Gas to electric power generation potential

September 19th, 2014, Published in Articles: Energize

 

Gas power generation (GPG) has increased significantly in the past few years , with gas overtaking coal in some countries. GPG offers greater efficiency and lower CO2 emissions than coal, as well as other operational advantages. The shale gas potential in South Africa as well as natural gas discoveries in southern Africa have increased the potential for CPG in this country and it is likely that development of gas powered sector will accelerate in the near future.

One of the risks associated with GPG is security of supply as SA does not have its own indigenous natural gas supply. This aspect of course will change if shale gas proves to be a viable option, and other developments such as coal bed methane and underground coal gasification could add to the security of supply

Advantages of gas for power generation

Construction time

Gas turbine power plant is far less complex that coal fired and hence has shorter construction times. As an example, the Eskom Ankerlig and Gourikwa plants were constructed in less than two years. The need to follow  demand growth closely favours equipment with short construction periods. Standard off-the-shelf designs are the norm for gas power stations.

CO2 emissions

Gas powered plant has approximately 40% less CO2 emissions per unit of power than coal, due partly to greater efficiency, but mainly due to the hydrogen content. This is a great advantage once carbon taxes come into effect.

Capital costs

According to a study done by the NREL [1] , gas power capital costs are about 40% of the equivalent coal fired cost. This is somewhat offset by the shorter lifetime of gas turbine and gas IC engine plant.

Flexible output

Rapid start-up,  ramp-up and ramp-down times enable gas power systems to follow variable and rapidly changing generation patterns of renewable energy sources.

Gas sources in South Africa

There are several different gas sources available for power generation in South Africa:

Natural gas (NG)

As its name suggests natural gas is obtained from gas wells. South Africa does not have a significant indigenous natural gas resource, with the main source of supply being the pipeline from the existing Mozambique gas fields. The pipeline has a capacity of 120-million GJ/a, sufficient to generate 18 400 GWh of electricity, approximately 7% of the South African annual consumption. New gas field discoveries on the east and west coasts of Southern Africa, as well as the development of stranded reserves, have opened the possibility of increased imports of gas, either via pipeline or in the form of liquified natural gas (LNG). Planned construction of a gas fired power station in Namibia has sparked development of the previously stranded gas fields in the area, with the possibility of gas import into South Africa. renewed interest in NG as a fuel source. NG has the typical composition shown in Table 1 .

Gas to power1

Table 1 : Typical composition of natural gas (Naturalgas.org [2]).

One of the factors which varies is the amount of CO2 contained in the gas. Some existing wells the high CO2 content makes the gas unusable and further processing is required. Natural gas has a typical calorific value of in the region of  35 MJ/m3.

Shale gas

Shale gas is similar in composition to natural gas and consists primarily of methane. Typical calorific values are similar to natural gas. The Karoo area contains the largest deposit of gas within the borders of South Africa, potentially estimated at anything between 500 and 300 trillion cubic feet (tcf) of recoverable gas. Shale gas has been a controversial issue over the past few years, but with the lifting of the moratorium on prospecting, the market is likely to develop rapidly. Sources are far from centres of consumption so it is very likely that gas powered generation plant may be established in the area as a first step. There are a number of solar PV and wind farms under construction or planned in the shale gas area and the prospect of a shale gas fired power plant co-existing with PV or wind farm offers an interesting option. Gas fired power plants are the first choice to balance the variability of renewables and co-location of GPP and RE would seem to be a logical step, and may provide leverage for the development of shale gas power. Co-location of CCGT plants with RE seems to be a logical conclusion.

Coal bed methane (CBM )

As its name suggests, CBM consists almost entirely of methane, trapped in coal beds. Traditionally regarded as a nuisance which would have to be removed from coal seams before mining could take place, CBM is now regarded as a valuable energy source, and several companies are investigating recovery CBM from deep coal seams which are unmineable in South Africa. CBM has a calorific value slightly lower than natural gas. The CBM potential for South Africa is uncertain. Many of the search and prospecting areas are close to existing power stations and offer the potential for conversion from coal fired .

Syngas (UCG/IGCC)

Syngas is gas derived from coal, either in an underground coal gasification scheme (UCG) or in an integrated gasification combined cycle (IGCC) power plant. Syngas consists primarily of carbon monoxide and hydrogen and has a typical calorific value in the region of 9 MJ/m3. IGCC operation offers the possibility to use coal that is unsuitable for pulverised coal boilers.

Integrated gasification combined cycle generation uses an  on site coal gasifier to produce syngas which runs the combined cycle gas turbine. Heat from the gasifier is also used in the heat recovery system to produce steam.

Underground coal gasification is an undeveloped potential source which offers the same advantages as the use of natural gas, namely reduced CO2 emissions plus the following additional potential advantages.

  • Local source of feedstock , namely coal – independence from imports
  • Technology advanced to ready-to-implement stage .
  • Potential lower prices than natural gas
  • No need to establish infrastructure – power station built on site
  • No mining activities involved
  • Use of unmineable coal extends coal lifecycle. – unmineable coal is un-exportable – an indigenous resource suitable only for beneficiation and not subject to world prices.
  • Could be applied to mineable coal as well

The potential for UCG in South Africa is estimated at 40-billion tons [3]. With UCG yields ranging from 3600 to 3260 Nm3/ton of coal this gives 40 x 3600-billion Nm3 of gas (108 tcf of gas) – more than the shale gas potential of this country or the offshore gas finds.  UCG produces a syngas type product whose useable components are hydrogen and carbon monoxide. Oxygen and air fed plants differ considerable in the amount of nitrogen. Table 2 gives the average composition of gas obtained from the test plant at the Polish central mining institute [4].

Gas to power2

Table 2: Composition of syngas obtained from UCG testplant (Stanczyck [4]).

Methane hydrate

Methane hydrates are ice-like solids that consist of methane and water. The methane molecules are enclosed in microscopic cages composed of water molecules. This is apotential future gas source which is estimated to contain more energy than all the currently known carbon fuel sources combined, this source resides at the bottom of the ocean on continental shelves, and under ice layers in permafrost areas [5]. Several pilot projects are being undertaken to tap this resource. There are fears that global warming may release some of this massive store into the atmosphere.

 

Existing gas power generations stations in South Africa

Gas turbine generation stations exist at Ankerlig, Western cape (1448 MW) and Gourikwa, Mossel bay (746 MW). Designed as peaking stations they are currently running on a higher duty cycle. Both are currently using diesel as a fuel source. There are several other smaller gas turbine generating stations in operation

Gas engines

Internal combustion engines

These are available in the size range of 1MW up to 18 MW the internal combustion gas engine is finding a wide application in the fields of standby generation, primary power generation for power farms, and onsite generation for critical applications. The engines are used increasingly in trigeneration systems where heat from exhaust gas is used to drive absorption chillers and to provide hot water.

Open cycle gas turbines (OCGT)

Open cycle gas turbine is a once through engine where the hot exhaust gas, at temperature ranging from 500 to 1000°C, is released into the atmosphere. OCGTs are characterised by rapid start up times and fast ramp rates. A typical lifetime would be 100 000 h or 3000 starts. These turbines are typically used in peaking operations. Efficiency is of the order of 35%. OCGTs can run on a variety of different gases. The turbines can be retrofitted to combined cycle operation using separate steam turbines. They are mainly used for peaking generation and dynamic load response for wind and solar variable generation.

Combined cycle gas turbines (CCGT)

Combined cycle or closed cycle gas turbines use the heat from the exhaust gas of the gas turbine to generate steam, in a heat recovery systems, which is used to drive a steam turbine. Two configuration are possible:

  • Separate units. In this case separate gas and steam turbines are used, each fitted with their own alternator, and run separately.
  • Single shaft units, where both turbines are mounted on the same shaft and drive a single alternator. A clutch is provided to couple the steam turbine to the shaft, which allows the two turbines to be operated separately.

CCGTs have claimed efficiencies of up to 60%. The units combine the rapid start-up and ramping capabilities of the gas turbine with the higher efficiency of the combined unit, and can be operated as a mid-term unit. There is an obvious start up delay on the steam turbine portion relative to the gas turbine, and the single shaft unit may operate under reduced power during the steam turbine start-up time.

Microturbines

Microturbines fall in the range of tens of kW to 200 to 300 kW. Characterised by a simplified design and delivered as self-contained units. Microturbines are mainly used for back-up power, or on site power generation for critical equipment. The units can run on an variety of different gases.

Fuel cells

Until recently regarded as back-up units and small primary power units using mainly hydrogen gas or methanol as fuel, fuel cells have now advanced to the stage where units of 200 kW and larger are available, and are being used as primary power sources, mainly for ICT data centres and high reliability installations such as hospitals. There are several installations of combined units with a total generation capacity of several MW in existence. Fuel cells of this size can be constructed to run on a variety of gaseous fuels such as natural gas, biogas, landfill gas and other non-conventional gases, and are suitable for installation where piped gas is available.

Plans for development of the gas industry in South Africa

In 2005, the then Department of Minerals and Energy published a document titled the “Gas infrastructure master plan” [6], which was “intended to be a strategy for the development of the natural gas industry in South Africa”. Little has happened since the publication of this plan and we are now faced with a new master plan, the gas utilisation master plan (GUMP). At the date of writing the GUMP has not made an appearance but according the DoE the master plan is well advanced and a draft should be released for public comment shortly. The preparation of  the GUMP may be taken to indicate that the DoE sees gas as a serious future energy source and intends to support the development of gas sources and infrastructure. The GUMP is intended cover all aspects of the Gas industry including sourcing, infrastructure and utilisation and will feed into the IRP and IEP. According to Michael Fichardt of the DoE [7], a gas based IPP program could be the first off-takers of the new gas distribution network and kickstart the program. The GUMP remains a mystery.

How much gas is required for power generation?

As an example consider how much gas would be required for baseload generation of 1000 MW using a CCGT.

Take following parameters for the CCGT

  • Net heat rate = 6500 kJ/kWh = 6500 MJ/MWh = 6 500 000 MJ/GWh
  • Calorific value of natural gas  =9,8 kWh/m3 or 35,2 MJ/m3

Gas required per annum at 90% duty cycle = 1 464 171 428 m3 = 51 699 893 142 cf

One tcf of gas would thus provide 1000 MW of power for approximately 20 years

Cost of gas generation

This is the most difficult aspect to consider as world LNG prices have varied considerable over the last few years. The fuel price for gas powered generation works out to roughly $0,006/kwh/$/MMBtu. So if the price of LNG is $5/MMBtu then the fuel cost would be $0,03/kwh or about R0,3/kwh.

Fast track solution for the gas network

It has been proposed that a “fast track” LNG based gas network be set up to establish the gas industry in anticipation of a more formal plan of action [8]. Such a network requires an “anchor customer”, and power generation fulfils this role ideally. Ankerlig is an obvious candidate user for a LNG terminal located in the Western Cape. Other possible customers include the existing gas turbines located in coastal areas, which could be converted to run on gas, and IPP gas projects.

Take Ankerlig as the anchor customer. The maximum nominal power generation capacity is given as 1338 MW. The performance of a gas turbine is affected by a number of operating parameters, including humidity and air temperature and the following parameter values are estimated for the purpose of illustration of the operation of an OCGT.

  • Net heat rate = 10000 KJ/kWh  = 10 MJ/kWh
  • Calorific value of natural gas = 9,8 kWh/m3 or 35,2 MJ/m3

Energy produced per m3 of gas = 35,2/10 = 3,52 kWh/m3

Then gas consumption (m3 /MWh) = 1000/3,52 = 284 m3/MWh

Total gas consumption = 284 x 1338 = 379 992 m3/h or 13 413 717 cf/h (13.4 Mcf/h)

Alternatively 379 992 x 35,2 MJ/hr = 1 337 318,4 MJ/hr.

A possible FSRU based LNG terminal is the Dubai LNG terminal [8]. This has a gasification capacity of 400-million standard cubic feet per day (mmscfd) or 16-million m3/day.

Table 3 lists the daily consumption under different operating regimes, considering the possibility of converting to CCGT and operating as mid term unit for longer periods What percentage of a possible terminal would this consume? Capacity of an offshore gas liquefier or LNG container ship.

FSRU varies in size from 130 000 m3 to 180 000 m3 with gasification rates of 400-million scf/d = 16-million scf/hr to 700-million scfd.

 

Gas to power3

Table 3: Daily gas consumption for Ankerlig under different regimes (author’s calculation).

 

Table 3 shows that under peaking conditions of 1hr/day, the Ankerlig station will consume 3,35% of the daily capacity of the regasifier, and when running as baseload uses 80,35 % of the capacity, ie would almost require a dedicated SFRU for an output of approximately 2000 MW.

However, when it is running at full capacity the power station consumes 83,75% of the regasifier capacity, so some form of storage would be necessary to allow other users to be served.

On the face of things with a single gas power station consuming up 40% of the gasifier capacity running as mid term may well justify the investment in an LNG terminal. Ankerlig is only one power station in the WC and although FSRUs are available with gasifcation rates up to 700 mmscfd ,at first sight it does not seem that using an FSRU to supply gas fro power generation will be viable, and a larger onshore permanent terminal would be required. Saldahna Bay municipality has such a terminal in mind [9].

Application of LNG for power generation.

Floating gasifiers might provide an entry for gas power generation, provided smaller gas turbines are envisaged. Large scale application of LNG for power generation would require higher gasification rates than are possible with SFRUs and land based LNG storage and gasification terminals would need to be constructed.

It can be seen from the above example that running large gas powered stations from LNG might not be practical unless onshore gasifiers and LNG storage facilities are provided. A possible solution for future gas generation using LNG  would be co-location of generation plant with onshore LNG storage, which would allow dedicated storage and vapouriser/gasifier for the power plant without affecting gas supply to other users. With the case of WC and other coastal terminals a dedicated storage/gasifier and pipeline feeding the existing gas plant may be the long term solution.

Saldhana Bay

Plans are at an advanced stage for the construction of a LNG terminal and distribution pipelines at Saldhana Bay [9]. The possibility of a permanent onshore storage and gasification plant are being considered as well as a SFRU option to supply and estimated demand of 89 MMBtu/A (1,8 MMt/A). The preliminary study identified several different possible LNG sources.

Coega

Original plans were for an onshore gasification plant with a co-located power generation island. Options were considered for power generation using CCGT with capacities from 800 MWe which would require a LNG ship delivery every 22 days, to 3200 MW which would require an LNg ship delivery every five days [10].

Mosselbay

Considered as a strong contender to supplement the dwindling supply of gas from the existing gasfield, the project has been shelved due to offshore conditions being found unsuitable.

References:

[1] R Tidball: “Cost and performance assumptions for modelling electricity generation technologies”, NREL Report NREL/SR-6A20-48595, November 2010, www.nrel.gov/docs/fy11osti/48595.pdf

[2] Naturalgas.org: “Óverview of natural gas”, http://naturalgas.org/overview/background/

[3] Eskom: “COP17 fact sheet, underground coal gasification”, www.eskom.co.za/OurCompany/SustainableDevelopment/ClimateChangeCOP17/Documents/Underground_Coal_Gasification.pdf

[4] K Stanczyk: “Experience of the central mining institute in underground coal gasification research and pilot test.  Fossil Fuel Foundation underground coal gasification conference, Johannesburg, 28 August 2104.

[5] GA Olah, A Goepert, and G Surya Prakash: “Beyond oil and gas: the methanol economy” 2006.

[6] Department of Minerals and Energy: “Gas infrastructure plan” www.energy.gov.za/files/media/explained/statistics_gas_infrastructure_2005.pdf

[7] M Fichardt: “Gas utilisation master plan” Fossil Fuel Foundation gas conference, 21 May 2014.

[8] J Schoobridge: “LNG – a fast track solution to meet South Africa’s energy needs” Fossil Fuel Foundation gas conference, 21 May 2014.

[9] Western Cape Government: “LNG importation initiative-Saldhana-Cape Town corridor”: Fossil Fuel Foundation gas conference, 21 May 2014.

[10] Coega IDZ: “Coega presentation, CCGT EOI session” www.coega.co.za/DataRepository/Documents/taP74_EOI%20Project%20Overview%20Presentation.pdf

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