Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability
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Transcript of Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability
Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability
Levitan & Associates, Inc.www.levitan.com
Presentation to the NEPOOL Participants Committee
January 5th, 2001
January 5, 20012
Levitan & Associates, Inc. (LAI) Practice Areas
Energy Markets Simulation and Optimization Modeling
Merchant Generation Economics
Pipeline Transportation Management
Fuel Supply Procurement
Power System Engineering/Heat Balance Optimization
ISO Interconnection Policy and Pricing
NUG Contract Administration (Reformation and Buyouts)
Environmental Compliance Strategy
Litigation Support
January 5, 20013
Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability
What the Study Is & Is Not
Individual & Consolidated Models
Steady-State Perspective
No Temporal & Force Majeure
Market Dynamics in New England
January 5, 20015
New England Natural Gas Supply Sources
WCSB
Gulf Onshore
Gulf Offshore
SableIsland
LNG
RockyMountain
January 5, 20016
Tennessee
Iroquois
PNGTS
M&N
Algonquin
New England’s Interstate Pipelines
January 5, 20017
New England’s Interstate Pipelines
Western Canadian Gas thru TCPL, Iroquois
and PNGTSEastern Canadian
Gas thru M&N
Western Canadian Gasthru Tennessee
Gulf Coast Gasthru AlgonquinAnd Tennessee
LNG fromAlgeria and
Trinidad
Steady-State Modeling Results
January 5, 20019
Confidentiality
ISO-NE & LAI has and will continue to comply with the
NEPOOL Information Policy - Rev 3, dated August 10, 2000
Proprietary Information kept Confidential
Steady-State hydraulic model developed from interstate
pipeline public domain information
• FERC 567 Reports & FERC Flow Diagrams Reflecting Peak Day
Design
January 5, 200110
Steady-State Highlights
No summer peak day pipeline deliverability constraints through 2005
Delivery constraints are apparent in Winter 2003
• Shortfall in gas requirements 1,755 MW out of 8,946 MW assumed
• There are 71 gas-fired units, 51 of which are dual fueled
Delivery constraints intensify by Winter 2005
• Shortfall in gas requirements 3,226 MW out of 11,579 MW assumed
• There are 75 gas-fired units, 54 of which are dual fueled
Theoretical mitigation potential thru back-up fuel
No pipeline delivery constraints on a peak day in Winter 2000-01
Findings and Observations
January 5, 200112
High Ref High Ref High Ref
1755
1164
3226
1484
1176
443
3159
468
0
500
1000
1500
2000
2500
3000
3500
60-Day
Peak Day
Projected Shortfalls in Gas Requirements (MW)*
* 6970 Btu/kWh
2001 2003 2005
January 5, 200113
Summary of Peak Day Scenarios – Total Regional Demand vs. System Capacity
3000
3200
3400
3600
3800
4000
4200
4400
4600
4800
2001 2003 2005
MM
cf/d
System Capacity High Reference
January 5, 200114
Steady-State Modeling Results
------1501406HighSummer Peak Day
31595138672837HighWinter 60-Day
32265249062837HighWinter Peak Day
468767822837ReferenceWinter 60-Day
14842419072837ReferenceWinter Peak Day2005
11761918612837HighWinter 60-Day
17552858802837HighWinter Peak Day
443728042837ReferenceWinter 60-Day
11641898722837ReferenceWinter Peak Day2003
------7512617HighWinter Peak Day2001
Capacity
(MW)
Volumes
(MMcf/d)
Merchant Generators
LDCs
Unserved MerchantPipeline Demand
(MMcf/d)ForecastScenarioYear
Unserved merchant capacity does not take into account back-up fuel capabilities.
January 5, 200115
Back-up Fuel Issues
Infrastructure• Air Permits • Delivery Logistics
• Tankage • Refill
Operational Constraints, e.g. switch-on-the-fly
Sustainability
January 5, 200116
Mitigation Potential
447.5524.0971.55,89011,579High
141.5241.0382.52,2637,551Reference
Excess or Shortfall w/
Back-up Fuel Use
(MMcf/d)
Peak Day Transport Shortfall
(MMcf)
Peak Day Gas
Available w/ Back-up Fuel
Use
(MMcf)
Back-up Fuel
Capability
(MW)
New Entry
(MW)Case
Contingency Cases
January 5, 200118
Contingency Cases
ISO Contingencies• Loss of Major Gas-fired Generating Unit
• Loss of 2000 MW HydroQuebec Phase II Line
Gas Contingencies • Scenario 1 - Loss of compression at Burrillville on
Algonquin
• Scenario 2 - Loss of compression at Agawam on Tennessee
• Scenario 3 - Loss of 36-inch line on Tennessee
January 5, 200119
ISO Contingency: Loss of Major Gas-Fired Generating Unit
No significant loss of pressure or flows
Interstate pipelines have the ability to divert and/or re-route gas along the 1100-mile transportation path
January 5, 200120
ISO Contingency: Loss of 2000 MW HydroQuebec Phase II Line
Winter Peak Day - System cannot transport any additional gas
Summer Peak Day - More than sufficient pipeline capacity to support replacement gas fueled generation
January 5, 200121
Gas Contingency Scenario 1
Available compression capacity at Burrillville on Algonquin derated from 11,400 hp to 5,700 hp
January 5, 200122
Increased horsepower requirements at other compressor stations
Fall in delivery pressures to levels that could disrupt plant operations
No observed impact on other pipelines
Gas Contingency Scenario 1
January 5, 200123
Gas Contingency Scenario 2
Available compression capacity at Agawam on Tennessee derated from 9,760 hp to 3,253 hp
January 5, 200124
Downstream compressor stations able to make-up for loss
No unacceptably low delivery pressures for merchant plants observed
No impact on other pipelines
Gas Contingency Scenario 2
January 5, 200125
Gas Contingency Scenario 3
7 miles of Tennessee’s 36-inch line at NY-MA border removed
January 5, 200126
Downstream compressors able to compensate for pressure loss
Gas Contingency Scenario 3
Recommendations
January 5, 200128
Recommendations
Advocate the streamlining of FERC’s pipeline certification process
Promote coordination of power and natural gas scheduling protocols
Increase understanding of merchant generators’ fuel-switching capabilities
Certify quality of interstate transportation arrangements
Study Assumptions
January 5, 200130
Steady-State Demand AssumptionsTwo Gas Demand Cases developed by ISO-NE & LAI: Reference Case & High Case
Reference Case High Case
Annual Net Energy Growth Rate
1.5% 2.4%
Summer Peak Demand Growth Rate
1.7% 2.9%
Winter Peak Demand Growth Rate
1.6% 2.5%
Capacity Additions 7,551 11,579
January 5, 200131
Electric Assumptions
ISO-NE develops electric side assumptions PROSYM production simulation model Analysis performed for 2000 - 2005 ISO-NE assumptions for:
• projected NEPOOL loads,
• existing & proposed capacity and capacity attrition
• net-interchange with New York, New Brunswick and Hydro-Quebec
ISO-NE delivers hourly gas demands for NEPOOL units for peak day (summer/winter) and 60 day winter average (Dec 15th thru Feb 15th)
January 5, 200132
Load Profiles and Seasonality
Winter• Reliance on Peak Day System Flow diagrams from
various certificate applications to serve merchant generators
Summer• Statistical inference from LDCs’ normalized sales
January 5, 200133
Merchant Entry in New England (High Case)
2000 2001 2002 2003 2004 2005
2876
2493
2182
1395
971
1662
0
500
1000
1500
2000
2500
3000W
inte
r C
apac
ity
(MW
)
January 5, 200134
Merchant Entry by Pipeline
Iroquois Tennessee Algonquin M&N PNGTS
1118
2654 2645 2698
443
0
500
1000
1500
2000
2500
3000W
inte
r C
apac
ity
(M
W)
January 5, 200135
Merchant Entry by Pipeline* (2005 High Case)
278.22698M&N
440.72645Algonquin
67.3443PNGTS
479.72654Tennessee
163.21118Iroquois
MMcf/dWinter MWPipeline
* No LNG units
January 5, 200136
Heat Rate vs. Gas Requirements
Plant Type
Heat Rate
(Btu/kWh)
(HHV)
Gas Requirements
(MMcf/d)
Fossil Steam 9,600 127
Advanced Combined Cycle
6,900 83
January 5, 200137
Gregg’s WinFlow Steady-State Model
WinFlow is a shell, requiring extensive and elaborate customization
WinFlow calculates the balanced steady-state pressure-flow relationships for pipeline networks
January 5, 200138
Validation of Steady-State Models
Each individual interstate pipeline model matched its Peak Day Flow diagram within industry tolerances 5# psi 10 hp
Steady-state models for Algonquin, Tennessee and M&N were reviewed and informally validated with individual pipelines
January 5, 200139
Scheduling Priorities during Constraints
Primary Firm Transportation LDCs, to a lesser extent, QFs and some merchants
Secondary Firm Transportation (quasi-firm) Marketers and merchant generators
Interruptible Transportation Industrials, merchant generators
Market Dynamics in New England
January 5, 200141
New England Natural Gas Infrastructure
New England’s Major Interstate Pipelines• Iroquois • Portland• Algonquin • Maritimes & Northeast• Tennessee
Existing pipeline delivery capacity = 3.6 Bcf/d.
Daily LNG sendout capability at Everett = 0.450 Bcf/d.• Expansion of 0.60 Bcf/d for 1,550 MW Sithe New Mystic Station,
possibly Island End• About 1.4 Bcf/d peak day deliverability behind the citygates• Liquids via truck 0.1 Bcf/d
January 5, 200142
Interstate Transportation Market Dynamics 14 pipeline projects placed in-service during 1999-’00
+ 2.0 Bcf/d in the Greater Northeast
New Pipelines in New England, M&N and PNGTS, result in + 0.615 Bcf/d, or about 3800 MW• Counterflow capability through Dracut Tennessee• Pressure and flow benefits improve network reliability
New LNG supplies from Trinidad
Commoditization of the “Supply Chain”• Repackaged Btu services • Synthetics• Increased liquidity • Risk management
January 5, 200143
Typical New England LDC Daily Gas Send-Out
Storage InjectionsPipeline
Storage Withdrawals
LNG/Propane
Source: WEFA, Northeast Natural Gas Markets, Opportunities and Risks, November 1998
January 5, 200144
LAI Project Team
Richard LevitanPrincipal
John BitlerPrincipal
Edward McGee, P.E.Managing Consultant
Jack Elder, P.E. Manager, Power Systems and Technology
John Pitts Senior Consultant
John Mesko, P.E.Senior Consultant
Lilly ZhuConsultant
Shilpa ShahAssistant Consultant
Levitan & Associates, Inc.www.levitan.com
Tel: 617-531-2818Email: [email protected]