Featuring Oxygen-Blown PRENFLO Coal Gasification
3. Syngas Operation
Natural Gas LHV = 50056 kJ/kg
2. Syngas Operation Non-Integrated
Concept
Syngas LHV = 10000-15000 kJ/kg
(undiluted") : 5000-10000 kJ/kg
(„diluted")
1 1 0 - 1 2 0 % 1 0 0 % Due to exceeding the surge limit, adaptation of the compressor necessary I
3. Syngas Operation Integrated
Concept
r
r—
<8>
2 0 - 2 4 %
= = Syngas LHV = 4000 - 5000 kJ/kg
K Air to Air Separation Unit approx. 1 5 - 2 0 %
Figure 4: Influence of integration concept on gas turbine/ compressor mass flow ratio
Number of gas turbines Air extraction for ASU from 1 gas turbine
• related to ASU demand
• related to compressor mass flow Nitrogen for syngas dilution (related to ASU production) Fuel gas saturation
• syngas
• syngas/nitrogen mixture Fuel gas temperature
Dimension j
-
%
%
%
-
°C
°F
DEMKOLEC
1
100
16
100
+
300 572
ELCOGAS
1
100 18
100
+
302 576
ISAB Energy
2
0
0
0
+
195 383
Figure 5: Comparison of main gasside and integration characteristics
Coal gas
Stop valve Control valve
V G 8 Kraflwerkslechnik 74 (1994), Heft 6
Figure 6: ICoalGCC Buggenum, fuel supply system for coal gas and natural gas
Fuel oil return
Fuel gas flow to the pilot burner nozzle Fuel gas flow to the diffusion burner nozzle-
Fuel gas flow to the premixed burner nozzle
Diagonal swirler
Fuel gas/air mixture for the premixed operating mode
Fuel oil inlet iSteam or water
•Water injection
Main air flow
Fuel gas for diffusion burner
Figure 7: Siemens standard hybrid burner Siemens syngas burner
3 0 % 4 0 % 5 0 % 6 0 % 7 0 % Power Output Combined Cycle
Figure 8: Measured CO- and NOx-emissions, coal gas operation ICGCC Buggenum, Siemens gas turbine model V 94.2
Subject:
Paper for :" Gasification Technology in Practice "
Authors:
M. Baldizzone R. Macchia P. Zanello
( FIAT AVIO " Power plant design and construction - Application Engeneers -" ) Title:
ELECTRICITY FROM NON CONVENTIONAL FUELS IN HIGHLY EFFICIENT P O W E R PLANTS
)
Pag. 1
INTRODUCTION
Gas Turbine is recognised as the best prime mover for modern Power Plant based on Simple Cycle as well as in Combined Cycle configuration according to the features of the specific Project.
Presently Gas Turbines manufacturers have two main objectives:
• Technological improvement in order to get better performance and in this way to reduce fuel consumption involving new materials as well as component design
• Proper engine and system design in order to allow as much as possible the direct use of fuels typically not palatable for gas turbines
Capability of burning a wide range of fuels in a Gas Turbine power Plant has become, in the last years, a very important factor, due to fuel availability, quality and cost.
The direct use of fuel into the Gas Turbine is widely the most economic way to use it unfortunately there are limits in physical and chemical properties that can not be overcome from engine as well as system stand point.
Gasificationis a typical process used to get fuel palatable for the gas turbine even if the resulting gas, because of its low calorific content, requires some engine readjustment in order to allow the increased mass flow through the turbine.
The available experience in both fields of FiatAvio - Mitsubishi H.I. - Westinghouse GT family, direct use of contaminated fuels as well as burning low BTU gas from gasification process, is reported highlighting the most important technological aspects associated to the engine and the system in both cases.
CONTAMINATED FUELS
Fuel availability and costs considerations are the key parameters for selection of residual oil as primary fuel. Its price is generally variable, but as a general rule a difference between twenty to one hundred percent compared with light oil price can be assumed in economical evaluations.
This evaluation has to be based on many variable effects such as electric power selling price, power plant running time, fuel costs, fuel treatment and additivation costs, additional maintenance. An accurate analysis and its direct validation through actual plant operation experience is necessary for a final answer. On a general basis, considering that treatment costs will never increase fuel cost, by more than 20% economical benefits are typically obtained.
CRITICAL ASPECTS OF BURNING CONTAMINATED FUEL IN GAS TURBINES
These fuels have a high level of contaminants because they contain all these already existing in the crude, plus some introduced in the refining process and transportation. The effect of these compounds can be a corrosive action on the Gas Turbine hot parts.
An additional area of possible problems is related to the low level of Hydrogen and the considerable presence of Asphaltenes. These components are responsible for high flame radiation, causing severe operating conditions for turbine hot parts. These effects can be compensated by an adequate reduction of engine firing temperature.
In addition to that, residual fuel physical characteristics', namely density and viscosity, require care in fuel handling to assure adequate pumping and atomisation capability.
Pag. 2
The above mentioned corrosive phenomena, due to Sodium, Vanadium and Potassium, occur at high temperature involving the turbine components working on direct contact to the combustion gases at temperature above 600 °C.
Usually they are due to a reaction between the oxides and melted substances present in the combustion gases.
The corrosion occurs when the protective oxide layer of the metal surfaces is broken. As it is destroyed, non oxidised metal is exposed and attacked with a continuous process. In particular the corrosion propagation due to Sodium attack is inter-granular, and therefore the material matrix is disintegrated with consequent decrease of the heat resistance of the alloys, especially under the action of mechanical and thermal stresses. The improvement of high temperature corrosion resistance of Nickel and Cobalt alloys has therefore become a key point both under a technical and economical viewpoint.
Sodium and Potassium, combined with Vanadium, form eutectic salts whose melting point is lower than 566 °C; when combined with sulphur, they form sulphates which start their corrosive effect at a temperature which is in the operating range of the Gas Turbine.
Na + K level must thus be limited and considering that they are water soluble this is possible by means of fuel washing.
Vanadium is present in the fuel in the form of metal-organic compound (Vanadium - Porphirin) and cannot be removed with chemical or physical treatments; its negative effects are inhibited with an oil soluble Magnesium additive.
The Magnesium will combine with Vanadium to form compounds which have a melting point higher than turbine operating temperature. It is very imponant to assure that all the Vanadium is inhibited by the additive; on this regard a consolidated experience shows an optimum additivation ratio Mg/V=3.
An adverse effect of Magnesium additivation is related to consistent deposits of Magnesium compounds on turbine parts.
These deposits can be responsible for engine performance deterioration, combustion asymmetry with increase of temperature spread and sometimes modification of engine vibration behaviour.
The deposits are however water soluble, so that they can be removed by proper turbine water washing which frequency is considerably depending on engine operating mode. Frequent starts and stops are typically beneficial with the deposit spalling off subsequent to the thermal transient phases.
The physical fuel characteristics require special care in plant design. Because of its high viscosity, the residual fuel must be heated for handling purposes and to ensure adequate atomisation in the Gas Turbine injectors.
Moreover the fuel requires a specific operation procedure. It is normal to start and stop the Gas Turbine on distillate oil to avoid plugging of piping, filters and nozzles downstream the heaters;
for the same reason fuel pipes must be purged with distillate oil after every emergency shut down or trip.
Another key point is a constant control and monitoring of the fuel quality to tune the treatment system to the actual fuel composition.
Pag. 3
FUEL TREATMENT
The proven approach to overcome the above mentioned turbine corrosion problems is based on:
• fuel washing in order to reduce Sodium and Potassium contents;
• fuel additivation to inhibit Vanadium corrosion effect.
Fuel washing
In order to reduce the contents of Sodium and Potassium FiatAvio has adopted in the latest application a two stage electrostatic fuel treatment system.
Nominal performance for these treatment plants, is a Sodium plus Potassium content in the residual oil at treatment system outlet not exceeding 0,5 ppm.
The untreated residual oil is heated first by means of steam to a proper temperature to reach the optimum viscosity for the electrostatic process. Subsequently, fresh water is added to the residual oil and is mixed with it in order to dilute the water phase, that contains all the contaminants. Fresh water i; added to the second stage and then pumped from a re-cycle water pump to the first stage in order to get the maximum efficiency at the final stage with a counter flow effect. In order to minimise the water requirements inside the pressurised vessel, the electric field created by a high voltage transformer (short circuit proof type), increases of thousands of times the phenomenon of water droplet coalescence, thus achieving a separation of the two phases:
• In the bottom of the vessel, water that contains almost all the Sodium plus Potassium previously dispersed in the fuel;
• At the top of the vessel, a water free residual oil.
De-emulsifier is injected before each stage.
Fuel additivation
A Magnesium organometallic oil soluble additive injection system is used to inhibit the Vanadium compound. The system consists of a tank, a circulation pump and dosing pump which inject the additive in the high pressure line downstream the fuel injection pump of the Gas Turbine.
The additive injection point has been selected near to the Gas Turbine fuel nozzles, in the high pressure line downstream the final filter, and upstream the fuel flow divider in order to have the best mixing of additive with fuel and therefore the best inhibition effect.
FUEL SYSTEM
The fuel system of a plant burning residual oil is typically composed by:
• Distillate oil system
• Residual oil system
Distillate oil is adopted to start up and shut down the Gas Turbine and consists of standard system with no specific features.
Residual oil system shall be designed to overcome the above mentioned physical characteristics of residual oil and perform fuel treatment.
From the unloading bays the residual oil is stored in the untreated tanks, than is transferred to the treatment plant to remove water soluble Sodium and Potassium.
Pag. 4
The treated residual oil is then forwarded to certification tanks. When one of the two certification tanks is full, the treated oil is certified by chemical analysis. If the contaminants level comply with fuel specification, the fuel is transferred by the pump station to the Treated storage tanks. If the fuel does not comply with specification it is sent back to the untreated tanks to be treated again.
All the tanks of the residual oil handling system are insulated and provided with bottom heating coils capable to maintain the residual oil at the temperature which allows fuel handling (typically 50°C).
Each Turboset is fed by a residual oil forwarding pump. A final heater is installed on each Gas Turbine supply line upstream the fuel change over valve.
An automatic fuel change over valve is used to switch from distillate oil to residual oil after start up and vice versa during shut down. The automatic fuel change over valve, one for each GT., is a three ways valve, electrically operated, installed on the forwarding pump station. One three ways valve, one for each GT., is also installed on the recirculation line to tanks: the valve is necessary to send back residual oil to residual oil tank and distillate oil to distillate oil tank.
L O W BTXJ GAS
The integration of a combined cycle with a gasification plant is an evolution imposed by different reasons:
• availability of consolidated gasification technologies to gasify different low commercial value products or to gasify refinery slag.
• increased quantity of those products caused by ambient protection regulations aggravation
• government aids to auto production
• high commercial value by-products
T h e integration of a combined cycle gas turbine in such a plant requires a deep analysis; the accuracy of the analysis covering all aspects technical as well as economical has an important impact on the initial investments and on operating results.
IGCC plant is competitive respect other plants like:
• Conventional plants with desulfuration and denitrification
• Plants with partial gasification and conventional combustion They have increased performances like:
• High combined cycle efficiency (approx. 46% referred to electric power in lieu of 34% of a conventional thermal plant, and 90% referred to the total utilised power (eiectric and heating power)
• Production costs similar to those of conventional thermal plants with lower emission values
• Potential technologies evolution in order to increase efficiency (target 52%) e reduce emissions levels.
Otherwise:
• Higher investments costs
• More interconnected systems
• Insufficient acknowledgement to guarantee application of large power plants.
Pag. 5
I IMPACT ON THE PLANT
r To operate with low BTU gas the GT compressed air feeding the combustion section must be reduced respect to the design value usually based on natural gas or distillate oil. The reduction changes with the ambient temperature and the load. The limitation could be obtained with compressor bleed or inlet air reduction.
The air required by the Air Separation Unit could be fed by the air bleed from the GT compressor. Otherwise an independent air compressor should be installed.
The independent compressor increases the flexibility of the system, has a rapid response in starting or tripping phases, and at part load.
The compressor air bleed increases the global efficiency of the plant. Anyway a complementary independent compressor has to integrate the insufficient air bleed flow. Control system will be adequate to manage much more parameters.
Two possible solutions are typically examined for emission control:
• Nitrogen injection [) • Steam saturation
Different is the impact on the plant; to have the same NOx reduction nitrogen mixed quantity is bigger than corresponding steam. It requests larger size piping.
The percentage of steam can be limited; a catalaiser, dimensioned to reach the imposed value, is installed on the exhaust section.
The particular syngas composition (high hydrogen and Carbon oxide content) imposes classification areas, where gas piping is installed, in Class 1 Division 2 Group B according NFPA 70. The interested areas are:
• Gas turbine enclosure
• Auxiliary systems enclosure
• Gas detection and treatment area
Gas detection and treatment area is open air and standard configuration was adequate.
All components installed on the gas turbine enclosure and auxiliaries enclosure are explosion -' proofing type. In the standard configuration only gas skid components are explosion proofing
type. Also fuel oil skid, lube oil skid, water injection skid are equipped with explosion proofing components.
Gas turbine and auxiliary enclosures standard ventilation systems are both provided of 3 50%
capacity extraction fans, two in operation and one in stand-by. For this application the system will be provided with two 100% capacity each, fans one in operation and one in stand-by Purge time will be increased in order to assure the total volume changing 6 times in lieu of 3 as per standard.
Gas piping vent system has been implemented with a nitrogen purge system to assure, at fuel changeover or at trip the total elimination of syngas. A system with bottles, piping, valves and automation was added.
Gas detection system already existing on standard gas turbine and auxiliary enclosures, was been implemented with CO detectors, to assure personnel safety.
Pag. 6
IMPACT ON THE ENGINE
The design of a combustor for a syngas application requires special care to:
• Take into account the higher flame speed of syngas, typically with significant amount of H2)
several times greater than of methane. Consequently will have a rather short flame compared to that of methane-based natural gas, impacting on the cooling requirements of the combustor dome and on the primary zone local equivalence ratio.
• The amount of fuel injected through the combustor fuel ports is much greater than the typical amount of natural gas. Such a large amount calls for a careful dimensioning of primary, secondary (if any) and dilution scoops (chutes) together with sizing cooling air devices devoted to keep the combustor wall temperature down.
The above impose design choices which might not be enough proven or are totally new. This usually leads to hot rig tests of the combustor prior of installing it into the engine.
One combustor has been designed referring to a preselected fuel composition. As most of the design choices were based on standard practices it was decided to have an extensive run of rig tests to validate the final design. The tests were carried out with the same syngas composition used for design and rig geometry as closely as possible to engine pressure shell configuration.
Low pressure tests
Tests were carried out from No Load (0%) to Base Load (100%) with 20% power increments.
Ignition was attained at a rather low F/A with respect to nominal conditions, to prevent the possible accumulation of large quantities of unlit fuel at the stack.
Weak extinction limits were investigated at each of the above conditions by reducing fuel flow in small steps (~ 10%o) until the exhaust thermocouples indicated flame extinction. Also a rich point (nominal + 20%) was run to investigate flame stability in the rich zone.
Emissions (NOXj CO and UHC) were recorded at the T/D exit and at the EPA. Combustion efficiency was in excess of 99.7%. Maximum metal temperature topped at 1123 K in the first cooling ring when running the 100% load simulated condition. Visual investigation after these test showed some distortion on the dome cooling skirt indicating temperatures around and over 1173 K, possibly caused by the very short flame occurring at this low pressure conditions.
The combustor was performing with good ignition characteristics and with a wide stability range; also emissions, especially CO emissions were much lower than expected. (See fig. 1 & 2) High Pressure Tests
Testing conditions simulated engine running at No Load and Base Load conditions.
The ignition was carried out with no problems. For Base load test it was decided to rise the rig pressure by oil running and performing a fuel switch over to syngas once reached the test conditions.
The fuel transfer was successful with no signs of combustion instabilities during the process.
During Base Load with syngas a complete exhaust traverse reading at sixteen equally spaced angular positions at T/D exit was done. A simulation of engine load rejection was attempted by suddenly cutting down the fuel flow to the No Load value; no problems with flame stability were experienced.
Syngas emissions test results (all the NOx emission values are dry - 15% 02 corrected, all the other emission are on dry basis) are given in Table 1. Combustion efficiency was found to be in excess of 99.9%
Pag. 7
The highest recorded metal temperature was about 1150 K in the second cooling ring, this showing that the flame peak has moved downstream from the position it took when running at low pressure, as it was expected because of the higher fuel flow. Combustion-induced pressure fluctuations when running the syngas high pressure tests were rather small if not negligible.
On oil running a complete exhaust traverse reading was carried out at each of the test conditions (i.e. with different water/fuel ratios). Emissions results are given in Table 2.
Basket metal temperature were found to be lower than with syngas with a peak maximum temperature o f - 893 K. This was expected because of steam injection and because of a longer more narrow flame shape.
Additional tests were carried out to investigate the syngas combustion properties while changing steam content (25%, 36% to 45%, the case with 35% steam added being already tested).
In the end these tests showed that the syngas combustor gave good performance when handling different syngases. CO emissions, source of primary concern, did not increase when increasing the syngas steam content and seemed to reach a plateau of minimum value at nearly the maximum steam content. Stability at all conditions was satisfactory (pressure fluctuations well ) below 10 kPa).
The emission results for Syngas Base Load tests, that is, the NOx level, were transposed to the actual engine conditions to give the following (all values are):
Syngas N°l from 20.4 to 32.4 ppmvd - 15% 02
Oil w/ W/F=0.6 from 59 to 85 ppmvd - 15% 02
Oil w/ W/F=078 from 45 to 65 ppmvd - 15% 02
Oil w/ W/F=0.96 from 35.6 to 50 ppmvd - 15% 02
GAS TURBINE
Both reported studies have been based on use of TG 50D5 gas turbine.
The machine is a result of 45-year history of developing and manufacturing large heavy duty combustion turbines for industrial and utility service. It is the current production version of the ) large 50-Hz combustion turbine first developed by Westinghouse and its licenses, Fiat Avio and
Mitsubishi, in the mid-1970s. This development was derived from the highly successful Westinghouse model W501 series of large 60 Hz units, first introduced in the late 1960s. The combined Westinghouse/Fiat/Mitsubishi fleet of such large combustion turbines totals more than 300 operating units. Collectively they display an excellent record of high reliability, availability and economy both in simple and combined cycle applications.
EXPERIENCE
Within the FiatAvio - Mitsubishi H.I. - Westinghouse family operating experience of TG 50D5 is available on contaminated fuels as well as Low BTU gas
Al Nasseriah and Zayzoon Syrian power plant in operation from 1995 with residual ( Viscosity = 7 °E, Na + K = 20 ppm, Va = 60 ppm)
Plaquemine (Dow Chemical) and Kawasaki Steel are most important low BTU gas operation experiences:
A 7 years long experience has been accumulated by Plaquemine Power Plant, burning a 239 BTU/SCF gas from coal gasification process (41.41 % H2, 38.52 % CO, 0.11 % CH4, 18.49 %
Pag. 8