Combustion Turbine Flexibility

Combustion Turbine Flexibility

Presentation to: NorthWestern Energy ETAC June 6, 2013

Why Does NWE Need Flexible Resources?

• Variations in load (within hour flexible

capacity)

• Hour-to-hour ramp (10 minutes before to 10

minutes after the hour) to reflect schedule changes

• Forced outage response

• Variable Energy Resource (VER) following –

Regional Wind (36 hours)

7000 MW

+/-Northwest Resource Flexibility

• Prior to 2003, NW IOUs (PacifiCorp, PGE, PSE,

Avista, Idaho Power) enjoyed adequate

resource flexibility from Mid C projects and/or utility-owned hydro resources

• BPA, BC Hydro, Mid C PUDs, Seattle, Tacoma

operate hydro resources with significant

flexibility – second-to-second, daily, seasonal

• The wind revolution and expiry of Mid C

contracts (starting in 2004 with Priest Rapids) changed the regional flexibility landscape –

PacifiCorp and PGE joined NWE as hydro flexibility “have-nots”

Role of Gas Resources to Meet Flexibility

Needs

• PGE, PacifiCorp, NWE, and (to a lesser extent)

PSE use gas-fired generation to follow load and resource deviations

• Maintaining load resource balance can be

particularly difficult in spring and over winter peak – may need to run gas out-of-merit for regulation margin

• Entities with surplus hydro flexibility (large

publics, BC Hydro/Powerex) generally make more money from load factoring (LLH to HLH) than providing regulation service

Types of Open Cycle Gas Turbines

• Frame SCCTs - Primarily capacity (large/fast w/controls)
GE 7EA, GE 7FA, Siemens 501G, etc.

85-350 MW

Heat Rate = 9400-11,400 Btu/kWh – rarely dispatch (under

2% of hours)

• Reciprocating Engines - Primarily flexibility (small/fast)
9-20 MW

Wärtsilä, Caterpillar (Basin Creek)

Heat Rate = 8500-9000 Btu/kWh – higher variable O&M limits

dispatch

• Aero derivative SCCTs - Capacity and flexibility (fast)
GE LM6000 (Highwood), GE LS100, P&W FT-8 (DGGS)
10-105 MW

Heat Rate = 8700-9500 Btu/kWh – infrequent dispatch (under

Open Cycle Turbine Dispatch

• Purchase spot market natural gas

• Infrequent dispatch complicates gas pipeline and

transmission strategy – Firm transport way too

expensive, but interruptible may be interrupted or reduced over winter peak

Avista Rathdrum – California storage and

exchange via GTN

Back-up fuel (DGGS)

● Smaller unit size and flat HR curve may make

reciprocating engines a better fit for flexibility requirements than other SCCT technologies

● Infrequent CT dispatch increases start-up forced

Combined Cycle CT Basics

• CCCT utilizes two turbine generator sets,

usually with separate shaft for each T-G:

Gas-turbine generator (GE Frame 7, MHI, or

Siemens) – thermal energy from fuel combustion directly spins the turbine

Steam-turbine generator – uses heat energy

from gas-turbine exhaust to create steam to spin a second turbine

• Add additional combustion capability after

combustion turbine to increase steam-turbine output (duct-firing)

CCCT Math

• Large gas turbines have a “heat rate” under

7000 Btu/kWh - describes the conversion of thermal energy into electrical energy.

• Natural gas generally priced in $/MMBtu • Incremental cost of production =

Heat Rate/1000 x (Gas Price + Variable

Transportation) x (1+ End Use Gas Tax Rate) + Variable O&M

• Depending on location of unit, may need to

factor incremental transmission and losses into the calculation

CCCT Incremental Cost Example

Heat Rate = 7000 Btu/kWh Gas Price = $4/MMBtu

Variable Gas Transportation = $.10/MMBtu

WA Gas Tax Rate = .038 (allows me to make a point)

Variable O&M = $3.5/MWH

Incremental Cost = (7000 Btu/kwh) /1000 x ($4/MMBtu +$.10/MMBtu) x (1 + .038) + $3.5/MWH = $33.3/MWH

But CCCT Dispatch Decisions Rarely

Straight-forward

• NW CCCT fleet usually sets daily market-clearing price

– wind and hydro push CCCTs in/out of the money

• CCCTs often economic HLH but uneconomic LLH

-$1.5/MWH in-the-money HLH, -13.0/MWH LLH on 6/1/13

• Start-up requires multi-hour ramp-up/ramp-down –

quick start package can shorten the ramp-up

• Maintenance contracts charge for starts after some

maximum (around 50/yr) - $3000-$5000/start

• Best CCCT heat rate at full load

Heat rate increases 1% for every 5% of output

reduction between 80% and 100% of rated capacity

Heat rate increases 2.7% for every 5% of output

CCCT Ramp (GE Product)

Quickly load GT - Start charge - High HR

GE Part Load Performance

CCCT Part-load Performance + LM6000

But Wait, There’s More

• Different schedule for gas day (9 AM – 9 AM

PPT/MPT 8 AM – 8 AM) versus electric day (midnight to midnight) introduces additional uncertainty on CCCT economics

• Dispatching CCCT up/down to minimize

electric imbalance charges could cause imposition of pipeline imbalance charges

• Location on transmission system could limit

ability to dispatch on some hours

Note the number of discontinuities and uncertainties inherent in CCCT dispatch decisions!

CCCT Duct-firing

• Standard GE Frame 7FA CCCT GT-STG

package includes 22 MW of duct-firing – could be as much as 60 MW for a 1x1 CCCT

configuration

• Duct-firing looks like a quick-start SCCT with

9400 Btu/kWh HR

• Duct-burner start and ramp to full output

takes about 10 minutes due to need to have plant operator configure equipment

• On the ragged-edge of fast enough to use for

And Did I Mention Hedging?

• Once you sign the confirm to purchase forward gas, the

unit price you paid has no bearing on dispatch decisions

• However, purchasing gas in the forward market at a

price well above the ultimate market price will attract attention, and

• Not purchasing gas in the forward market at a price

that turns out to be well below the ultimate market price will attract attention

• Depending on hydro conditions, load growth,

coal/nuclear performance, etc, a CCCT could dispatch on as few as 30% of the hours in a year and as many as 80% of the hours in a year.

Regardless of hedging strategy deployed, a CCCT operator needs good access to liquid natural gas and electric market hubs and/or suppliers to sell excess and cover deficits

Modeling Implications

• Hard to predict CT actual operation with a

dispatch model (requires perfect knowledge)

• Many examples of out-of-merit dispatch –

aware of one entity that won’t turn CCCT on unless in the money on a multi-week basis, then doesn’t adjust output until market

indicates unit uneconomic on a multi-week basis

• Hydro flexibility often used to keep CCCTs

either just in or just out of the money – some dispatch models handle hydro complexity

Integrated Uncertainty

• NWE Standards of Conduct limit ability of NWE

Transmission to coordinate flexibility needs of the BAA with NWE Supply

• DGGS provides much of NWE’s BAA balancing needs,

with Shell Trading available to buy/sell real-time to “recenter” DGGS – NWE Supply currently receives no information on DGGS operation

• NWE Transmission called NWE Supply for Basin Creek

support during DGGS outage as an emergency measure

• NWE would need to change current model for provision

of balancing resources to fully utilize flexibility of

Supply-controlled natural gas generation resources and to minimize NWE overall expense for natural gas

Final Points