Combined Cycle Gas Turbine System

FIELD OF THE INVENTION

The invention relates to a combined cycle gas turbine system and a method of operating the system. In particular, although not exclusively, the invention relates to a combined cycle gas turbine system utilizing methane obtained from a coal bed. BACKGROUND TO THE INVENTION

Methane gas is often generated within a coal deposit as a result of the metamorphic process that occurs during the transition of peat to anthracite coal. The methane is stored in a near liquid state within pores of the coal and is also held in cracks or water pockets throughout the deposit.

When the coal deposit is to be mined, the entrained methane must firstly be removed for safety reasons. Firstly, an area of the coal deposit, which is about to be mined, is drained to give mine drain gas (MDG). MDG is also known as goaf gas or gob gas. MDG is typically 40-60% v/v methane; however, the composition of the MDG can vary during the drainage operation depending upon the area of the deposit being drained.

Additionally, methane is released as the mining operation takes place and the coal is broken into pieces. The mine must therefore be continuously ventilated to prevent an unsafe build-up of methane gas. The vented air contains vent air methane (VAM) at approximately 0.3-1.0% v/v. Removal of VAM from the mine must also continue after the coal has been mined as methane may continue to be released from the area for some time.

In the past, MDG and VAM were vented into the atmosphere. However, methane is a potent greenhouse gas. In terms of emission reduction units (ERU, as defined by the Kyoto Protocol), methane has a value of 21 ERU. In other words, 1 kg of methane released into the atmosphere is considered to be equivalent to the emission of 21 kg of carbon dioxide. With the advent of pressure from government bodies to reduce carbon emissions, there are significant financial advantages as well as environmental benefits to reducing the release of methane into the atmosphere.

When 1 kg of methane is combusted in air, the combustion reaction results in 2.75 kg of carbon dioxide. Thus combustion of methane reduces the ERU from 21 to 2.75. Accordingly, the combustion of methane has been used by mines to reduce carbon emissions.

For example, methane from coal mines has previously been combusted to provide power when the methane gas is of a high concentration (>75% v/v), as described in US 2009/0301099. For gas having a lower concentrations of methane or a variable concentration, the methane has been required to be concentrated, or combusted in a flameless oxidiser, prior to use in a power generation system, as shown in WO 2008/079156 and US 5,921 ,763.

OBJECT OF THE INVENTION

It is an object of the invention to overcome or at least alleviate one or more of the above problems and/or provide the consumer with a useful or commercial choice. SUMMARY OF THE INVENTION

In one form, although it need not be the only or indeed the broadest form, the invention resides in a power generation system comprising:

at least one gas turbine having an air intake and an exhaust system;

a heat recovery steam generator having a duct burner, the heat recovery steam generator being supplied with exhaust gas from the exhaust system of the at least one gas turbine;

a mine drain gas supply unit for supplying mine drain gas to the duct burner; and

a steam turbine driven by steam generated in the heat recovery steam generator.

Preferably the duct burner is supplied with up to 95% v/v mine drain gas and between 5% and <100% v/v fuel gas. Suitably, approximately 70-95% v/v mine drain gas and approximately 5-30% v/v fuel gas is used. In a preferred embodiment, the duct burner is supplied with approximately 90% v/v mine drain gas and approximately 0% v/v fuel gas.

In one embodiment the power generation system also comprises a vent air methane supply unit for supplying vent air methane to the air intake of the at least one gas turbine.

In another embodiment the power generation system also comprises a vent air methane supply unit for supplying vent air methane to the duct burner of the heat recovery steam generator.

Preferably the power generation system includes at least one redundant gas turbine. In another form, the invention resides in a method of generating power including the steps of:

providing air to an air intake of at least one gas turbine;

compressing the air and directing it to a combustion chamber of the gas turbine;

mixing the air with a fuel gas and combusting the mixture in the combustion chamber to give an exhaust gas;

utilizing the exhaust gas to drive the gas turbine and subsequently directing the exhaust gas to a heat recovery steam generator;

supplying mine drain gas to a duct burner of the heat recovery steam generator;

combusting the mine drain gas in the duct burner to generate steam within the heat recovery steam generator;

utilizing the steam generated by the heat recovery steam generator to drive a steam turbine; and

generating power from the driving of the gas turbine and the driving of the steam turbine.

In one embodiment, the method further includes supplying vent air methane to the air intake of the at least one gas turbine.

In another embodiment, the method further includes supplying vent air methane to the duct burner of the heat recovery steam generator.

Further features of the present invention will become apparent from the following detailed description. BRIEF DESCRIPTION OF THE DRAWINGS

To assist in understanding the invention and to enable a person skilled in the art to put the invention into practical effect preferred embodiments of the invention will be described by way of example only with reference to the accompanying drawings, wherein:

FIG 1 shows a flow diagram of the power generation system according to one embodiment of the invention;

FIG 2 shows a flow diagram of the power generation system of FIG 1 further including a VAM filter;

FIG 3 shows a flow diagram of the power generation system according to a second embodiment of the invention;

FIG 4 shows a flow diagram of the power generation system according to a third embodiment of the invention; and

FIG 5 shows a flow diagram of the power generation system according to a fourth embodiment of the invention.

DETAILED DESCRIPTION OF THE INVENTION FIG 1 shows a power generation system 100 that converts methane, liberated from a coal deposit, into power. The power generation system 100 includes a vent air methane (VAM) supply unit 110, a mine drain gas (MDG) supply unit 120, a fuel gas supply unit 130, three gas turbines 140, a heat recovery steam generator 150 and a steam turbine 160.

The VAM supply unit 110 supplies VAM collected from a ventilation system servicing a coal mine. Typically, the VAM is 0.3-1.0% v/v methane gas.

The MDG supply unit 120 supplies MDG collected from a methane drainage system servicing an area of a coal mine prior to a mining operation. MDG is typically 40-60% v/v methane.

The fuel gas supply unit 130 supplies fuel gas from a commercial gas supplier. The fuel gas is a pipeline quality gas, normally containing >95% v/v methane.

The gas turbines 140 each include an air intake 141 , a combustion chamber 142 and a gas exhaust system 143.

The air intake 141 draws air into the gas turbine 140 and compresses it to form a high pressure gas. The air intake 141 of the gas turbine 140 also receives VAM from the vent air methane supply unit 110.

The combustion chamber 142 receives the high pressure gas from the air intake 141 together with a fuel gas delivered by the fuel gas supply unit 130. The combustion chamber 142 is used to combust the high pressure gas together with the fuel gas to produce a high pressure and high temperature exhaust gas.

The gas exhaust system 143 collects exhaust gas from each gas turbine

140. Additionally, a first electrical generator 144, as is commonly known in the field, produces the power generated by each of the gas turbines 140, if required. An external compressor 145 provides a cool air stream to the blades of the gas turbine 140.

The heat recovery steam generator 150 includes a duct burner 151 and a heat exchanger 152. The heat recovery steam generator 150 is sized to have the capacity to receive exhaust gas from the gas exhaust system 143 of a minimum of one gas turbine 140.

The duct burner 51 receives mine drain gas from the MDG supply unit 120 as well as receiving fuel gas from the fuel gas supply unit 130. The duct burner 51 is used to combust the mine drain gas and the fuel gas to provide heat.

The heat exchanger 152 is located within the heat recovery steam generator 150 to receive heat from the duct burner 151 and from the exhaust gas from the gas turbines 140. The heat exchanger 152 contains water which forms steam when heated.

The steam turbine 160 is supplied with steam from the heat exchanger 152. A second electrical generator 162, as is commonly known in the field, produces power which is generated by the steam turbine 160. A condenser cooling system 170 cools the exhaust steam from the steam turbine 160 and returns it as liquid water to the heat exchanger 152.

In operation, VAM is supplied by the VAM supply unit 1 10 to the air intake 141 of each gas turbine 140. The VAM is compressed and supplied to the combustion chamber 142. In the combustion chamber 142, the compressed VAM is mixed with fuel gas from the fuel gas supply unit 130 and the mixture is combusted to give a high pressure and high temperature exhaust gas.

The high pressure and high temperature exhaust gas drives the turbine blades (not shown) of the gas turbine 140. The turning turbine blades produce power in the first electrical generator 144.

In standard operations, air is bled from the compressor of the air intake

141 of the gas turbine 140 and used to cool the blades and vanes of the gas turbine 140. When VAM is supplied to the air intake 141 , a bleed from the compressor would include VAM which would oxidize and generate additional heat if it were directed as a cooling stream. Therefore an external compressor 145 is used to cool the blades and vanes of the gas turbine 140 when VAM is being supplied to the air intake 141. Alternatively, the external compressor 145 is not used and the turbine blades of the gas turbine 140 are cooled by other methods such as a flow of steam or an air bleed from a gas turbine which does not utilize VAM.

After driving the gas turbine 140, the exhaust gas maintains a significant amount of heat and is collected by the gas exhaust system 143. The exhaust gas is then directed to the heat recovery steam generator 150.

The duct burner 151 combusts the fuel gas from the fuel gas supply unit 130 and MDG from the MDG supply unit 120. Preferably, the duct burner 151 utilizes the fuel gas to maintain a pilot flame, and fires with the MDG. A typical usage ratio is 10% v/v fuel gas and 90% v/v MDG. Suitably, approximately 70- 95% v/v MDG and approximately 5-30% v/v fuel gas may be is used, although ranges of 5% to less than 100% v/v fuel gas and up to 95% v/v MDG may also be considered.

The quantity of MDG may be about 0.1%, 0.5%, 1%, 5%, 10%, 15%,

20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 92%, or 95% v/v. The quantity of fuel gas may be about 5%, 8%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 95%, 99%, 99.5% or 99.9% v/v.

Supply to the duct burner 151 may therefore comprise 0.1 % v/v MDG and

99.9% v/v fuel gas, or 0.5% v/v MDG and 99.5% v/v fuel gas, or 1 % v/v MDG and 99% v/v fuel gas, or 5% v/v MDG and 95% v/v fuel gas, or 10% v/v MDG and 90% v/v fuel gas, or 15% v/v MDG and 85% v/v fuel gas, or 20% v/v MDG and 80% v/v fuel gas, or 25% v/v MDG and 75% v/v fuel gas, or 30% v/v MDG and 70% v/v fuel gas, or 35% v/v MDG and 65% v/v fuel gas, or 40% v/v MDG and 60% v/v fuel gas, or 45% v/v MDG and 55% v/v fuel gas, or 50% v/v MDG and 50% v/v fuel gas, or 55% v/v MDG and 45% v/v fuel gas, or 60% v/v MDG and 40% v/v fuel gas, or 65% v/v MDG and 35% v/v fuel gas, or 70% v/v MDG and 30% v/v fuel gas, or 75% v/v MDG and 25% v/v fuel gas, or 80% v/v MDG and 20% v/v fuel gas, or 85% v/v MDG and 15% v/v fuel gas, or 90% v/v MDG and 10% v/v fuel gas, or 95% v/v MDG and 5% v/v fuel gas.

Heat from combustion in the duct burner 151 , and from the exhaust gas from the gas turbines 140, heats the contents of the heat exchanger 152 to form steam. The steam is directed to drive the blades (not shown) of the steam turbine 160, producing power in the second electrical generator 162.

After driving the steam turbine 160, the steam is directed to the condenser cooling system 170 to be cooled and returned to the heat exchanger 152.

The power generation system 100 usually includes three gas turbines 140. Two gas turbines 140 are operated whilst the third gas turbine 140 acts as a standby unit for use during maintenance or breakdown of the other gas turbines. However, it should be appreciated that the power generation system 100 could also operate only using a single gas turbine 140.

Additionally, a VAM line 1 1 is provided to direct the VAM from the vent air methane supply unit 110 directly to the duct burner 151 of the heat recovery steam generator 150. If circumstances exist where the VAM cannot be combusted in the gas turbines 140, then the VAM may be combusted in the duct burner 151 and does not need to be vented to the atmosphere.

FIG 2 shows a flow diagram of the power generation system of FIG 1 , where a VAM filter 180 is included into the pipeline from the VAM supply unit 110. During operation of the power generation system 100, the VAM filter 180 acts to remove any coal particles from the VAM which may otherwise foul components of the power generation system 100. A similar filter may also be included into other pipelines of the power generation system 100.

FIG 3 shows a second embodiment of the power generation system 100, where the option of connecting the VAM supply unit 110, via the VAM line 111 , to the heat recovery steam generator 150 is not included. When more than one gas turbine 140 is included in the power generation system 100, one of the gas turbines 140 can be available as a redundancy measure should another of the gas turbines 140 be unusable.

The likelihood of needing to direct VAM to the heat recovery steam generator 150 is therefore low as it would only be necessary if all of the gas turbines were simultaneously unusable. Thus the cost of potentially having to vent a portion of VAM to the atmosphere, and thus incur higher carbon taxes, is covered by the savings resulting from not requiring the infrastructure linking the VAM supply unit 110 to the heat recovery steam generator 150.

FIG 4 shows a third embodiment of the power generation system 100 including a catalytic combustor 190. The catalytic combustor 190 has a catalytic intake 191 and a catalytic exhaust 192. The VAM supply unit 110 can direct VAM to the catalytic intake 191. Exhaust from the catalytic exhaust 192 is directed to the heat recovery steam generator 150. Use of the catalytic combustor 190 effectively lowers the auto ignition temperature of methane in the VAM stream, hence improving the overall efficiency of the combustion process.

During operation of the power generation system 100 shown in FIG 4, VAM is directed from the VAM supply unit 110 through the VAM filter 180 to the air intake 141 of two of the gas turbines 140. VAM from the VAM supply unit 110 may alternatively be supplied to the catalytic combustor 190 if the gas turbines 140 are off-line. Alternatively the VAM supply unit 110 directs VAM concurrently to the gas turbines 140 and the catalytic combustor 190. Concurrent use of the gas turbines 140 and the catalytic combustor 190 may particularly be utilized if the volume of VAM is greater than can be safely consumed by the gas turbines 140.

FIG 5 shows a fourth embodiment of the power generation system 100 where the VAM supply unit 110 directs VAM to the duct burner 151 of the heat recovery steam generator 150. The MDG supply unit 120 directs MDG to the duct burner 151 , and fuel gas is also supplied to the duct burner 151 by the fuel gas supply unit 130.

In operation, air only is directed to the air intake 141 of the gas turbines 140. In the combustion chamber 142, fuel gas from the fuel gas supply unit 130 and is combusted produce power in the first electrical generator 144 and to give a high pressure and high temperature exhaust gas which is subsequently directed to the heat recovery steam generator 150. The duct burner 151 operates to consume VAM, MDG, and fuel gas, to produce power in the second electrical generator 162.

Operation of the power generation system 100 where VAM is directed to the air intake 141 of the gas turbines 140 or the duct burner 151 of the heat recovery steam generator 150 allows the VAM to be consumed without requiring a significant amount of pre-treatment or a large capital cost. Similarly, the MDG does not need to be significantly pre-treated prior to being supplied to the duct burner 151 of the heat recovery steam generator 150.

By utilizing MDG and/or VAM in a combined cycle power generation system, methane which would otherwise be vented to the atmosphere is converted to carbon dioxide and generates power. This reduces carbon emissions and thus provides both an economic and an environmental benefit to both the operator of the coal mine and the surrounding community.

Throughout the specification the aim has been to describe the invention without limiting the invention to any one embodiment or specific collection of features. Persons skilled in the relevant art may realize variations from the specific embodiments that will nonetheless fall within the scope of the invention. For example, more than one heat recovery steam generator could be utilized to provide a back up for the use of the MDG.

It will be appreciated that various other changes and modifications may be made to the embodiment described without departing from the spirit and scope of the invention.