EAU901.088.01_Virtual
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Energy Management: Optimizing Site Wide Utilities to Save Energy using Aspen Utilities Planner AspenTech Customer Education Training Manual Application Workshop Number: EAU901.088.01
Copyright © 2015 by Aspen Technology, Inc. 20 Crosby Drive, Bedford, Massachusetts 01730, USA. All rights reserved. This document may not be reproduced or distributed in whole or part in any form or by any means without the prior written permission of Aspen Technology, Inc. The information contained herein is subject to change without notice, and Aspen Technology assumes no responsibility for any typographical or other errors that may appear.
Aspen Technology may provide information regarding possible future product developments including new products, product features, product interfaces, integration, design, architecture, etc. that may be represented as “product roadmaps.” Any such information is for discussion purposes only and does not constitute a commitment by Aspen Technology to do or deliver anything in these product roadmaps or otherwise. Any such commitment must be explicitly set forth in a written contract between the customer and Aspen Technology, executed by an authorized officer of each company.
EAU 901 Application Workshop
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Energy Management - Aspen Utilities Planner
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Energy Management: Optimizing Site Wide Utilities to Save Energy using Aspen Utilities Planner
EAU901 Application Workshop Instructions
EAU901 Application Workshop
Energy Management – Aspen Utilities Planner
Introduction The provision of an adequate and reliable supply of Utilities (fuel, steam and power) represents a significant operating cost for many industrial companies. For many industries, the energy/utilities cost is the largest operating expense after the purchase of raw materials. Aspen Utilities PlannerTM explores the flexibility inherent in the purchase, generation, use and distribution of utilities on industrial sites and advises on the optimum choice available to the user. Issues such as different tariffs, alternative fuels, optimum loading of boilers and turbines, choice of equipment, import, self-sufficiency or export of electricity, choice of drives (motor or turbine) etc. are all taken into account in the optimization. Aspen Utilities provides a model-centric approach whereby a single rigorous model of the utilities system is used to address all the important business processes related to energy management. This workshop demonstrates how the most common energy management business processes can be performed with Aspen Utilities PlannerTM to substantially improve financial performance.
Objective
In this workshop, we will use a pre-build model of a utilities system which is based on a real application. First we shall review the model to familiarize with the utilities system and its equipment. Then we shall show to enter inputs, run the model and view results. Then we shall use the model to perform various energy management business processes : – Optimize Utility Plant Operation: Obtain advice on the optimum load allocation in boilers and turbines and optimum choice of drives (motor/turbine), to minimize operating cost. – Manage New Natural Gas Contract: Evaluate optimum choice of fuels with multi-tier pricing. – Forecast Power and Gas Demands to Provide Nominations: Optimize in advance, internal power generation vs. import, depending on the power price during peak and off peak times. Make “realistic” and “optimal” nominations to your suppliers, which you can fulfill, to avoid penalties. – Convert Production Plan to Utilities Plan: Transfer the weekly production plan into Aspen Utilities and convert this into utility demands using demand
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forecasting correlations. Based on these, produce a utilities production plan, allowing for a turbine to be brought down for maintenance during that week. – Evaluate Capital Investment : Assess the potential cost savings from investment in a new steam turbo-generator and calculate ROI.
We shall provide instructions how to execute each step. We shall review and comment on the solutions found.
Description This workshop includes the following tasks:
Task 1 – Open and review the Aspen Utilities model Task 2 – Link the model to an Excel Interface file Task 3 – How to run the model Task 4 – Optimize Utility Plant Operation Task 5 – Manage New Natural Gas Contract Task 6 – Forecast Power and Gas Demand to Provide Nomination Task 7 – Convert Production Plan to Utility Plan Task 8 – Evaluate Capital Investment
Before starting the workshop, you need to copy the following files from the Databases2periods folder:
ProfileData.mdb DemandData.mdb TariffData.mdb Interface.mdb
Paste the files into the following path: C:\ProgramData\AspenTech\Aspen Utilities Planner V8.8\Example Databases
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Task 1 – Open and Review the Aspen Utilities Model
Open the Aspen Utilities Planner file titled Model.auf.
This model represents a typical utilities system. – Steam is generated at high pressure in the BOILER and also in a heat recovery steam generator HRSG, which takes exhaust from a gas turbine GTG. – Power is generated on site in the gas turbine GTG and also in the condensing steam turbine STG. – There are 2 steam distribution headers : high pressure HPHDR and low pressure LPHDR – The usage of steam in the process units at each header pressure is modelled using steam demand blocks HPUSE and LPUSE – There is also steam generation from waste heat in the process units (from column pumparounds and exothermic reaction), modelled as steam supply blocks HPGEN and LPGEN. – Between the HP header and the LP header, there is a LETDOWN.
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– There is also a steam turbine drive, between the HP and LP headers, which drives the boiler feed water pump BFWPUMP. The turbine is modelled using a drive list block PUMPDRV. There is an alternative motor driven pump, which is also modelled inside the drive list block. – The model includes a DEAERATOR which receives: condensate return from the STG and from the process units COND, make up water MKUP and LP steam. The DEAERATOR provides boiler feed water to BOILER, to HRSG and also to the process units BFWPROC. – Two fuels are used: Natural Gas is used in the GTG, HRSG and BOILER. Butane can be used in the BOILER only. The flowsheet also includes block NGASCONS which represents natural gas consumption by the process units. – The block SITEPOW represents the total power demand of the site. The overall site’s power balance has been modelled using the power header POWERHDR. The model calculates how much power needs to be imported from the GRID to make up for any shortfall. – Note that the model also shows a steam turbine generator between the HP and LP headers (TURBINE). This equipment is not physically in place at the plant, but has been added in the model to evaluate a future potential investment.
Task 2 – Link the Model to an Excel Interface File To run the model and to view results from the model, we need to link the flowsheet to a Microsoft Excel Interface file using an Aspen Utilities Add-in. To activate the add-in, the steps are explained below: Open the Excel Interface file Task1Starter.xlsm. Select File | Options
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Select Add-Ins | Manage :Excel Add-Ins | Go
In the Add-ins window, select Aspen Utilities v8.4 Add-in Browse to the folder C:\Program Files(x86)\AspenTech\Aspen Utilities Planner V8.4\bin And select the Utilities 300.xla file Once selected, the following Aspen Utilities menu will appear in Excel.
You have now completed the activation of the Aspen Utilities Excel Add-in.
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Next you will link Excel to the Aspen Utilities model file, using the following steps: From the Aspen Utilities Add-In menu, select Open Aspen Utilities Point to the model model.auf and select Open. When prompted with the following question, press Cancel
The Excel file and the Aspen Utilities model are now linked.
Select Show Aspen Utilities, to make the model visible
The Aspen Utilities icon should appear and the model is now visible
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Task 3 – How to Run the Model The Excel Interface file has some preconfigured tabs that allow the user to send inputs into the model, run optimization and view optimization results. These tabs will be explained below.
Use the “Demand” tab to enter the utility demands of the process units.
The “Demand” tab contains a list of all the utility demands of the flowsheet. The inputs for each demand are the Min value and the Max value. Because the demands are fixed the Min and Max values should be specified to be equal. The results of the optimizer are reported in the next two columns: The optimized value is written by the optimizer in column Value and the marginal cost for each demand is written by the optimizer in the Shadow Price column. Note that the “Demand” tab contains data for two periods, 1 and 2. This allows the user to enter inputs for 2 cases, the inputs can be the same between the cases or different.
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Use the “Availability” tab to enter the equipment availability and capacity limits.
For each utility equipment type (i.e. BOILER, HRSG, STG, GTG etc.) the list contains typically two items: – Availability – Limits on capacity (Min and Max values) Availability is specified as follows: – Available This equipment is available for use if it is economical to do so. It need not necessarily be used – Not Available This equipment is not available, e.g., it is down for maintenance – Must be on This equipment must be used even if it is uneconomic to do so
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Use the “Energy Cost Summary” tab to enter the contract information and prices
The “Energy Cost Summary” tab is where the user enters prices and limits for the various contracts and the total operating cost is being calculated. For every contract, the user has to enter the Fixed Cost, the Variable cost, the Min limit and the Max limit. Columns Flow and TotCost are used by the optimizer to report the optimum flow of the corresponding utility and its cost. Our site has the following contracts: – A contract for Power Import from the GRID. – A contract for the Butane fuel used in the BOILER – A contract for the Natural Gas. This contract has two tiers. Tier pricing allows the user to define multiple prices within the same contract, depending on the usage. In the current screen you can see that Tier1price applies for the first 250 GJ/hr of gad usage, and any usage above this will use Tier 2 pricing.
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To run optimization, select Optimize Flowsheet from the Aspen Utilities menu
When the following optimization window appears, press OK
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When optimization is completed, go to the “Flowsheet” tab to view the optimized results for Period 1 You can view results for Period 2 by typing number 2 next to the PERIOD cell
In the “Production Plan” tab you can view and compare the results for all periods.
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Task 4 – Optimize Utility Plant Operation Objective of Task 4
First we shall use the model to set up a Base Case that represents the current operation of the utility system and calculate the current operating cost. We will use Period 1 for this case Then we shall perform optimization to find out the Optimized operation. We will use Period 2 for this Finally we shall compare the Base Case and the Optimized Case to conclude what changes to make to the plant operation and how much savings this will bring. For this task open Task4Starter.xlsm. Once opened, it will automatically link to model.auf.
Enter in Period 1 the current utility demands From plant measurements, we have obtained the current demands of the process units for steam, power, fuel and water: Utility Demand
Unit of measure GJ/hr MW(e) tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr
Natural Gas Consumption Site Power Demand HP Steam Use HP Process Steam Generation Recovered Condensate LP Steam Use LP Process Steam Generation Process BFW Demand
Value 40.00 31.90 130.00 53.00 33.00 52.00 32.00 85.00
In the “Demand” tab, in Period 1, enter the current values for each utility demand in the Min and Max columns. The same value should be entered for both Min and Max.
Demand Legend
Period 1
Area Units Min
Natural Gas Consumption Site Power Demand HP Steam Use HP Process Steam Generation Recovered Condensate LP Steam Use LP Process Steam Generation Process BFW Demand
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Area1 Area2 Area2 Area2 Area2 Area3 Area3 Area3
GJ/hr MW(e) tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr
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40 31.9 130 53 33 52 32 85
Max Value Shadow Price
40 31.9 130 53 33 52 32 85
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Enter in Period 1 the current equipment loads From plant measurements, we have obtained the current loads of the utility equipment. Equipment
Unit of measure MW(e) MW(e) MW(e) tonne/hr GJ/hr
New Turbine Power output STG Power Generation GTG Power Generation BOILER Steam Generation Butane Availability
Value 0 4 17.5 35 0
We also know that: – The Motor driven boiler feed water pump PUMPDRV.Motor is currently being used. – The turbine driven pump PUMPDRV.Turbine is switched off.
In the “Availability” tab, in Period 1, enter the current loads of the equipment. The same value should be used for both Min and Max.
For the HRSG Supplementary Firing and HRSG steam generation we don’t have measurements of the current loads, so we enter their capacity limits (0 – 300 and 0-200 respectively). The model will be able to calculate their loads based on the steam balance.
For each item of equipment, enter its availability, i.e. if the equipment is currently running set it to “Must Be On”, if its load is zero, then set it to “Not Available”.
Availability Legend
Period 1
Area Units Min
HRSG Supplementary Firing New Turbine Power Out STG Power Generation GTG Power Generation New Turbine Status STG Availability PUMPDRV.Turbine PUMPDRV.Motor HRSG Availability GTG Availability Boiler Availability HRSG Steam Generation Boiler Steam Generation BUTANE Availability
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Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area2
Max
GJ/hr 0.00 300.00 MW(e) 0.00 0.00 MW(e) 4.00 4.00 MW(e) 17.50 17.50 Not Available none Must Be On none Not Available none Must Be On none Must Be On none Must Be On none none Must Be On tonnes/hr 0.00 200.00 tonnes/hr 35.00 35.00 GJ/hr 0.00 0.00
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Enter in Period 1 the utility prices The prices for the purchased utilities - power, natural gas and butane - are provided below. Note that currently natural gas has the same price for both tiers.
Contract
Unit of measure
Power Import Butane Natural Gas Tier 1 Natural Gas Tier 2
MWh GJ GJ GJ
Variable Cost $/unit 40 6 1.5 1.5
In the “Energy Cost Summary” tab, enter the prices of the contracts in Period 1 in the Variable Cost column J
Energy Cost Summary Legend
Units Min
Period 1
Max
Fixed Cost Var. Cost Flow Total Cost Elec Power Import
MWh
0.00
9999.00
$0.00 $40.00 Elec Sub Total
0.00
$0.00 $0.00
0.00
$0.00 $0.00 $0.00 $0.00
Total Cost
$0
Fuel Butane GJ Natural Gas Tier 1 GJ Natural Gas Tier 2 GJ
0.00 0.00 0.00
9999.00 250.00 9999.00
$0.00 $6.00 $0.00 $1.50 $0.00 $1.50 Fuel Sub Total
Run optimization for Period 1
Run Optimization for period 1 only, by changing the ending period to be 1
Although we have run optimization, because we restricted the loads of the equipment to their current values, the model has actually reproduced the current operation. View the mass and energy balance for the current operation in the “Flowsheet” tab and make a note of the hourly operating cost 1282 $/h.
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Next we shall use Period 2 to optimize the operation. Enter in Period 2 the utility demands
In the “Demand” tab in Period 2, copy and paste the Min/Max values from Period 1.
Enter in Period 2 the equipment availability and capacity limits The capacity of the utility equipment is provided in the table below. Equipment HRSG Supplementary Firing New Turbine Power output STG Power Generation GTG Power Generation HRSG Steam Generation BOILER Steam Generation Butane Availability
Unit of measure GJ/hr MW(e) MW(e) MW(e) tonne/hr tonne/hr GJ/hr
Min
Max
0 0 3.5 8 0 20 0
300 0 7 20 200 200 9999
In the “Availability” tab, in Period 2, enter the equipment capacity limits.
Make all equipment “Available”, except the New Turbine, which should be set to “Not Available” and the BOILER which should be set to “Must Be On”
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Enter in Period 2 the utility prices
In the “Energy Cost Summary” tab make sure the prices for Period 2 are the same as for Period 1
Run optimization
Run Optimization for period 1 and 2, by changing the ending period to be 2
Task 4 - Solution
Availability Legend
Period 1
Area Units Min
HRSG Supplementary Firing New Turbine Power Out STG Power Generation GTG Power Generation New Turbine Status STG Availability PUMPDRV.Turbine PUMPDRV.Motor HRSG Availability GTG Availability Boiler Availability HRSG Steam Generation Boiler Steam Generation BUTANE Availability
Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area2
GJ/hr MW(e) MW(e) MW(e) none none none none none none none tonnes/hr tonnes/hr GJ/hr
Max
Period 2
Value Shadow Price
0.00 300.00 184.72 0.00 0.00 0.00 4.00 4.00 4.00 17.50 17.50 17.50 Off Not Available On Must Be On Off Not Available On Must Be On On Must Be On On Must Be On On Must Be On 0.00 200.00 109.30 35.00 35.00 35.00 0.00 0.00 0.00
Min
Max
Value
Shadow Price
0.00 0.00 300.00 264.05 40.00 0.00 0.00 0.00 16.28 3.50 7.00 7.00 30.18 8.00 20.00 20.00 0.00 Not Available Off 0.00 On Available 0.00 On Available 0.00 Off Available 0.00 On Available 0.00 On Available 0.00 On Must Be On 0.00 0.00 200.00 142.72 1.22 20.00 200.00 20.00 1.50 0.00 9999.00 0.00
0.47 0.00 8.81 31.33 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Demand Legend
Period 1
Area Units Min
Natural Gas Consumption Site Power Demand HP Steam Use HP Process Steam Generation Recovered Condensate LP Steam Use LP Process Steam Generation Process BFW Demand
Area1 Area2 Area2 Area2 Area2 Area3 Area3 Area3
Max Value Shadow Price
GJ/hr 40.00 40.00 40.00 MW(e) 31.90 31.90 31.90 tonnes/hr 130.00 130.00 130.00 tonnes/hr 53.00 53.00 53.00 tonnes/hr 33.00 33.00 33.00 tonnes/hr 52.00 52.00 52.00 tonnes/hr 32.00 32.00 32.00 tonnes/hr 85.00 85.00 85.00
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Period 2
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Min
Max Value
1.50 40.00 40.00 40.00 40.00 31.90 31.90 31.90 5.83 130.00 130.00 130.00 5.83 53.00 53.00 53.00 0.42 33.00 33.00 33.00 5.83 52.00 52.00 52.00 5.83 32.00 32.00 32.00 0.70 85.00 85.00 85.00
Shadow Price 1.50 40.00 5.83 5.83 0.42 5.83 5.83 0.70
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Energy Cost Summary Legend
Units Min
Period 1
Max
Period 2
Fixed Cost Var. Cost Flow Total Cost Fixed Cost Var. Cost Flow Total Cost Elec Power Import
MWh
0.00
9999.00
$0.00 $40.00 Elec Sub Total
0.00 0.00 0.00
9999.00 250.00 9999.00
10.81 10.81
$432.34 $432.34
$0.00
$0.00 $6.00 0.00 $0.00 $1.50 0.00 $0.00 $1.50 566.35 Fuel Sub Total 566.35
$0.00 $0.00 $849.52 $849.52
$0.00 $0.00 $0.00
Total Cost
$1,282
$40.00
4.91 4.91
$196.59 $196.59
$6.00 0.00 $1.50 0.00 $1.50 619.08 619.08
$0.00 $0.00 $928.62 $928.62
Fuel Butane GJ Natural Gas Tier 1 GJ Natural Gas Tier 2 GJ
$1,125
UTILITY PRODUCTION PLAN Power generation Steam Generation
Fuel
Steam
Power
Block GTG STG BOILER HRSG BUTANE NATGAS GTG HRSG Natural Gas Header BOILER LPUSE HPUSE HPGEN LPGEN BFWPROC LETDOWN VENT COND DEARATOR STG PUMPDRV PUMPDRV GRID SITEPOW STGPUMP PUMPDRV BFWPUMP TURBINE MKUP AnnCost
Description Power from Gas Turbine Power from Cond Steam Turbine Steam Generation from Boiler Steam Generation from HRSG Butane Natural Gas GTG - Natural Gas In HRSG - Natural Gas In BOILHDR - Natural Gas In Boiler Fuel LP Steam Use HP Steam Use HP Steam Generation LP Steam Generation BFW Steam Generation LETDOWN - Steam In VENT - Steam Out CONDENSATE Return DEAREATOR - Steam In HP Steam In Steam Into Turbine Driven BFW pump Shaftwork from Turbine Driven BFW pump Power Import from Grid Site Power Demand Power to STG condensate pump Power in Motor Driven BFW pump BFW Pump Power In Power from the new turbine MPtoLP Make up Water Hourly Cost
1
2 17.50 4.00 35.00 109.29 0.00 566.35 217.50 184.69 124.16 124.16 52.00 130.00 53.00 32.00 85.00 44.41 0.00 33.00 24.41 22.88 0.00 0.00 10.81 31.90 0.01 0.40 0.36 0.00 155.83 1282
20.00 7.00 20.00 142.70 0.00 619.08 242.00 263.99 73.09 73.09 52.00 130.00 53.00 32.00 85.00 30.67 0.00 33.00 25.67 40.03 15.00 0.40 4.91 31.90 0.01 0.00 0.39 0.00 157.13 1125
The current hourly operating cost is $1282. This can be reduced to $1125, if we optimize the operation. The changes recommended by the optimizer are: – To increase GTG power generation from 17.5 to 20 MW – To increase STG power generation from 4 to 7 MW – To reduce steam production from BOILER from 35 to 20 t/h – To increase steam production from HRSG from 109 to 142 t/h – To switch on the BFW Steam driven pump and switch off the Motor pump Save the Excel Interface File under the name Task4.xlsm ©2015 AspenTech. All Rights Reserved.
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Task 5 – Manage New Natural Gas Contract Objective of Task 5
Our gas contract has expired and our gas supplier has put forward a new contract. We can take up to 250 GJ/hr of natural gas at $1.5/GJ and any usage above the 250 is charged at $7.5/GJ. We have a supply of butane available at $6/GJ. We need to decide if we should take both tiers of natural gas, or only take the cheaper tier and top up our fuel requirements with butane. We shall use the model to evaluate the two options. We shall use Period 1 to evaluate option 1 (no Butane available), and period 2 to evaluate option 2 (with Butane available). We will prepare the data for both periods and run optimization of both cases in one optimization run.
You can continue to use the excel file from Task4. If you have not finished Task 4, load Task4Solution.xlsm to use as the starting file for Task 5 Enter utility demands The utility demands are the same as in the previous task, so there is no need to change them. Enter equipment availability
Enter in both periods the equipment Min and Max capacity limits Equipment HRSG Supplementary Firing New Turbine Power output STG Power Generation GTG Power Generation HRSG Steam Generation BOILER Steam Generation
Unit of measure GJ/hr MW(e) MW(e) MW(e) tonne/hr tonne/hr
Min
Max
0 0 3.5 8 0 20
300 0 7 20 200 200
For the availability of Butane, in Period 1 set its Max to be 0, in Period 2 set its Max to be 9999 (unlimited).
Set all equipment to “Available” with the following exceptions: – NEW TURBINE should be “Not Available” – BOILER should be “Must Be On”
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Availability Legend
Period 1
Area Units Min
HRSG Supplementary Firing New Turbine Power Out STG Power Generation GTG Power Generation New Turbine Status STG Availability PUMPDRV.Turbine PUMPDRV.Motor HRSG Availability GTG Availability Boiler Availability HRSG Steam Generation Boiler Steam Generation BUTANE Availability
Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area1 Area2
Period 2
Max Value dow P Min
GJ/hr 0.00 300.00 MW(e) 0.00 0.00 MW(e) 3.50 7.00 MW(e) 8.00 20.00 Not Available none Available none Available none Available none Available none Available none none Must Be On tonnes/hr 0.00 200.00 tonnes/hr 20.00 200.00 GJ/hr 0.00 0.00
Max
Valueadow Pr
0.00 300.00 0.00 0.00 3.50 7.00 8.00 20.00 Not Available Available Available Available Available Available Must Be On 0.00 200.00 20.00 200.00 0.00 9999.00
Enter Prices In the Energy Cost Summary change the Tier 2 price for Period 1 Natural gas to 7.5 ($/GJ). This is automatically applied to Period 2 also.
Energy Cost Summary Legend
Units Min
Period 2
Period 1
Max
Fixed Cost Var. Cost Flow Total Cost Fixed Cost Var. Cost Flow Total Cost Elec Power Import
MWh
0.00
9999.00
$0.00 $40.00 Elec Sub Total
$0.00 $0.00
$0.00
0.00
$0.00 $0.00 $0.00
0.00
$0.00 $0.00 $0.00 $0.00
Total Cost
$0
$40.00 0.00
$0.00 $0.00
0.00
$0.00 $0.00 $0.00 $0.00
Fuel Butane GJ Natural Gas Tier 1 GJ Natural Gas Tier 2 GJ
0.00 0.00 0.00
9999.00 250.00 9999.00
$0.00 $6.00 $0.00 $1.50 $0.00 $7.50 Fuel Sub Total
$6.00 $1.50 $7.50
$0
Run optimization Run Optimization for period 1 and 2, by setting the ending period to be 2:
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Task 5 - Solution The cost for Period 2 is lower than Period 1. Hence it is more cost effective to only take Tier 1 natural gas (250 GJ/h) and top up with butane.
UTILITY PRODUCTION PLAN Power generation Steam Generation
Fuel
Steam
Power
Block GTG STG BOILER HRSG BUTANE NATGAS GTG HRSG Natural Gas Header BOILER LPUSE HPUSE HPGEN LPGEN BFWPROC LETDOWN VENT COND DEARATOR STG PUMPDRV PUMPDRV GRID SITEPOW STGPUMP PUMPDRV BFWPUMP TURBINE MKUP AnnCost
Description Power from Gas Turbine Power from Cond Steam Turbine Steam Generation from Boiler Steam Generation from HRSG Butane Natural Gas GTG - Natural Gas In HRSG - Natural Gas In BOILHDR - Natural Gas In Boiler Fuel LP Steam Use HP Steam Use HP Steam Generation LP Steam Generation BFW Steam Generation LETDOWN - Steam In VENT - Steam Out CONDENSATE Return DEAREATOR - Steam In HP Steam In Steam Into Turbine Driven BFW pump Shaftwork from Turbine Driven BFW pump Power Import from Grid Site Power Demand Power to STG condensate pump Power in Motor Driven BFW pump BFW Pump Power In Power from the new turbine MPtoLP Make up Water Hourly Cost
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1 MWe MWe tonnes/hr tonnes/hr GJ/hr GJ/hr GJ/hr GJ/hr GJ/hr GJ/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr MWe MWe MWe MWe MWe MWe MWe tonnes/hr $/hr
2 8.00 0.00 20.00 99.85 0.00 434.19 130.00 191.09 73.09 73.09 52.00 130.00 53.00 32.00 85.00 27.85 0.00 33.00 22.85 0.00 15.00 0.40 23.90 31.90 0.00 0.00 0.32 0.00 154.87 2712
16.00 0.00 81.03 38.63 262.50 250.00 204.00 6.00 0.00 262.50 52.00 130.00 53.00 32.00 85.00 27.67 0.00 33.00 22.67 0.00 15.00 0.40 15.90 31.90 0.00 0.00 0.32 0.00 153.54 2586
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Period 1 Results – No Butane Available
Period 2 Results – Butane Available
Compare the loads of equipment between the two cases: – If Tier 2 gas is used (period 1), the load of GTG is reduced to 8 MW, to try and minimize gas usage. – In period 2, steam generation is shifted from HRSG to Boiler (due to Butane being cheaper than Tier 2 gas), freeing Tier 1 gas to be used for more GTG power generation (16 MW). Save the Excel Interface File under the name Task5.xlsm. ©2015 AspenTech. All Rights Reserved.
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Task 6 – Forecast Power and Natural Gas Demands to Provide Nomination Objective of Task 6
We need to nominate to our gas and electricity suppliers how much gas and electricity we plan to take the following day. There are two price zones for electricity : o Day time - 7:00 to 24:00 - Power Price = 40 $/MWH o Night time - 00:01 to 7:00 - Power Price = 20 $/MWH The gas price is flat (1.5 $/GJ) for both tiers The utility demands as the same as in the previous task The equipment availability and limits are the same as in the previous task We shall run optimization to optimize the operation and find out the corresponding gas and electricity consumption. We shall use Period 1 to optimize Day time operation and use Period 2 to optimize Night time operation.
You should use Task5.xlsm as the starting file for Task 6. If you have not completed the previous task, load Task5Solution.xlsm to use as starting file. Enter utility demands
The utility demands are the same as in the previous task, so there is no need to change them.
Enter equipment availability
The equipment availability and limits are the same as in the previous task. Set the Max limit for Butane to 9999 for both periods.
Enter prices
In the Energy Cost Summary, enter the price for power import to be $40 for period 1 and $20 for period 2. Reset natural gas price to 1.5 for both tiers
Energy Cost Summary Legend
Units Min
Period 2
Period 1
Max
Fixed Cost Var. Cost Flow Total Cost Fixed Cost Var. Cost Flow Total Cost Elec Power Import
MWh
0.00
9999.00
$0.00 $40.00 Elec Sub Total
$0.00 $0.00
$0.00
0.00
$0.00 $0.00 $0.00
0.00
$0.00 $0.00 $0.00 $0.00
Total Cost
$0
$20.00 0.00
$0.00 $0.00
0.00
$0.00 $0.00 $0.00 $0.00
Fuel Butane GJ Natural Gas Tier 1 GJ Natural Gas Tier 2 GJ
0.00 0.00 0.00
9999.00 250.00 9999.00
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$0.00 $6.00 $0.00 $1.50 $0.00 $1.50 Fuel Sub Total
1 - 45
$6.00 $1.50 $1.50
$0
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Run optimization for two periods
Run Optimization for period 1 and 2, by setting the ending period to be 2
Task 6 – Solution
View the results in the Utility Production Plan, to see the forecast for Natural gas demand and Power Import.
Note that during night time (period 2) the optimizer recommends to reduce natural gas import and increase power import. This is because it suggests to switch off the condensing turbine STG and hence less steam is produced from HRSG during the night time, hence less gas is needed.
UTILITY PRODUCTION PLAN Power generation Steam Generation
Fuel
Steam
Power
Block GTG STG BOILER HRSG BUTANE NATGAS GTG HRSG Natural Gas Header BOILER LPUSE HPUSE HPGEN LPGEN BFWPROC LETDOWN VENT COND DEARATOR STG PUMPDRV PUMPDRV GRID SITEPOW STGPUMP PUMPDRV BFWPUMP TURBINE MKUP AnnCost
Description Power from Gas Turbine Power from Cond Steam Turbine Steam Generation from Boiler Steam Generation from HRSG Butane Natural Gas GTG - Natural Gas In HRSG - Natural Gas In BOILHDR - Natural Gas In Boiler Fuel LP Steam Use HP Steam Use HP Steam Generation LP Steam Generation BFW Steam Generation LETDOWN - Steam In VENT - Steam Out CONDENSATE Return DEAREATOR - Steam In HP Steam In Steam Into Turbine Driven BFW pump Shaftwork from Turbine Driven BFW pump Power Import from Grid Site Power Demand Power to STG condensate pump Power in Motor Driven BFW pump BFW Pump Power In Power from the new turbine MPtoLP Make up Water Hourly Cost
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1 MWe MWe tonnes/hr tonnes/hr GJ/hr GJ/hr GJ/hr GJ/hr GJ/hr GJ/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr tonnes/hr MWe MWe MWe MWe MWe MWe MWe tonnes/hr $/hr
2 20.00 7.00 20.00 142.70 0.00 619.08 242.00 263.99 73.09 73.09 52.00 130.00 53.00 32.00 85.00 30.67 0.00 33.00 25.67 40.03 15.00 0.40 4.91 31.90 0.01 0.00 0.39 0.00 157.13 1125
20.00 0.00 20.00 99.85 0.00 508.48 242.00 153.39 73.09 73.09 52.00 130.00 53.00 32.00 85.00 27.85 0.00 33.00 22.85 0.00 15.00 0.40 11.90 31.90 0.00 0.00 0.32 0.00 154.87 1001
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Save the Excel Interface File under the name Task6.xlsm. From the Aspen Utilities Excel menu, select Close Aspen Utilities.
Then close Task6.xlsm too and all other excel files that may be open
In preparation for the next task you need to do the following:
Task 7 – Convert Production Plan to Utilities Plan The utility planning process usually follows the production planning process. Aspen Utilities (through its Excel based interface) offers the ability to:
easily transfer a Production Plan originating from the Production Planning department (in a refinery usually done by supply chain tools like PIMS) , convert it into a Demand Forecast and then send the calculated utility demands into the Aspen Utilities optimizer, to produce an optimum Utility Plan.
Copy/Paste Database files for 7 periods First you need to copy the following files from Databases7periods folder :
ProfileData.mdb DemandData.mdb TariffData.mdb Interface.mdb
Paste the files into the following path: C:\ProgramData\AspenTech\Aspen Utilities Planner V8.4\Example Databases
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Open the model file and link to the excel file for Task7
Open the Aspen Utilities Planner file titled Model.auf. Open the Excel interface file Task7Starter.xlsm
Next you will link the Excel file to the Aspen Utilities model file, using the following steps:
From the Aspen Utilities Add-In menu, select Open Aspen Utilities Point to the Model.auf and select Open. When prompted with the following question, press Cancel
The Excel file and the Aspen Utilities model are now linked. Review tab “FromPimsOrion”
Overview of Production Plan Table (rows 3-13)
The Production Plan Table (rows 3-13) includes a production plan for the week (7 days) coming from the production planning department. By clicking on the button “Load Tags from Mapping File” these data has automatically populated the table from another worksheet. The data includes the following information for three process units (HYD, IGAS, FCC): – Feeds and Product rates – Mode of operation and – Season
Overview of Equations Table (rows 25-38)
The Equations Table includes demand forecasting correlations that calculate individual utility usages (steam, power, BFW, natural gas) for each of the 3 process units, as a function of their production rates and the other production parameters.
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When you navigate to any cell within the table you can see the formulas used for these calculations. The formulas have been produced by regressing historical data.
Overview of Targets Table (rows 15-23)
The Targets Table sums up the individual consumptions by utility type to calculate the total demands per utility type as represented inside the Aspen Utilities model. For example the LPUSE for all these process units is added up to a total amount . The totals shows on the Targets table are automatically sent to the “Demand” tab, as inputs to the model. So if a new production plan is loaded in the top table, then the “Demand” tab will be automatically updated with the corresponding utility demands. Objective of Task 7
Start with a Process Production Plan for the coming week (7 days) Convert this to a Utility Production Plan for the week Evaluate the impact on cost if we shut down the condensing turbine STG for maintenance during the week First we shall run optimization for the 7 periods, assuming STG is “Available” Then we shall run optimization for the 7 periods setting STG to “Not Available” Then we shall compare the power import profiles for the two cases and the total weekly cost
Review tab “Demand” View the “Demand” tab and observe that all the demands originate from the “Targets Table” and that there is variation in the utility demands between the periods Review Equipment Availability The equipment availability and limits have been set to the default values for all the periods. Note that the new steam TURBINE is “Not Available” and that the BOILER is “Must Be On” Review Prices The default prices have been set for all periods (Power :40$/MWH, NatGas:1.5 $/GJ, Butane 6$/GJ) Run optimization for 7 periods Run Optimization by setting the ending period to be 7:
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View Results View the results in the Utility Production Plan and the Graphs tabs, to see the forecasted Power Import and costs. The costs are reported as hourly cost for each day of the week and as a weekly total. Save the file as Task6STGAvailable.xlsm Rerun the model with STG down In the Availability tab, change the STG Availability to “Not Available” for all periods and re-optimize. View the results and save as Task6STGDown.xls. Task 7 - Solution Case 1 Results – STG Available
Case 2 Results – STG Not Available
The cost of shutting down the STG during this week will be $14,420. This is the difference between the weekly cost for case 1 (187,480) and case 2 (201,900).
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Task 8 – Evaluate Capital Investment Objective of Task 8
Over the years, new process plants have been added to this industrial site. This has impacted the overall steam balance, and as a result of this, there is quite often a large steam let-down flow between the HP and LP steam headers. Apart from the BFW pump steam drive, there is no other steam turbine between the two steam headers. The objective of task 8 is to evaluate the potential energy cost savings and payback period if we install a new steam turbo-generator between the HP and LP steam levels. The new steam turbine has operating limits of 3.5-7 MW and has estimated capital cost of $3.8 Million. This new steam turbine is already in the flowsheet but has been “Not Available” in the previous tasks.
Available Information and Methodology
To evaluate the total annual cost savings from this potential investment, we have identified the 7 most typical operating cases and the corresponding hours for which each case occurs during the year. These are shown in the table below. Operating Case Hours/year
1 900
2 1100
3 1500
4 1500
5 2000
6 500
7 500
The utility demands for each operating case have been entered in the Task8Starter.xlsm file, in the “Demand” tab, in each of the 7 periods. First we shall calculate the total annual operating cost for the 7 operating cases without the new turbine Then we shall calculate the total annual operating cost with the new turbine being “Available” By comparing the cost for the two options, we can estimate the potential energy cost savings from the investment in the new turbine
Solution Steps
Open Task8Starter.xlsm file. This will automatically link to the model file View the “Demand” tab to see the utility demands for the 7 operating cases. In the “Availability” tab, set the NEW TURBINE to “Not Available” Run optimization for 7 periods View the optimized results in the “Production Plan” tab. Fill in the data for the hours of operation per year for each period (yellow cells)
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This allows the total annual operating cost to be calculated 9,394,084 $/year Save the excel file with the name Task8NoNewTurb.xlsm
Next we will find out the annual operating cost, if the new turbine is put in place
In the “Availability” tab, set the NEW TURBINE to “Available” and its capacity limits to be between 3.5 – 7 MW for all periods Run optimization for 7 periods View the optimized results in the “Production Plan” tab.
The total annual operating cost with the new turbine in place is 7,511,204 $/year Save the excel file with the name Task8NewTurb.xlsm The operating cost savings from the new turbine is 1,882,880 $/year The cost of the new turbine is 3.8 $Million, this gives a payback of approximately 2 years
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