Integrated heat and power plant supplies copper facility at Gresik

In 1996, Mitsubishi Materials Corporation, which was planning to build a large copper smelter and refinery at Gresik in Indonesia, suggested that BOC bid to supply the plant with industrial gases. As discussions progressed it became apparent that the two companies could benefit from an extended scheme. This would involve supply of a wider range of services by BOC including oxygen, steam, electricity and boiler feedwater. It would also utilise steam from the refinery waste heat boilers (WHB).

The utilisation of this WHB steam, 42 barg and saturated, was an important part of the overall design. Availability of fresh water at the site was extremely restricted, so the condensate from this steam needed to be recycled. This meant that the steam could not be used for power augmentation in a gas turbine since this would lead to its loss into the atmosphere.

In fact, water restrictions at the site were severe. Use of seawater for cooling had to be limited to 900 m3/h and use of fresh water limited to 8 m3/h. This meant that all water usage had to be carefully controlled with maximum recycling.

Copper refining is operated as a continuous process with minimal breaks so the utility system was also required to provide:

about100 per cent availability of electric power;

about100 per cent availability of oxygen;

about100 per cent availability of steam.

Agreement was finally reached and BOC was awarded a project worth $100 million. Project development was by BOC with its Indonesian partner Garama. The industrial gas facility was built by BOC Process Plants, the power and steam facility was built by Black & Veatch and project management was provided by BOC.

Copper processing

Copper refining is carried out using an electrolytic process. This was the type of plant planned for Gresik.

Such a plant consists of three major facilities:

the smelter/refinery-complex where the copper concentrate is processed;

an oxygen plant producing high purity oxygen required by the chemical reactions in the smelting and converting furnaces;

a utilities plant to supply the smelter/refinery complex and oxygen plant with the steam, electrical power and condensate needed for their operation (see Figure 1).

The raw material for the process, copper concentrate from Indonesia, is received at the smelter/refinery complex where it is stored before processing. When required, the concentrate is transferred from storage, dried, mixed with pulverised coal, silica and limestone and injected pneumatically into the smelting furnace. High purity oxygen from the oxygen plant, mixed with air, is also introduced into the furnace where it reacts with the concentrate to produce matte and slag. The slag is discarded and processed for sale.

Matte from the smelting furnace flows to the converting furnace via the slag cleaning furnace where once again it is reacted with oxygen enriched air and limestone to produce blister copper and slag (again discarded, processed and recycled to the smelting furnace after drying).

Blister copper from the converting furnace with a purity of 98.5 per cent flows to the anode furnaces for final refining before being cast into anodes for electrolytic refining. The cathode copper resulting from the electrolytic process has a purity of more than 99.99 per cent.

Byproducts called slimes resulting from the electrolysis process contain small amounts of precious metals such as gold, silver, platinum, palladium, selenium and tellurium. The slimes are recovered and sent to an off-site facility for processing.

Flue gas treatment

Both the smelting furnace and the converting furnace produce flue gases which are ultimately discharged into the atmosphere. To meet environmental regulations, the gases must first be treated.

The gas from the smelting furnace is first cooled in a waste heat boiler before reaching the sulphur dioxide treatment facility consisting of an electrostatic precipitator and an acid plant. High temperature gases from the converting furnace, also high in sulphur dioxide (around 21.7 per cent) are cooled in a second waste heat boiler to the same temperature as the gas leaving the first waste heat boiler. Both flue gas streams are combined before flowing through the electrostatic precipitator and acid plant. Condensate from the power plant is used to cool the flue gases in the waste heat boilers.

The saturated steam produced in the two waste heat boilers is sent to the power plant where it is superheated in a separate gas fired superheater before inclusion in the power plant steam main where it is used either for motive power for the air separation plant or for power generation. The condensate resulting from these two processes is partially used for boiler feedwater for the smelting furnace waste heat boiler.

Water chemistry in the waste heat boilers is monitored and controlled by the smelter/refinery operating personnel using a combination of chemicals and boiler drum water blowdown. The steam produced in the two waste heat boilers is always less than the condensate supplied (a result of boiler blowdown and transient conditions), so the power plant is required to make up the difference.

Smelting and converting are continuous processes that are only stopped for scheduled shutdowns needed for inspection and repair. During shutdowns, the furnaces are maintained at temperature using oil burners so that full operation can be resumed as soon as possible after the inspection has been completed. Under these conditions, flue gases from the furnaces are reduced to a minimum and steam generation from the waste heat boiler is also reduced to a minimum.

Utility plant design

In order to find the optimum solution that would meet the energy requirements of the copper smelter/refinery gas as well as those of the air separation unit (ASU), a series of questions had to be answered:

What would be the optimum size of the ASU?

How would the smelter waste heat boiler saturated steam be used?

What was the optimum method of generating power and steam?

What arrangement of power generating equipment best satisfied the availability and reliability requirements?

What type of power plant would provide power at below grid costs?

How could the problem of restricted cooling water be solved?

After a preliminary study it became apparent that the size of the ASU could be tailored to match the power available from the fixed amount of saturated steam. However this required a method by which the steam could be superheated.

BOC determined that superheating the steam to 400°C would provide sufficient steam to drive the combined main air and the booster compressor required for a liquid pumped air separation plant. Hence this design was chosen instead of the more traditional oxygen compression cycle.

Power plant design

The type of arrangements that could be used to achieve a reasonable payback on an avoided cost basis – the price that the client would have to pay for electricity directly from the grid – are shown in Figure 2. This demonstrates that to produce power at prices below the Indonesian grid price of about 6.5 cents/kWh, a gas turbine combined cycle power plant offers the best option.

In selecting the system, availability and reliability were the key issues along with a balanced efficiency between the gas turbine and steam cycles. Consequently, it was decided early in the project that a combined cycle gas turbine based power plant would be employed, with the addition of supplementary firing on the heat recovery steam generators (HRSGs) to provide high steam making capability.

The prime reason for providing the additional steam generating capacity was to ensure that the main air/booster compressor required for the ASU and the steam turbine driven generators of the combined cycle plant would always have motive steam available even if the waste heat boilers were out of service. It was initially believed that the waste heat boilers would be out of service on average for about an hour each day. The additional steam capacity would prevent the need to shut down the ASU during this hour.

Gas turbine selection

All gas turbines, including both industrial and aeroderivative types, that were capable of producing about 40 MW electricity and 60 t/h of high-pressure steam were examined. The software-based study also looked at how many such units would be needed and the impact of the number on availability. Table 1 indicates the results of this review, which showed that availability decreases as the number of gas turbine trains decreases.

It was concluded, therefore, that to meet the availability and reliability objectives the three-train option was required. Figure 3 below shows the final arrangement.

The review also determined that the Solar Mars 100s provided the optimum power, steam and fuel balance. At ISO conditions three such units in a combined cycle configuration promised to provide about 42 MW gross electrical output.

Based on these decisions, the final arrangement comprised:

three Solar Mars gas turbine generators each site rated at 9070 kWe;

three HRSGs each with supplementary firing capability;

two Mitsubishi steam turbine generators each rated at 9000 kWe;

a backup fuel system to cover for the loss of natural gas supply;

two fuel gas compressor trains.

This arrangement allowed the copper smelter and refinery, as well as the ASU, to continue operating with sufficient power and steam if either one gas turbine, one HRSG or one steam turbine was out of service. The plant was designed such that in the event of a trip of one of these major components the remaining units would ramp up to supply the deficit power and steam balance without tripping the ASU or power plant. This necessitated the use of a steam dump to the various condensers in the system.

Power plant design

The electrical power and the process steam needed for the continuous operation of the smelter, refinery and oxygen plant, are produced by a combined cycle plant arranged in a 3 x 2 configuration (3 gas turbines, 3 heat recovery steam generators and 2 steam turbines). There is also a low pressure auxiliary steam generator and an on-line process steam superheater (see Figure 3).

  Natural gas is delivered to the plant from the main gas pipeline through a metering station installed by the gas supply company. The main gas pipeline pressure is boosted by a compressor station before being supplied to the three gas turbines.

The flue gas produced by the gas turbines is routed through three supplementary fired single (gas only) pressure HRSGs for steam generation and subsequent discharge to atmosphere through the individual HRSG exhaust stacks. A bypass stack and damper arrangement between the turbine exhaust and each HRSG inlet is provided to isolate each HRSG from the corresponding gas turbine during simple cycle operation.

The steam cycle is typical of a combined cycle of this size. The high pressure steam produced by the HRSGs and the process steam superheater is delivered to a common header which supplies the two steam turbine generators and the ASU compressor steam turbine.

Exhaust steam from the steam turbine generators condenses in two power plant condensers, one for each turbine, from where the condensate is pumped to the deaerator for degasification. Exhaust steam from the ASU compressor turbine drive is condensed in a dedicated ASU condenser from where it is pumped to the main condensate header before reaching the deaerator for degasification. Feedwater from the deaerator is delivered to the HRSGs and the waste heat boilers by a feedwater system. Cycle makeup water is supplied by gravity, directly to the condenser, from the plant storage tank.

During transient conditions such as sudden electrical load rejection, a certain amount of excess steam is expected to accumulate in the system. The excess steam from the main steam header is dumped to the three condensers (two for the power plant and one for the ASU).

No. 2 fuel oil is available as a back-up fuel for the gas turbines and the process steam superheater in case of natural gas supply interruption. The auxiliary steam generator operates on natural gas only.

The expected maximum electrical gross capability of the power plant (power measured at the generator terminals) is 42 MW (ISO) when all the electrical generators are in operation at 100 per cent load, with full oxygen production. The maximum process steam production from the HRSGs in unfired condition is 54 t/h, rising to 90 t/h with supplementary firing. The primary fuel is natural gas.

The plant is designed for “black start” (no other power source is available for start-up) using air-cooled generators driven by the Solar Mars gas turbines. The Solar Mars gas turbines are equipped with air-cooled lube oil coolers and the generator packages do not require cooling water.

Electric power is delivered to the copper plant at 11 kV, 3 phase, 50 Hz with a power factor greater than 0.85. The copper plant distributes the power as required by its own demand centres from the 11 kV interconnection point through the smelter/refinery complex utility centre or through the main switch gear room located on the northeast corner of the power plant site.

The electrical power required by the power plant balance-of-plant equipment and the by oxygen plant is taken from the main bus before the interconnection with the copper plant. It is stepped down to 400V by auxiliary transformers. The 400V and 3.3 kV auxiliary electric systems are for the exclusive use of the power plant and oxygen plant equipment.

In addition to the generation of electricity, the power plant produces high pressure steam for the air separation plant, low pressure process steam for use in the copper refinery and condensate (deaerated water) for the waste heat boilers installed in the smelter complex. Steam returned from the waste heat boilers is heated in the process steam superheater before passage to the main steam header where it mixes with the steam from the HRSGs.

The main steam header delivers steam to the turbine generators and the turbine drive for the main air and booster compressor on the ASU. The low-pressure steam generated for the copper refinery is produced by a packaged auxiliary steam generator using demineralised water from the steam cycle. A back-up let down steam station is provided from the main steam header to supply steam in the event that the auxiliary steam generator is out of service. The steam produced for this purpose is not be recovered.

The water problem

The lack of water supply at the site of the refinery proved a severe restriction. There was insufficient fresh water to provide cooling to both the air separation plant and the steam plant, but in order to meet project economics a desalination plant could not be used. The only viable alternative was to use seawater and an indirect cooling system. Once through cooling could not be used due to environmental restrictions so a seawater-cooling tower was chosen as the basis of the design.

The main air compressor intercoolers, the condensers of the power plant and main air compressor steam turbine use direct seawater cooling. Seawater is also used as the cooling medium in a plate frame exchanger to cool the treated water used by the air separation compressor aftercooler, direct cooler and vap cooler as well as critical components on the gas turbine power plants.

Low pressure steam requirements

The plant is designed to provide 24 t/h of 10 barg steam at all times in order to secure 100 per cent availability to the copper refinery of up to 12 t/h. This steam is provided by one packaged boiler and one steam letdown station. In the event that the packaged boiler is out of service, the steam letdown station takes a feed from the saturated steam line returning from the refinery waste heat boilers.

The steam header is under pressure control. Additionally, if the letdown station valve is opened the header pressure reduces and duct firing will be initiated, as necessary, to meet any additional steam requirements.

Current status and future projects

The BOC power plant was started up in October 1998. It operated initially in simple cycle mode before switching to combined cycle and cogeneration mode in December 1998. The air separation plant was started up in November 1998.

The project was BOC’s biggest at the time it won the order. It was the forerunner of the Canterell nitrogen facility for Pemex’s enhanced oil recovery project offshore in the Gulf of Mexico,which BOC and their joint venture partners, Westcoast Energy, Marubeni, ICA Fluor Daniel and Linde won one year later. This facility, at Campeche, near Carmen, on the Gulf of Mexico, which includes a 34 million Nm3/day, 120 bara nitrogen plant and a 520 MW gas turbine cogeneration plant, is currently under construction, at a cost of $1000 million. At the time of writing the first of the four modules at BOC Canterell was under commissioning.
Tables

Results of availability and reliability analysis