REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS REPORT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS REPORT.

ACKNOWLEDGMENTS

TENSA Services, Inc. appreciates the interest and support of Pennsylvania Electric Company (Penelec), the Electric Power Research Institute (EPRI) and the United Refining Company (URC), throughout the course of this study. Special thanks to Mr. Geoffrey S. Soares, Robert Ennis, David Dorn and their colleagues at URC, for their excellent cooperation during the data collection and validation phases of this study. We are also grateful to Gary Wareham and David A. Pascale of Penelec, who provided the valuable electric distribution rate data.

CONTENTS

Section Page

1 Introduction .............................................................................................................. 1.1

2 Furnaces ................................................................................................................... 2-2 Crude and Vacuum Furnaces Operation ...................................................... 2-1 Furnaces Excess Air Reduction ................................................................... 2-5 Recommendations for Flue Gas Analyzers .................................................. 2-7

3 Steam System ......................................................................................................... 3-1 Introduction ................................................................................................. -3-1 Recommendations Toward Steam System Efficiency .................................. 3-1 Summary ...................................................................................................... 3-5 Description of Modeling of URC Steam System ........................................... 3-8

4 DIB Column Heat Pump .......................................................................................... 41 Introduction .................................................................................................. 4-1 Base Case .................................................................................................... 4-1

New Column Configuration .......................................................................... 4-7 New Configuration Pressure Reduction and Heat Pump Evaluation ............ 4-7 Summary ...................................................................................................... 4-9

Heat Pump and Pressure Reduction Operation ........................................... 4-4

5 FCC Main Fractionation Unit ................................................................................. 5-1 Process Description ..................................................................................... 5-4 Analysis of the Current “Base Case” Operation ........................................... 5-4 Optimum Energy Recovery .......................................................................... 5-4 Discussion .................................................................................................. 5-12

Appendix A ...................................................................................................... A-1 Introduction to Pinch Technology ................................................................ A-1

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1 f

1 1

EXECUTIVE SUMMARY

A detailed process efficiency optimization study using Pinch Technology of the United Refining Company’s facility at Warren, Pennsylvania was performed. The study was co-sponsored by the Electric Power Research Institute (EPRI) and the Pennsylvania Electric Company (Penelec).

The Scope of Work contains refinery wide steam and condensate system modeling and optimization, heat integration of FCC unit and DIB column, operation and efficiency improvement of crude and vacuum furnaces, and efficiency improvement of other furnaces in the refinery. In this study, TENSA Services, Inc. applied pinch technology along with other energy conservation strategies to identify significant savings for United Refining Company (URC). The summary of these findings are listed below:

Heat Pump on the DIB column can save over 11,000 Ib/hr of steam usage with the additional benefit of increasing the column capacity by 25%, and also reducing the flare system load.

Replacing steam turbines with electric motors can save URC 68,000 Ib/hr of steam.

Modification on the reformer deaerator including piping change and flash drum installment, can save 3,000 Ib/hr of steam and also unload the deaerator.

Modification on wash water piping can save 5,000 lblhr of steam usage.

A heat integration option in the FCC unit can save 1.6 MMBtu/hr of fuel and reduce the wet gas compressor power consumption by 224 KW.

Excess air reduction in the furnaces can save 28 MMBtu/hr of fuel usage.

With the above projects implemented, URC can shut down some of the existing low efficiency boilers.

The identified projects are also summarized in Table ES-1. After implementing some of these recommendations, the refinery could reach excess-fuel gas situation. Even if the

ES- 1

credit for saving only 50,000 Ib/hr of steam is considered, it will still result in a yearly savings of over one million dollars per year for the refinery.

Total savings in steam ($/yr) = 2,150,000 Additional cost of electricity ($/yr) = 726,200 Net annual savings: $1.4 millions/yr.

ES-2

Table ES-1 Calculated Value of URC’s Savings

Item Savings in Savings in Additional Estimated Payback Steam Fuel Electricity Installation Period

(1000 Ib/hr) (MMBtu/hr) Consumption cost ( Y W

Replacing steam turbines 68 -0- 1,945 2* (KW)

Heat pump on DIB 1 1 -0- 320 603,000 1.6

Reformer Deaerator 3 -0- 70 140,000 1.3

Water wash repiping 5 -0- -0- 100,000 0.5

FCC Heat integration 1.6 -224 180,160 1.2

Flue gas analyzer 28 -0- 2*

Total 87 29.6 2,111

*Estimated 2 years or less in payback

ES-3

I 1

INTRODUCTION

The objective of the study is to apply Pinch Technology to identify ways to reduce the energy consumption in the plant and simultaneously debottleneck its capacity. Pinch Technology is a comprehensive analytical tool for analyzing processes to calculate the optimum amount of energy required to operate a process. These calculations are based on basic thermodynamic concepts. Practical constraints related to the process may be incorporated in the analysis to predict the minimum energy required to run the process and meet these constraints at the same time. Application of Pinch Technology also enables calculation of the capital investment required to realize these savings and an accurate estimation of the payback period for suggested retrofit schemes. An introduction to Pinch Technology is provided in Appendix A.

Though originally developed for optimizing Heat Exchanger Networks (HEN), pinch technology is now being applied for the integration of the various unit operations such as distillation, evaporation, drying, etc. Pinch technology has gained recognition as a valuable process design tool and has pointed the way to many energy-saving ideas in the process industries.

The Scope of Work for this study is comprised of Deisobutanizer (DIB) column in the alkylation unit, Fluid Catalytic Cracking (FCC) main fractionation unit, steam and condensate system, furnaces & boiler efficiencies.

Section 1 of this report describes the background information of this study. Section 2 deals with findings in the area of furnaces efficiencies. Section 3 focuses on the steam and condensate system. DIB heat pump evaluation is presented in Section 4. Finally, the FCC heat integration study is discussed in Section 5. The economic factors in evaluating various project feasibility are summarized in Table 1.1. These values are used throughout this study:

Table 1.1

Utility cost Steam cost: $91 000 Ib. Cooling water cost: $0.3/MM B tu Condensate cost: $0.3/1000 I b. Annual average electricity cost: $O.O4/KWH

Annual operating hours: 8600 hr/yr

1-1

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I

2 FURNACES

Introduction

URC has many fired heaters including crude & vacuum heaters, Fluid Catalytic Cracking (FCC), reformers, Naphtha HydroTreater (NHT), and Deisobutanizer (DB) reboiler. This section discusses the operation of these heaters for efficiency improvement through excess air reduction. More effort has been put on the crude and vacuum furnaces, since they are the biggest fired heaters in the refinery.

Crude and Vacuum Furnaces Operation

The existing crude and vacuum furnaces configuration is shown in Figure 2-1. The vacuum flue gas is ducked to the crude convection section. The upper 5 rows of the process coil in the crude convection section are used to preheat the crude column bottoms, before it gets heated further in the radiant section of the vacuum furnace. Before the scheduled turnaround, the performance of the existing configuration was evaluated to see the effect of furnace decoking and possible separation of the upper 5 rows from crude bottoms preheat as shown in Figure 2-2.

Table 2-1 summarizes the results of the evaluation for three different conditions: the existing fouled (before decoking), the existing clean (after decoking), and the clean and separate.

The evaluation was based on rigorous calculation on the radiant and convection sections at reasonable bridge wall temperature and design heat transfer area. The total duty provided to the crude feed was determined to be about 150 MMBtu/hr. through feed simulation. The vacuum furnace duty was calculated to be 20 MMBtu/hr.

From Table 2-1 , it is apparent that decoking does not improve the furnace efficiency significantly in this case. However, the major benefit of the decoking procedure is to lower the tube metal temperature. Coking rate is highly exponential and if not decoked at the appropriate time, it could plug the tubes solid. Even before it reaches that stage, the tube metal temperature may reach a point where it may reduce the coil’s life.

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Table 2-1 Summary - Crude / Vacuum / Furnaces / Analysis

Existing Fouled Existing Clean Clean Separate

Crude Fuel Fired = 236.2 Fuel Fired = 236.6 Fuel Fired = 210.8 Furnace Rad. eff. = 0.494 Rad. Eff. = 0.5029 Rad. Eff. = 0.5171 (MMBtu/hr) Q crude conv = 41

Rad. Flux = 11,206" Q crude conv = 33

Q vac mnv = 12 Rad. Flux = 12,000*

Q crude conv = 31 Q vac mnv = 12.4

Rad. Flux = 12,234*

Vacuum Fuel Fired = 11.96 Fuel Fired = 11 .I 3 Fuel Fired = 32.4 Furnace Rad. Eff. = 0.6685 Rad. Eff. = 0.6829 Rad. Eff. = 0.6171 (MMBtulhr) Rad. Flux = 2383* Rad. Flux = 2264* Q vac conv = 0

Rad. Flux = 5958*

Steam Steam Generated = 27 Steam Generated = 28.3 Steam Generated = 26.5 Generation (MMBtu/hr)

Flue Gas 755°F 750°F 735°F Temp.

Total Heat 197 198.3 196.5 Absorbed (MMBtu/hr) (CRU + VAC + STM) Total Heat 248.16 247.73 243.2 Released (MMBtu/hr)

0.8005 0.808 Overall 0.7938 Efficiency

Annual Fuel $6.454 million $6.392 million $6.323 million Cost (8,600 hrs)

Savings $62,00O/yr $1 31,00O/yr

(* Unit in Btu/Hr - Sq. ft.)

2-4

I , Fumaces

It is also obvious from the summary table that each service should be performed in its own furnaces. There is a net savings of $1 31,00O/year, if they operate individually. The separate configuration provided flexibility to increase capacity in the crude and vacuum furnaces. The flux density will drop to below the designed value of 12,000 and 7,000 for crude and vacuum furnaces respectively.

From the analysis it appears that the existing crude furnace may have problems meeting the overall efficiency shown on the data sheet.

The burners on both furnaces were also examined. There are 28 burners in the crude furnace. Twelve of those are from John Zink with 15 MMBtu/hr. maximum heat release. The remaining sixteen (16) are made by NAO, with 8.98 MMBtu/hr of maximum heat release. The furnace should have only one size and type of burner to get uniform flame pattern at the same fuel pressure and also to avoid mix up in burner tips. URC should replace the existing sixteen (16) NAO burner with John Zink burner. This will give a total maximum firing of 420 MMBtuIhr. Since the designed operation will be only 50% of the burner capacity, these burners will not be fired at full capacity. To achieve the desired turndown, URC will have to shut some of the burners.

The vacuum furnace has nine (9) John Zink burners each with maximum heat release of 5.39 MMBtu/hr. The total maximum heat release is 48.5 MMBtu/hr. By examining the drawing of the vacuum furnace, it is noticed that the top tubes are only 17’-0 above the burners. It is recommended that only gas firing be used in the vacuum furnace to minimize the flame length, and flame impingement on the top tubes and tube supports.

URC should explore the possibility of changing the arrangements of four (4) top tubes and their support system, to avoid direct flame impingement on the tube. If new burners of higher capacity are considered, they should preferably be all gas fired along with the above changes.

Furnaces Excess Air Reduction

URC has a number of fired heaters for its process heating needs. Optimizing combustion efficiency and minimizing exhaust emissions are vitally important for proper operation of these furnaces.

As most combustion equipment operator knows, it is extremely undesirable to operate a burner with less than stoichiometric combustion air. Not only is this likely to result in a smoking stack, but it will significantly reduce the energy released by the fuel. In actual application, it is impossible to achieve stoichiometric combustion, because burners can not mix fuel and air perfectly. To ensure that all of the fuel is burned and that little or no combustibles appear in the flue gas, it is common practice to supply some amount of excess air. But too much excess air is also inefficient because it enters the burner at ambient temperature and leaves the stack hot, thus stealing useful heat from the process.

2-5

Furnaces I I

Table 2-2 illustrates the savings by reduction in excess air in the crude furnace. The Table compares various percentage of excess air to 20% excess air. It shows that fuel consumption can be reduced by 20 MMBtuIhr, simply by reducing excess air from 80% to 20%, as an example.

But how is the correct amount of excess air determined? By far the most widely used method is flue gas analysis.

Table 2-2 Effects of Excess Air On Fuel Savings For The Crude Furnace

Flue Gas Temp (OF) 755 755 755 755 755 755 % Excess Air 20 30 40 50 60 80 Efficiency (%) 81.71 80.57 79.14 78 76.51 73.54 Efficiency change (%) 0 1 .I4 2.57 3.71 5.2 8.17 Add. heat available 0 2.83 6.38 9.21 12.9 20.27 (MMBtu/hr) Annual Savings ($/yr) 0 85,182 192,036 277,218 388,286 610,121

Based on 180 MMBtu/hr, furnace duty.

By measuring the actual concentrations of several flue gas constituents, as well as the flue gas temperature, both unburned fuel loss and flue gas heat loss can be determined. It is then possible to control the supply of excess air so that combustion efficiency will be maximized.

There are basically two types of flue gas analyzers available Le., extractive and in-situ. The extractive method takes a sample from the stack, conditions it, and then analyzes it. The in-situ method is where the sensor is mounted in the stack and typically, because of high temperature, a Zirconium Oxide sensor is used to measure oxygen. The in-situ instruments are normally cheaper than extractive instruments. But there are many advantages for extractive analysis:

1. With the in-situ method, the following components may cause incorrect reading and/or damage to the Zirconium Oxide sensor, such as: moisture, SOx, dust, freon and fluorine gas, combustible materials, silicon compounds, HCI and Cla. With the extractive method, harmful substances are removed by sample conditioning prior to analysis.

2. Since the in-situ sensor is directly in the stack, process must be shut down for sensor repair. The extractive method is remote from stack and repair will not hinder stack operation.

2-6

, Fumaces

3. As the in-situ sensor must be calibrated remotely, this is typically done with microprocessor-based electronics. These electronics are typically beyond the scope of field repair and must be sent to the factory for repair, resulting in lengthy instrument downtime.

Recommendations for Flue Gas Analyzers

A) An extractive flue gas analyzer system is recommended for the crude furnace, vacuum furnace, and the debutanizer (DB) fired heater. These three furnaces are in the same area. A single extractive analyzer with up to twelve (1 2) sampling point digital sequencing, can be used to analyze the flue gas from each probe point periodically, according to selected time intervals. This system is suitable for Class I, Division 1 area classification. Figure 2-3 illustrates the position on the furnace where the sample probes are to be inserted. The sample points in the radiant section can be used to measure the excess air. The sample points in the stack are used to evaluate the amount of air leakage to the stack.

8) Other Furnaces and Boilers. For other fired heaters and boilers in URC, a portable analyzer is recommended for quick spot checking.

It is important to remember that just to have these analyzers installed is not sufficient to guarantee adequate excess air percentage and improved combustion efficiency. The operators have to be trained to pay attention to these measurement and to take proper action once an abnormal condition occurred.

Based on a plant wide average of 50% excess air, which if reduced to 20% results in a fuel savings of 28 MMBtu/hr. The estimated payback for the installation of flue gas analyzer is less than 2 years.

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3 STEAM SYSTEM

Introduction

URC consumes a large amount of steam in various plant operations. The steam system is modeled on the EPRl software “APLUS (Analysis of Plant Utility System), written by TENSA Services, to obtain an overall picture of the system. The APLUS program solves the heat and mass balance of the entire steam system. It calculates the BFW make-up water requirement based on the prescribed boiler steam generation, blowdown percentage, and condensate return condition. The steam and water flow rates are in Ib/hr in Figure 3-1. A detailed description of the modeling is attached at the end of this section. From Figure 3-1, it is obvious that the steam system is not operating efficiently in the following areas:

1. The percentage of condensate recovery is too low. Only 25% of the condensate returns to the boilers. The low return causes more make-up water and steam requirements in the deaerator, which eventually reduces the overall efficiency of the steam system. Condensate recovery is a major area of improvement that need to be focused on.

2. There is 49,765 Ib/hr of steam lost by the back pressure turbine exhausting to the atmosphere. This loss of steam to the ambient also contributes to the overall low condensate recovery of the steam system. Replacing these turbines with electrical motors will result in big savings for the plant.

3. The estimated 69,116 Ib/hr of tracing steam consumption is large for this size of refinery. Steam must be leaking through steam traps on the tracing.

Recommendations Toward Steam System Efficiency

Several areas in the steam system can be improved to increase its efficiency. Due to these large losses, URC is considering installing an additional boiler to meet the demand. The following strategies are geared toward more efficient usage of steam:

3-1

20326 6712

4 I Reformer

Dea.

43088 9000

Condensate Loss

4

52396

560 . b7500 . h057S.

+ v condensates Goes to Sour Water

All Steam Users Condensates Are Dumped

1

373766 7

995

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,115,800

691 16 Tracing

I 953

38000 MainDea.

1 d116C 1

Figure 3-1 100 GPM Poly. Wash Alky. wash,

Gasoline Wash, OVHD. Exe. I BFW Make-up (110 F)

i

Steam System Flow Chart

* * Steam System

1. Replacing steam turbines with motor drive

a. Some turbines which are running 100% of the time, are exhausting to the atmosphere. The following list summarizes these candidates:

Service I b/hr HP LVGO 485 9 VAC BOT 790 15 Sour Water 100 2 MCWCR 1,050 20 Crude Top Reflux 675 12 #8 Well 5,250 95

#4 Boiler Fan 6,000 109 #4 Boiler Steam Drum 1,200 22

Alky Comp. Hot Well 1,000 18

Total 1 6,550 302

These replacements are estimated to payback in less than two years.

b. Some turbines which are used as back up and are used only 50% of the time are listed below:

Ib/hr HP Crude Pump 3,750 68 Prefrac. Reflux 525 10

~~ ~

610 Tank 1.965 36 Total 6,240 114

This replacement is estimated to payback in less than 2 years.

c. Turbines which are running only 33% of the time are listed below:

I b/hr HP FCC Cooling Tower 14975 272 MID Cooling Tower 12000 21 8 Total 26975 490

This replacement is estimated to payback in less than 2 years.

d. Air Blower Steam Turbine Replacement. The condensing turbine to drive the air blower has an estimated actual steam rate of 1 I .02 Ib/HP-hr. This is equivalent to generating electricity at $0.074/Wh. This is higher than the current rate offered by local utility. This turbine can be

3-3

Steam System t

replaced by motor drive. This replacement is estimated to payback in less than 2 years.

There is also potential for converting some of the steam turbines to 15 psig back pressure turbines to provide low pressure steam to the deaerator. URC should make judgment on this option after evaluation of the proposed replacement.

In summary, the plant has a potential of saving 67,765 Ib/hr of steam consumption, by replacing these steam turbines with electrical motors. This will increase the electricity consumption by 1,945 KVV.

2. Condensate Recovery

From Figure 3-1 , there are several areas of condensate loss which can be recovered to enhance the condensate return percentage and improve overall steam system efficiency.

a) Reformer Deaerafor Area. There is 9,000 Ib/hr of steam condensate being dumped to the river and glade in the reformer area as shown in Figure 3-2. Condensate is being dumped because several steam traps and the condensate return system are undersized. URC is correcting these problems.

Currently, the reformer deaerator works as a flash drum. According to the APLUS simulation, there is 6,712 Ib/hr of flash steam being exhausted to the atmosphere. URC is installing a new flash drum to flash off 50 psig steam, which will be used in the nearby sour water stripper (SWS). This will save an estimated 3,000 Ib/hr of steam.

The reformer deaerator also needs to be modified to work properly. The modification includes a new motor with 120 HP to replace the old motor with only 75 HP. No change is required except a large impeller.

All these changes in the reformer deaerator area will cost $140,000. Annual savings are estimated to be $152,000.

b) Tanks 237,238 area. There is 24,000 Ib/hr of steam usage for tank heating in Tanks 237 and 238. The condensate is not recovered. URC is considering installing a new hot oil heating system to replace the steam coil heating.

c) Steam Turbine Exhaust. Many of the steam turbines are exhausting to the atmosphere, resulting in significant loss of condensate returning to the boiler. The replacement of steam

' Steam System

turbines with electric motor will cut down the exhaust steam loss, and increase the condensate return percentage.

3. Wash Waterusage

Figure 3-1 shows that 100 GPM of water from deaerator at 225°F is used at poly wash, overhead exchanger, alky wash, and gasoline wash. However, only at poly wash is the hot treated water required. The other usage can be replaced with ambient treated water. By modifying the wash water piping and adding two water softeners for water treatment, URC can save 80 GPM of hot water from deaerator. Annual savings are over $21 5,000. This change will also ease the over-loading situation at the main deaerator.

Summary

A new APLUS simulation is summarized in Figure 3-3, assuming all the aforementioned efficiency measures are carried out. This will leave URC with plenty of steam generation capacity for expansion and addition of new units. The condensate return percentage has increased to 41 % from the present 25%. Deaerators steam requirement dropped from 57,221 Ib/Hr to 25,473 Ib/Hr. These changes also eliminate the need for a new boiler purchase. URC is already considering recovering heat from the reformulated gasoline to preheat BFW to 154°F. This change is not included in the simulation.

3-5

Reboilers

t Various Steam Traps

I

1 9,000 lbhr Condensate being dumped to river, glade, grade, etc., because of condensate return line limitations.

Figure 3-2 Reformer Deaerator

N.C.

7 L

Reformer Deaerator I at 30 psig

I

BFW Make Up From Boiler House Deaera tor

7 N.0.

A Boiler Feed Water to No. 5 Boilers Crude and Reformer 7 SteamDrums

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Steam System 1 8

Description of Modeling of URC Steam System

Figure 3-3 illustrates the steam system in URC. There are nine (9) boilers shown on the diagram to signify all the steam generation equipment in the plant. The detailed boiler information and steam generation are listed below. This information was extracted from an Audit Report performed by Betz Industrial Company.

BL3-- B L4-- BL5-- RFB-- SUB-- CRU--

DEL-- FU2- SSB--

Boiler 1,2,3, 225 # Pressure, I 17,780 Ib/hr, 7.69% blowdown. Boiler 4, 225 # Pressure, 1 15,800 Ib/hr, 7.69% blowdown. No. 5 boiler, 300 # Pressure, 34,530 Ib/hr, 7.69% blowdown. Reformer Boiler, 225 # Pressure, 36,620 Ib/hr, 5% blowdown. Sulfer boilers, 225 # Pressure, 4,400 Ib/hr, 7.69% blowdown. Steam generation in the crude unit. Including FLUX SG, HGO SG, and crude furnace, 225 # Pressure, 40,960 Ib/hr, 7.69% blowdown. DELTAC boiler, 225 # Pressure, 40,940 Ib/hr, 7.69% blowdown. #2 Furnace boiler, 225 # Pressure, 6,920 Ib/hr, 7.69% blowdown. Slurry steam generators, 225 # Pressure, 33,250 Ib/hr, 12.5% blowdown.

The steam users are grouped to simplify the diagram. For example, all steam users whose condensate are dumped is grouped into FU2. All steam turbines used only 33% of the time is grouped into ST6. The following list summarizes these steam users in the plant

ST1 --

ET1 --

ST3--

ST4- ST5- ST6- PUI--

PU4--

RB1--

Condensing steam turbine for the FCC main air blower, 18000 Ib/hr steam flow rate. Exhausted to graham surface condenser CNI to produce 90" F condensate. 2 stages steam turbine. 25,000 Iblhr steam flow rate. 16,000 Ib/hr exhaust at 40 # for process usage at PU3. 9,000 Ib/hr exhausts from the 2nd stage and is then condensed in the condenser CN2 to generate 90" F condensate. ,Include two steam turbines at boiler house (8,250 Ib/hr), and FCC deaerator (2,750 Ib/hr) to drive BFW pumps. Steam turbines running 100% of the time and exhaust to atmosphere. Steam turbines running 50% of the time and exhaust to atmosphere. Steam turbines running 33% of the time and exhaust to atmosphere. Represents all the stripping steam usage. Condensate goes to sour water. 40,575 Ib/hr. Represents the process users of lsom Regen. Vap.(560 Ib/hr), Vac. Vent Reboiler (550 Ib/hr), and SRUI Rx. Reheat (450 Ib/hr). Condensate is recovered and returned to the main deaerator (DAI) through Boiler feed water mixer (BMI). 58,800 Ib/hr steam flow rate. For all the reboiler usage in the reformer. Condensate are collected in a splitter SP3, from where about 9000 Ib/hr were dumped through S21 due to limitation on the size of condensate return line.

3-8

* Steam Sysfem

PU2-- 37,500 Ib/hr steam usage. Includes steam users where condensate are dumped: 237TK coil (12,000 Ib/hr), 238 TK coil (1 2,000 Ib/hr), pretreater LSR reboiler (1 2,500 Ib/hr). 15,350 Ib/hr steam usage. Includes Propane dryer (1,250 Ib/hr), Alky Dgp Reb (7700 Iblhr), DIB upper reb (5,900 Ib/hr), and olefin feed heater (500 Ib/hr). These condensate are collected and flashed in FL3. Liquid from FL3 is then send to mixer (MX5) along with 90" F condensate from the graham condenser. The vapor from FL3 is vented to the atmosphere through SH7.

FCC-- FCC deaerator. Provide 38,000 Ib/hr of BFW to SSG. It also takes I O # steam from SH5.

DAl-- Main boiler house deaerator. Provide about 420,000 Ib/hr of BFW for boilers and wash water.

PU3--

There are three (3) deaerators in the steam system: the main boiler deaerator, reformer deaerator, and FCC deaerator. The APLUS simulation uses a flash drum to represent the reformer deaerator as it is actually functioned as a drum. The boiler feed water make-up enters the steam system at 110°F after picking-up heat from the cooling water system and boiler blowdown heat exchanger. A detailed stream information showing the APLUS results is attached at the end of this section.

3-9

.

4 DIB COLUMN HEAT PUMP

Introduction

TENSAs experience in process optimization has shown that Deisobutanizer (DIB) is a good candidate for Industrial Heat Pump (IHP) application. In this study, the DIB column of the alkylation unit in URC is to be examined and evaluated for its IHP potential.

Base Case

To establish a basis for comparison, the plant operating data of the DIB column is first simulated. The attached Figure 4-1 is a simplified process flow diagram of the DIB column. The alkylation reactor effluent, which contains alkylate and unreacted IC4 and NC4, is fed to the DIB column to obtain 70-75% purity of IC4, as overhead product of the column to be recycled back to the reactor. There are two other feed streams to the column, one from the alky splitter bottom and the other from IC4 storage. The NC4 component is drawn as a side vapor product from the column. Alkylate is drawn as the bottom product.

There are two reboilers for this column. The upper reboiler provides 14.3 MMBtu/hr of heating duty. The rest of 4.6 MMBtu/hr is provided by the lower reboiler. Table 4-1 summarizes the comparison between plant data and simulation results. The simulation results have been consistent with the plant measured data on all crucial parameters. The only discrepancy is in the column’s bottom temperature, which is believed to be caused by the difference in the heavy component composition of the column feed stream. The simulation also shows that a reflux ratio of 0.21 5 is required compared to the plant data of 0.1 7.

4-1

D1B Column Heat Pump a ,

Table 4-1 Base Simulation of DIB Column

Plant Test Data Simulation Reflux ratio 0.17 0.21 5 Upper reb. duty (MMBtu/hr) 14.3 14.3 Lower reb. duty 4.6 4.6 AP (PSI) 8 8 Top tray temp. (OF) 153 152.4 NC4 draw (OF) 176 180 Umer reb. return (OF) 225 228 Bottom (OF) 31 7 347 Total Overhead( I b/hr) 77946 77562 Vol.% CQHs 2.6 2.4 C-HF: 0.1 0.1 IC4 70.8 70.8 NC4 24.7 25.4 IC5 1.9 1.3 NC5 0 0 c6+ 0 0 NCA Side Draw(lb/hr) 6738 6757 VOl. % C3H8 0 0 C3H6 0 0 IC1 6.8 4.5 N CA 89.9 91.2 ICs 3.2 4.0

c6+ 0 0.2 Bottom ( I b/hr) 341 02 341 59 VOl. % C3H8 0 0 CQHF: 0 0

0.1 0.1

IC5 8.3 8.8 NC5 0.3 0.3 c6+ 83. I 84.2

4-2

SGRU Debutanher- OVHD

Aiky Deprop. OVHD or Poly Deprop. OVHD

- -

E GI 3 - -

IC4 Storage

From e IC4 Storage

I NC4

Alkylate

Figure 4-1 Existing Configuration of IC4 Separation

Dl6 Column Heat Pump 8

Heat Pump and Pressure Reduction Operation

The DIB column heat pump schematic is shown in Figure 4-2. The heat pump takes the overhead vapor of the DIB column, compresses it to a higher pressure to raise its condensing temperature. The pressure is raised high enough so that when the overhead vapor is condensed, it will provide heat to the column’s upper reboiler.

One advantage of the heat pump is that it allows the column to operate at a lower pressure than its normal operating pressure. The two factors that may set any column pressure are: a) the pressure required for the vapor (in case partial condenser), and b) the temperature required for condensing the overhead vapor with cooling water or air. The heat pump allows the column to be operated at lower pressure because the overhead condensing is no longer restricted by the temperature differential between the overhead vapor and cooling medium. Instead, the majority of the overhead condensing heat will be transferred to provide reboiler duty. Due to improved separation at lower pressure, the energy is saved by operating the column at a lower pressure. Another advantage of column pressure reduction is that it can reduce the column flooding by about 20%. This is much needed increase in capacity which URC will like to have since the column is nearly flooded at present. The energy saved at low pressure operation is obtained by comparing the difference in reboiler duty between the base simulation and the simulation at reduced top column pressure of 60 psia. The product specification has been kept the same in both cases. Table 4-2 summarizes the energy savings due to pressure reduction operation along with the heat pump placement. The heat pump is sized to take 60% of the overhead vapor through the compressor. The remaining 40% of the overhead vapor still goes through the condenser to be condensed. Energy savings and compression power requirement are also summarized in Table 4-2. Heat pump operation not only saves hot utility but also cold utility at the top condenser. A typical cost of $0.3/MMBtu has been used to evaluate the cold utility savings. Table 4-2 summarizes the heat pump economics. Without giving credit to the capacity increase, the heat pump system can payback in less than 2 years.

4-4

A 1 1 - 1 - 1 1 1 1

- 1 I

Compressor I

DIB

Upper Reb.

f

N Lower Reb.

I

Figure 4-2 DIB Heat Pump Schematics

DlB Column Heat Pump * I

Table 4-2 Heat Pump Economics For The Current Configuration

Cost of Steam ($/IO00 Ib) 5

Pressure Reduction Savings (MMBtuIhr) 3.7

Heat Pump Hot Utility Savings (MMBtuIhr) 7.27

Total Hot Utility Savings (MMBtuIhr) 10.97

Total Cold Utility Savings (MMBtu/hr) 7.42

Compressor Work (Hp) 420

Total Hot Utility Savings ($/yr) 471,710.00

Total Cold Utility Savings ($/yr) 19,143.60

Compression Cost ($/yr) 107,637.60

Net Savings ($/yr) 383,216.00

Investment ($)

Installed Compressor Cost 395,100.00 (including 50% of the equipment cost for installation) Installed Motor Cost 54,000.00 (including 50% of the equipment cost for installation)) Installed Reboiler Cost 54,000.00 (including 50% of the equipment cost for installation)) Piping & Instrumentation 40,000.00

Engineering 60,000.00

Total 603,100.00

- Payback (yrs) 1.6

4-6

’’ DIB Column Heat Pump

New Column Configuration

The current DIB column produces about 70% purity of IC4 at the top. There is a large amount of NC4 being carried at the top (about 25%) and is feeding back to the reactor. The presence of NC4 in the reactor not only reduces the effective reactor volume but also inhibits the rate.

In order to reduce the amount of NC4 being circulated in the reactor, a new way of removing NC4 from DIB column is considered as shown in Figure 4-3. The new configuration differs the old configurations (Fig. 4-1 ), by taking the Depropanizer bottom to the DIB column and by taking the reactor effluent to an idle existing column (30 trays, 42” diameter). The new configuration allows the DIB column to obtain much purer IC4 from the top, and most NC4 comes out at the bottom. The effect of this better separation of IC4 and NC4 are many folds:

1.

2.

3. 4.

It reduces the amount of NC4 being fed to the reactor (25.6 Ib molelhr, compared to 340 Ib mole/hr). It unloads the DIB column for more thruput (88% flooding compared to existing

It increases the alky reactor capacity and reaction rate. The DIB column will have a smaller temperature difference between top and bottom. Therefore, it will be even more attractive for heat pump placement.

100%).

Table 4-3 summarizes the simulation results of the DIB and the new columns. Also shown are the corresponding performance in the current DIB configuration.

New Configuration Pressure Reduction and Heat Pump Evaluation

The principle of heat pump and the benefits of pressure reduction in the new configuration, are the same as described in Section 4.3. Table 4-4 summarizes the economics of heat pump on the new DIB column. The heat pump takes 70% of the overhead vapor to provide enough heat for the reboiler duty.

4-7

SGRU -+ Debutanizer OVHD

I

I I I I I I I I I I I I I

r I I I I

1

IC4 Storage - - -

~ l k y w a t e r fl Washw 3 -a.

‘r-

Figure 4-3 New Configuration of IC4 Separation

Alky Deprop. OMID or Poly Deprop. OVKD

c 3

NC4

Alkylate

' DIB Column Heat Pump

Table 4-3 New Configuration Simulation

New DIB Current DIB Top Temp. (F") 147 Bottom Temp. (F") 170

Reflux Ratio 2.56 Reboiler Duty (MMBtu/hr) 12.0 18.9 Top Product (Iblhr) IC4 22982 54386 NC4 1491 19732 Bottom Product (Ib/hr) IC4 212 303*

Flooding (%) 88 100

NC4 6095 61 63* (*Side draw product)

New Column

Top Product (Ib/hr) Reboiler Duty (MMBtu/hr) 9.8 --

IC4 23267 NC4 1041 Bottom Product (Ib/hr) ICr 63 21 NC4 31 2266 AI kylate 301 98 31 872

As expected, the compression power reduces to 360 HP because of smaller temperature lift between column reboiler and condenser. At $5/MMBtu of steam cost, the heat pump system can payback in less than 3 years. This savings estimate is based on the new configuration already in operation. No cost for erecting the new column and other necessary accessories are included. The comparison is solely from the energy savings point of view. No credit has been given to the increased alky reactor capacity and reaction rate. A more detailed study on the proposed configuration should lead to a better assessment of these effects on the overall benefit to the plant.

Summary

A preliminary evaluation of industrial heat pump operation on the DIB column has indicated a very good economic payback, in both the current DIB , and a new DIB configuration. All the comparisons are based on rigorous column simulation. URC is

4-9

DIB Column Heat Pump # I

currently limited by DIB capacity along with other restrictions, but increasing the DIB capacity is certainly the direction of the immediate future.

The current configuration with heat pump installation can increase the capacity by 20% without adding a new column and its accessories. With feed tray optimization and tray hydraulic review, it is possible to increase the column capacity by 25%. This increase will give URC a corresponding FCC rate of 25,000 BPD. This has been the goal of many related upgrading projects.

Other benefits of a heat pump system including NOx, SOx, and COz reduction in flue gas emission, which is directly proportional to the amount of fuel fired in the boiler. Heat pump system also reduces the load on the flare system by automatically shutting down the heat supplied to the reboiler in case of an emergency. This could be a tremendous savings in upgrading the flare system. All these benefits have not been credited in the economic analysis. In view of all these benefits, URC should seriously consider implementing the heat pump system. A detailed engineering design package should be developed to firm up all the details of the heat pump system.

Table 4-4 Heat Pump Economics For The New Configuration

New DIB column reboiler duty (MMBtuIhr)

Heat pump savings on new DIB column (MMBtu/hr)

12.0 New column reboiler duty (MMBtu/hr) 9.8 Current DIB column reboiler duty (MMBtulhr) 18.9

9.0 Net hot utility savings on new configuration 6.1 heat pump system (MMBtu/hr) 18.9 - (12.0 + 9.8 - 9.0) Total cold utility savings (MMBtu/hr) 5.6 Compressor work (Hp) 360 Total hot utility savings ($/yr) 262,300.00 Total cold utility savings ($/yr) 14,448.00 Compression cost ($/yr) 92,260.80 Net savings ($/yr) 184,487.20 Investment ($) Compressor (including 50% of the equipment cost for installation) 330,000.00 Motor (including 50% of the equipment cost for installation) 45,000.00 Reboiler (including 50% of the equipment cost for installation) 54,000.00 Piping & Instrumentation 40,000.00 Enaineerina 70.000.00 Total 539,000.00 Payback (yrs) 2.9

4-10

5 FCC Main Fractionation Unit

Process Description

Figure 5-1 illustrates the process flow diagram of the FCC main fractionation unit. The fresh gas oil feed from a storage tank is heated to 355OF, by successive heat exchange with overhead vapor, naphtha circulation, LCO product and slurry product in the fractionation section. The feed is then further heated to 514°F by a fired heater (350- H102), before flowing to the reactor.

The feed to the main fractionator is the FCC reactor products which enters at the bottom of the column. A light cycle oil (LCO) pumparound stream is taken as a side stream to provide heat to the poly depropanizer and debutanizer reboilers. Another heavy cycle oil (HCO) pumparound stream provides heat to the poly charge stream, gas concentration debutanizer and gas concentration stripper reboilers. LCO product is taken from a side stripper (TI 05) and used to preheat the feed before being sent to storage. A naphtha pumparound stream is used for feed preheating. The bottom slurry is used to generate steam in the steam generators (E-I02 A-C). A split stream of the slurry is used to further preheat the column feed to 355°F.

Figure 5-2 shows the existing heat exchanger network of the FCC main fractionator unit on a grid diagram. Each stream with arrows pointing to the right is a hot stream which needs to be cooled. Streams with arrows pointing to the left are cold streams which needs to be heated to the desired temperature. The dumbbells represent heat exchangers between hot and cold streams.

The overhead stream is simulated to obtain the condensing duty of heat exchangers E117, E107, and E l l l .

The measurements on each heat exchanger inlet and outlet temperature are used to obtain the log-mean temperature of each exchanger. The overall heat transfer coefficient for each exchanger was calculated based on the known surface area, and log-mean temperature difference. This information is also used in the targeting phase of pinch analysis.

5-1

0 .r( Y

-

E117 E107 E l l 1 -n+

Frac. OVHD

Slurry

LCO Reflux

LCO

Naph. Cir.

HCO Reflux

L Y 1

712 476 I

490 A

r+ 353 ;5

24 I I*'

13B L

........ ..:.:.:<.:*. .:.:.:FA.:.:, .'...> .x.:.>:., .... ::...:.:. ..:.:.:.:.:2.:. $$$.?x+ .......... T

353 PolyDeC3 4

103 284

3703107 I

I 252 I

I 3513104

)E@z@!+ 12.7 19.8 13.3

A El05 E103A

Poly DeC4

Poly Charge

Gas DeC4

Gas Stripper

Figure 5-2 Existing Heat Exchanger Network

@-@+ E112

6.43

358

149

I t r , FCC Main Fractionation Unit

Analysis of the Current “Base Case” Operation

An important result of the pinch technology principles is the ability to set performance targets prior to the actual design. It is possible from the process data alone, to confidently predict the minimum thermal energy and surface area requirement of any process.

Starting from the individual streams, it is possible to construct one “composite curve” of all the hot streams in the process, and another for all the cold streams by simple addition of the heat contents over the temperature intervals in the problem. Figure 5-3 shows these curves for the FCC base case. The overlap between the two composite curves represents the maximum amount of heat recovery possible within the process. The “over-shoot” of the cold composite represents the minimum amount of external heating (hot utility) requirement. The “over-shoot“ of the hot composite represents the minimum amount of external cooling (cold utility) requirement. The closest point between the two composite curves is known as the “pinch” point. The temperature approach between the composite curves at the pinch is defined as “DTmin)). As DTmi” increases, utility requirements increases, however, the heat exchange surface needed to recover the energy decreases as a result of the larger approach temperature. For any DTmi”, the composite curves define the minimum utility requirements for the process and thus establish the energy targets for the process.

The Grand Composite Curve (GCC) is a plot of the interval temperature versus heat flows through the intervals. The GCC is derived from the composite curves. The net heat flow is zero at the pinch. From the GCC, the levels of hot and cold utilities required for the process can be identified (for details refer to Appendix A).

The GCC for the base case of FCC Main Fractionation is shown in Figure 5-4. This is a typical “threshold problem, no hot utility is required from outside the process. The process itself produces enough heat to supply its own needs. From practical application, this means that the FCC fired heater could be eliminated. However, to meet the steam demand in the plant, the heat source available from the slurry stream is used to generate steam. If the modification recommended in the steam system is followed through, the steam demand in URC will be reduced drastically. This will allow URC to use the slurry heat to preheat the reactor feed and eliminate the fired heater totally. Even with current mode of operation, where only part of the slurry heat is used to preheat the reactor feed, there is some energy savings potential. This can be achieved by increasing heat exchanger surface area. The following sub-section describes in detail the maximum savings potential.

Optimum Energy Recovery

To evaluate the optimum energy recovery potential, a pinch analysis is again performed on those streams with potential for increased heat integration.

5-4

O t 9

0 t (v

OOT-

a tn tu u a

m u u Er k 0 y.l

tn

k u a 4J

:

!! a

4 * I ,

FCC Main Fracfionation Unit

The streams that have been used for heat recovery like LCO reflux and HCO reflux are removed from the analysis. Also removed are those heat sinks for LCO and HCO reflux like Poly DeC4 and Gas DeC4, etc. The heat exchanger information is summarized in Table 5-2. Figures 5-5 and 5-6 show the composites curve and GCC respectively. As the DTmi, varies, the amount of direct heat integration and the corresponding exchanger surface areas also changes. Figure 5-7 shows the hot utility vs. surface area plot.

Table 5-2 Heat Exchanger Information Summary

Heat Exchanger ATin Area Q U

E-I 17 57.9 18,020 12.7 12.2 (OF) (ft*) (MMBtu/hr) (Btu/hr- ff-OF)

E-1 16 20.9 8,828 4.3 23.3

E-1 03B 134.1 1,206 1.8 11.1

E-1 04 261 4,692 9.2 7.51

E-1 07 NA 19.8

E-I05 + E103A NA NA 7.3

E-1 12 NA NA 6.43

Point “A” on Figure 5-7 represents current level of integration. From Figure 5-7 it is evident that the optimum heat recovery is at Point “B.” Beyond Point B, further increase in the surface area will not be economical. Point B corresponds to a DTmin of 20°F, with pinch interval temperature of 281 OF. The pinch design rules are then followed to obtain the optimum design change. Figure 5-8 shows the revised network design. An increase in surface area on E-1 17 will allow E-1 17 to transfer more heat to the gas oil feed. The net effect is to save 1.6 MMBtu/hr of hot utility at the FCC fired heater and the same amount of cold utility from the cooling water. However, the big advantage in increasing the surface area through one additional shell on E-1 17 is to reduce the pressure drop of this exchanger. A 4500 HP wet gas compressor is currently used down stream of overhead gas stream. Increasing the suction pressure by about 2 psig can reduce the compression power by about 300 HP. The estimated savings for utility and compressor power reduction is $14I1212/yr. An investment of $1 803 60 for installing the additional 4504 ft2 shell on E-1 17 is required. This system will have a payback in 1.3 years.

5-6

W > U 3 0

w I-

cn 0

z 0 0

Z

CT El

H

a.

a a

oz9 00;-

COMPOSITE CURVES

0 t t

n u. Q W cl W

E8 3 N t- U U W a x W I-

O m

Figure 5-5 Hot and Cold Composite Curves for FCC Modified Case

I ' I .

a a a UJ

I- z

> > I-

-I

t- 3

I- O I

H

W

H

m a, 2

k a, m c m 4 X w

Frac. OVHD

Slurry

LCO

Naph. Cir.

29 1 1

712 478 I

439

353

/a7

E103B r\ 291

J E116 n 291

J

Gas Oil F e e d 4

21.7

Figure 5-8 Revised Heat Exc

h4

ianger Network

- E105 E103A

@-@+ E112

1 149

* 1 , . FCC Main Fractionation Unit

Discussion

1.

2.

3.

The calculated overall heat transfer coefficients in Table 5-2 are low compared to most design values. For instance, the overall heat transfer coefficient calculated between slurry and feed is 7.51 , compared to a similar design value of 49. The U values for E-l03B and E-I 16 are expected to be about 30, but were found to be much less. Apparently, these heat exchangers are badly fouled. Proper cleaning and maintenance schedules should be followed to ensure satisfactory performance on these heat exchangers.

There is still plenty of medium level heat available at E-107 and E-105, which are dissipated through cooling water (E-I 07) and air (E-I 05). No low temperature process sink can be used within FCC to recover this heat. However, the BFW make-up can be used to pick up some heat from the overhead gas in E-107. Other low temperature sinks such as the sat gas feed stream in the alky unit and olefin feed to the alky depropanizer can also be used to pick up more heat from these two heat sources.

The FCC fired heater can be totally eliminated if the recommendations in the steam system are carried out and the steam demand reduced. In that case, the slurry heat will not be used to generate steam, instead it can be entirely used to preheat the feed to the FCC reactor.

5-12

b

A INTRODUCTION TO PINCH TECHNOLOGY

This Appendix provides an introduction to the basic concepts and terminology associated with "pinch technology". It also demonstrates the usefulness of pinch- based methods for industrial heat pump and heat engine placement. This is intended for readers unfamiliar with these technologies, to provide the necessary background for a general understanding of the main sections of this report.

A bibliography is attached to this appendix. It highlights recent articles that present a more detailed discussion of pinch technology and its application to heat pump placement and related subjects, such as:

e Overall Energy Efficiency (I),

0 The Design of Heat Exchanger Networks (HEN's) (2),

0 Integration of Heat and Power Systems with Chemical Processes (3),

e Heat integration of Distillation Systems (4), and

e "Appropriate Placement'' of Heat Pumps in Chemical Processes (5,6,7,8).

Process Heating and Cooling

Within most processes in the chemical and allied industries, there are streams that require heating and streams that requires cooling. Any stream that requires heating is conventionally said to be "cold" (irrespective to its temperature level), and streams that require cooling are said to be "hot".

The heating and cooling duties within a process can be provided by "utilities" such as steam (for heating) and cooling water (for cooling) that are available on the site. However, the load on these external utilities can often be reduced by "heat integration" of the process - that is, by transferring heat from hot process streams to cold process streams by means of heat exchanger networks (HEN's). This is illustrated in Figure A- 1. As the only heating and cooling duties that incur direct operating costs are those associated with utilities, heat integration generally leads to a reduction in process operating costs.

A- 1

QH (from hot utility)

Process 1-b

Streams 1111111)

In - I

+ Process

Streams

out

QC (to cold utility)

Figure A-I : Heat Transfer Between Process Streams

Using A Heat Exchange Network

A-2

The Heat Transfer Pinch

In most processes, no matter how thoroughly they are heat integrated, there will always be a residual heating duty (QH) and a residual cooling duty (Qc) that have to be met by utility heating and cooling. The size of these residuals can be reduced by increasing the heat transfer area within the process heat exchangers. This essentially allows smaller temperature differences between the matched hot and cold streams. In general, however, the residual utility loads would be finite even if the heat transfer area were infinite.

If both utility heating and cooling are required, the process may be considered to be made up of two parts:

e

e

A higher temperature part which, after complete heat integration, acts as a net heat "sink" or acceptor. A lower temperature region which, after complete heat integration, has surplus heat to be rejected. It is thus a net heat "source".

The temperature that separates the source and sink sections of the process is called the heat transfer "pinch" (Figure A-2). In a properly integrated process, there is no heat transfer from above the pinch to below the pinch. Also, the "temperature driving force" (Le., the difference in temperature between the hot and cold streams) reaches its minimum value, designated DTmin, in the region of the pinch.

When a pinch design is implemented, the hot and cold utility requirements reach their minimum values, QHmin, QCmin, appropriate to the selected value of Dtmin. A few processes do not have heat transfer pinches. These require either only heating or only cooling from external utilities, but not both. Such processes are said to exhibit "threshold" characteristics.

Heat Pumps

Heat pumps provide a means of upgrading heat (Le. raising its temperature) by the input of work. They may therefore be regarded as heat engines running in reverse. The principle behind the heat pump is illustrated in Figure A-3, where an ideal heat pump extracts an amount of heat Q from a temperature TI and elevates it to the temperature T2 by the input of reversible work WREV. The best known real heat pumps are reverse Rankine cycles. Low pressure vapor generated at some source temperature, Tsl is compressed to a higher pressure at which it condenses, releasing its heat at a higher target temperature Tt.

The work input for such a system is generally provided by mechanical compression with the system operating in a closed cycle (Le. the working fluid repeatedly passes through evaporation, compression and condensation stages). This is depicted in Figure A-4.

A-3

QH

Heat Sink

2

I Pinch Temperature

Heat Source

QC

Zero Heat Flow

Figure A-2: The Heat Transfer Pinch

T Q Figure A-3: Basic Principles of the Heat Pump

A-4

Cold Process Fluid

I Condenser

Flash

Evaporator I

Figure A 4 : Closed Cycle Heat Pump

Compressor

Hot Process Fluid

A- 5

Sometimes, it is possible to use a process vapor stream as the working fluid in heat pumps. These heat pumps are called semi-open cycle heat pumps. The most common semi-open cycle (type I), is called the mechanical vapor recompression (MVR) heat pump. The hot process vapors are compressed in a compressor and then condensed in the heat pump condenser to satisfy a process heating requirement at an elevated temperature (see Figure A-5). A less common type of semi-open cycle heat pump (Type 2) has the opposite configuration, i.e., an evaporator instead of a condenser. A liquid stream is vaporized in the evaporator and then compressed to a higher temperature in a compressor (see Figure A-6). This type of heat pump cycle is recommended when a low temperature heat source is available to evaporate a liquid process stream which is required in the vapor phase at a higher temperature. It is important to note that semi-open cycles are only feasible when the process fluid undergoes a phase change; condensation for Type 1 systems, and evaporation for Type 2 systems. These are the main types of heat pumps considered in this report. In addition to these, there are a number of other types of heat pumps either commercially available or under development. These include chemical heat pumps (which use exothermic and endothermic reactions as a means of upgrading heat), absorption heat pumps (which use low grade heat to drive an evaporationkondensation cycle to elevate the available "waste heat" to a useful level) and electromagnetic heat pumps.

Current state-of-the-art heat pumps tend to be limited in the operating temperature range for available working fluids. Moreover, economic considerations generally limit the practical temperature lift in heat pumps to around 60°F.

Appropriate Placement of Heat Pumps

The pinch concept leads to useful insights into the appropriate use of heat pumps in industrial processes. Because the below pinch region is a net heat source any heat pump must accept heat in this region if it is to reduce the external cooling requirements of the process. By a similar argument the heat pump must reject its heat to the net heat sink above the pinch to reduce the demands on external utility heating. A heat pump which satisfies these criteria is said to be "appropriately placed" (Figure A-7).

If a heat pump acts wholly above the pinch, it will reduce the hot utility requirement QH by an amount equal to the work input W of the heat pump (see Figure A-8). However, as the unit cost of providing work is normally greater than the unit cost of heating, such an arrangement is generally uneconomical. A heat pump acting entirely below the pinch (Figure A-9) has the net effect of degrading the work input W into waste heat that has to be rejected to the cold utility Le. the net heat rejected rises from QC to QC + W, which is clearly undesirable.

Both Figures A-8 and A-9 represent "inappropriate placement" options for industrial heat pumps.

A-6

QD Heat Sink

I W

Tpinch I zero A

QA Heat 4 Source

I

Figure A-7: Appropriate Heat Pump Integration

A-8

QD W

W

Source v Figure A-8: Inappropriate Heat Pump Integration-above pinch

I Sink Heat I QD I

c I Heat Source Q* IT!

Tpinch

Tpinch

W

Figure A-9: Inappropriate Heat Pump Integration-below pinch

A - 9

The Grand Composite Curve (GCC)

As already noted, most industrial processes can be divided at a "pinch temperature" into net heat source and net heat sink regions with no heat flow at the pinch itself. However, it is possible to represent the net heat flow at every temperature level within the process by means of a "Grand Composite Curve" (GCC) or temperature enthalpy plot. An example of such a plot is given in Figure A-1 0.

The ordinate of the GCC is the so-called "interval temperature." This is a convention to put the hot and cold streams on a common temperature basis, after allowing for the necessary minimum temperature driving force (DTmin) between them. Consider the simplest case, where the heat transfer resistance associated with all the hot streams is equal to that associated with all the cold streams. The interval temperature of a hot stream at an actual temperature of TH is defined to be TH - (DTmin/2); and that of a cold stream at an actual temperature of TC is TC + (DTminR). Where the heat transfer resistance of the streams are different, it is necessary to ascribe an appropriate "DTmin contribution, "DTcont, between 0 and DTmin, to each stream. Heat transfer between such streams is permitted only if (TH - Tc) > DTmin Le. if the interval temperature of the hot stream is greater than or equal to that of the cold stream. The abscissa on Figure A-I 0 represents the net heat flow through the process after allowing for all permitted heat integration of process streams. This takes the value of zero at the pinch, as described in the earlier discussion, and has the values of QH (Le. net hot utility requirement) at the highest interval temperature in the process and QC (Le. net cold utility requirement) at the lowest interval temperature.

The GCC is important in evaluating heat pumping opportunities because it allows a rapid assessment of the temperature levels available, and the amount of heat that can be heat pumped in a process. Thus, in Figure A-I 1 an amount of heat QA can be accepted by a heat pump from the process at an interval temperature TA below the pinch. An amount of heat QD = QA + W can then be delivered to the process above the pinch at interval temperature TD.

Hot and Cold Composite Curves and Area Targeting

The effect of heat integration on the process utility consumption and temperature driving forces is shown in the form of hot and cold composite curves in Figure A-12. The "hot composite curve" represents the summation of the heat loads associated with all streams that have to be cooled in the process ("hot" streams) and similarly, the "cold composite curve" represents the summation of all heating loads (Le. "cold" streams). DTmin, the minimum temperature difference between the hot and cold composite curves, appears as the vertical distance between the hot and cold composite curves at their point of closest approach. DTmin is a measure of the level of heat integration.

A-1 0

pinch T

Q = Hot Utility Load

Q = Cold Utility Load

Ti = Interval Temperature

H = Enthalpy

H

Figure A-10: The Grand Composite Curve

A-1 1

W

T Q D I D /

T A

\ \

Figure A-11: The Grand Composite Curve and Heat Pump Integration

A-1 2

1 1 1 ,

Heat Duty

Heat Duty

Heat Duty

Increasing Heat Integration

Figure A-12: Effect of Heat Integration on Utility Targets and Temperature Driving Forces

A-1 3

Varying the extent of heat integration is represented by moving the hot and cold composite curves horizontally relative to one another. Doing so will change the vertical distance between them at their point of closest approach (Le. the pinch), and thus corresponds to changing values of DTmin. The horizontal displacements between the composite curves at their high and low temperature ends are the corresponding values of QH and QC (the external heating and cooling requirements, respectively) for the process. A decrease in DTmin implies an increase in the level of heat integration. In general, as DTmin decreases the minimum hot and cold utility requirements also decrease. Progressively smaller values of DTmin are represented in Figure A-1 2(a) through A-I2(c). However, a decrease in DTmin also implies a decrease in the overall driving force for heat transfer and a resulting increase in heat transfer surface area requirements.

Figure A-I3 shows a plot of plant heat transfer area and the corresponding minimum hot utility consumption. Curves of this type can be generated for any given process using area targeting algorithms based on pinch technology principles (see below).

The curve shown in Figure A-I 3 separates the thermodynamically feasible region from the infeasible region. The region above the curve and to the right represents a process in which the available heat transfer area is greater than or equal to the minimum needed to achieve a specified hot utility usage level. To the left and below the curve the implied heat transfer area is less than the minimum requirement, implying that no practical process can correspond to any point in the feasible region, e.g. point A. The hot utility consumption and the heat transfer area requirements are directly related to the plant operating costs and capital costs, respectively. Therefore, the inverse of the slope of the straight line joining two points on the curve is a measure of the payback period for going from one level of heat integration to another. This is also illustrated on Figure A-1 3.

The subject of heat exchanger network (HEN) area requires further elaboration. Townsend and Linnhoff (9) provides a useful algorithm for estimating required HEN areas without having to design the HEN in detail. The principles behind the algorithm are illustrated in Figure A-I4 in terms of heat transfer from the hot composite curve to the cold composite curve and between the process and the hot and cold utilities. For a given value of DTmin, there is a certain extent of horizontal "overlap" of the two composite curves. This represents the amount of heat that can be transferred from hot streams to cold streams within the process. Outside of the overlap region, utility heating or cooling is required. All heat transfer is represented as vertical lines on Figure A-14. This is an idealized representation implying that all matched hot and cold temperatures within the process HEN must be the same as the matched temperatures on Figure A-14. However, with this simplifying assumption, it is possible, using appropriate stream heat transfer film coefficients, to predict the minimum area for a HEN with surprising accuracy. For further details, reference (2) should be consulted.

A-1 4

Q~~

Q H C

Existing Plant

I Feasible Region I

1 Decreasing AT

\ c min

sB sC

Heat Transfer Surface Area

I ( s c - S B ) c A

Incremental Payback Period [years] = - ( Q H C - Q H B ) c H

c A

C H

H = Hours of Operation per Year

= Cost per Unit Area

= Cost per Unit of Hot Utility

Figure A-1 3: Hot Utility Consumption Versus Heat Exchanger Area

A - 1 5

250

200

150 c 0

0

- 5 0

- 100

I I

Hot Composite Curve

! I

I

C. Utility Cooling Q~ -1

j / !

I I

I

1 20 4 0 6 0 80 100 0

Cumulative Heat Load (MMBtu/hr)

Figure A-14: Area Targets for the Example Problem

A-1 6

Appropriate/lnappropriate Integration of Heat Engines

Consider the hypothetical process shown to the right of Figure A-I 5. The process pinch and minimum utility requirements (QHmin, QCmin) are shown on the figure. To the left of Figure A-I5 is a representation of a Carnot engine, for which both the heat acceptance and rejection temperatures are hotter than the process pinch temperature. This Carnot engine is assumed to have an efficiency (ratio of power produced to heat absorbed) of 33.3%. This means that for each 3W units of heat absorbed, 2W units of heat are rejected at a lower temperature and W units are converted into work. The heat and work flows associated with the Carnot engine are shown in Figure A-I 5.

The total hot utility requirement for the Carnot engine and process is (QHmin + 3W). This requirement can be reduced by integrating the heat engine with the process above the pinch, see Figure A-16. In the "above pinch" integrated arrangement, the engine exhaust heat displaces the process hot utility usage and the total utility requirement falls to (QHmin + W), a saving of 2W units of heat. Work W has effectively been produced at a marginal efficiency of 100% (neglecting mechanical and electrical losses) since the waste heat from the machine is usefully used to displace process requirements.

Figure A-I 7a illustrates the same process together with a Carnot engine for which both the heat acceptance and rejection temperatures are colder than the process pinch temperature. As in Figure A-I 5, a machine efficiency of 33.3% is assumed. The total hot utility requirement for the Carnot engine and process shown in Figure A-17a is (QHmin + 3W). This requirement reduces to QHmin when the heat engine is integrated with the process below the pinch, see Figure A-I 7b, since the engine heat requirements are supplied by waste process heat.

In Figure A-18, a Carnot engine is shown integrated with the process such that heat is absorbed from above the pinch and rejected below the pinch. In this heat integrated arrangement, the minimum utility requirement is not reduced from the total non- integrated requirements. In other words the heat engine violates the process pinch by transferring heat across it. As a result, the total hot utility requirement of the integrated system (QHmin + 3W) is the sum of the two separate system requirements.

Figure A-I 6 and Figure A-I 7 illustrate the concept of "appropriate" integration of heat engines with a process. Appropriate integration involves operating a heat engine such that the engine heat acceptance and heat rejection are entirely above or entirely below the process pinch but not across the pinch. As the figures illustrate, this appropriate integration leads to substantial reductions in utility requirements over the inappropriately integrated case, Figure A-I 8. Inappropriate integration means the heat engine transfers heat across the process pinch.

A-I 7

Q H = 3W

Heat Engine

eff = 0.33 F W

2w

Pinch Temperature

Q H min

1

QC min

Figure A-15: Stand Alone Heat Engine Operation and Process Demand

A-1 8

Heat Engine

eff = 0.33

2 w

- - Q = 0.0 - Pinch Temperature

Heat Source

1

1 b W

QC min

Figure A-I 6: Appropriate Heat Engine Integration

A - 1 9

Q~ min

Sink

3w Pinch Temperature

Source I, QC min

1 Engine

eff = 0.33

* 2 w

a) Before Integration

W

QH min

Sink

Source L W eff = 0.33

[ Q c min - 3w 1 2w

b) After Integration

Figure A-1 7: Appropriate Heat Engine Integration Below the Pinch

A - 2 0

1 I

3w

I + Heat

Engine eff = 0.33

w

[ Q H min + 3wl

I b

2w

Heat Sink

Q = 0.0 0

Figure A-1 8: Inappropriate Heat Engine Integration

A-21

Placement of Distillation Columns and Evaporators

The rules for placing distillation columns and evaporators are essentially the same as those for heat engine placement. The entire distillation or evaporation system should be either above the pinch, or below the pinch to ensure the maximum scope for beneficial heat integration of the condenser and reboiler heat loads. Placing the system such that the reboiler is above the pinch and the condenser is below the pinch (see Figure A-I 9) is "inappropriate" as it degrades heat across the pinch. The procedure for correcting inappropriate "cross pinch" placement of distillation columns (4) is based on the concept of "pressure shifting". Reducing the pressure of the column lowers the evaporation and condensation temperatures, and so may allow the temperature of an "above pinch" reboiler to be reduced to below the pinch. Conversely, raising the pressure may allow a "below-pinch" condenser to be raised to a temperature above the pinch. In either case, the result is that the "cross pinch" placement is eliminated and both the reboiler and condenser are restored to the same side of the pinch.

Correction of inappropriate evaporator placements uses precisely the same procedure.

Summary

This appendix gave a quick review of pinch technology and its relevance to heat pump and heat engine placement in industrial processes. Methods to determine the appropriate positions for heat pumps and heat engines in any given process have been detailed.

A-22

Heat Sink 1

Figure A-1 9: Inappropriately Placed Distillation Column or Evaporator

Distillation Column

or Evaporator

A-23

References for Appendix A

Boland and E. Hindmarsh. "Beyond HENS: A Total Thermodynamic Approach to High Energy Efficiencies." Chem. Eng. Prog., July 1984.

Linnhoff and E. Hindmarsh. "The Pinch Design Method for Heat Exchanger Networks." Chem. Eng. Sci., 1983, 38, 745-763.

Hindmarsh, D. Boland and D. W. Townsend. "Maximizing Energy Savings for Heat Engines in Process Plant." Chem. Engineering, February 4, 1985, p. 38.

Hindmarsh and D. W. Townsend. "Heat Integration of Distillation Systems into Total Flowsheets - A Complete Approach." AlChE National Meeting, November 1984.

Townsend, J.W. Hill and D. Boland. "The Future of Heat Pumps in the Process Industries." I. Chem E. (NW Branch) Symposium Number 3 on Heat Pumps, 1981.

Ranade, E. Hindmarsh and D. Boland. "Industrial Heat Pumps: Appropriate Placement and Sizing Using the Grand Composite." 8th Industrial Energy Technology Conference, Houston, Texas, June 1986.

Ranade, A. Nihalani, E. Hindmarsh and D. Boland. "Industrial Heat Pumps: A Novel Approach to Their Placement, Sizing and Selection." Presented at the 21 st lntersociety Energy Conversion Engineering Conference, San Diego, Calif. , August 1986.

Chappell and S. J. Priebe. "Process Integration of Industrial Heat Pumps." Presented at the 8th Annual Industrial Energy Technology Conference, Houston, Texas, June 1986.

Townsend and B. Linnhoff. "Surface Area Targets for Heat Exchanger Networks." 1 1 th Annual Research Meeting, The Institution of Chemical Engineers, April 1984.

A-24