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Pertamina partners with Solena Fuels Kembangkan PLTSA Bantargebang, Pertamina Gandeng Solena Fuels – Jaring News

“JAKARTA,   – PT Pertamina (Persero) and PT Godang Tua
Jaya agreed to set Solena Fuels Corporation as a partner in the project
technology provider of Power Plant Waste (PLTSa) capacity of 120 MW in
the Integrated Waste Disposal (TPST) Bantargebang, Bekasi. thing This was
marked by the signing of a Joint Development Agreement (JDA) between
Pertamina Gas Director”

“the initial agreement between Pertamina and Godang Tua Jaya on October
8, 2012. President Director of PT Pertamina (Persero) Karen Agustiawan
convey, that the focus of this collaboration is to make detailed
feasibility study for the use of municipal solid waste into energy with
the latest technology in the form of Plasma gasification is believed to
be capable of generating 120 MW of electricity equivalent to the input
waste 2000 tons per day. “This will be one of the breakthrough
technologies that can solve the problems of garbage and also in response
to the energy crisis that happened recently, “said Karen. According to
Karen, waste into electricity by building biomass-based power plant waste
from Integrated Waste Disposal (TPST) Bantargebang”

Bioliq pilot plant: Successful operation of high-pressure entrained flow gasification

Download PDF : 2013-02-bioliq-successful-high-pressure-entrained-gasification

Gasification Technologies Council Issues Call for Presentations for Annual Conference

Download PDF : 10448672

Air Products to build air separation units for China coal gasification facility

At Lu’An’s Changzhi City facility, the coal-to-liquids project will produce mainly diesel fuel and derivatives. Air Products’ ASU trains will include design enhancements to minimize operating costs through energy efficiency. It is the second-largest ASU onsite order ever awarded to the company for a single project.


Air Products on Wednesday announced the signing of a long-term agreement with Shanxi Lu’An Mining Co. for Air Products to build, own and operate four air separation units producing oxygen, nitrogen, compressed instrument air and steam.

The units will supply Lu’An’s multiple process trains at its coal gasification facility to be built in Changzhi City, Shanxi Province, China.

It is the second-largest ASU onsite order ever awarded to the company for a single project, according to Air Products officials.

Air Products’ four ASUs will combine to supply over 10,000 tpd of oxygen, more than 6,000 tpd of nitrogen, and over 700 tpd of instrument air.

The first of the four ASUs is targeted for onstream in July 2015. The remaining three are to be operational at one month intervals with the final ASU scheduled for commercial operation in October 2015.

“It’s been our strategy to pursue large ASU projects in the high growth China coal gasification market,” said Steve Jones, Air Products’ China president.

“This is another key win and important project for Air Products as we continue to grow our relationship with the major coal groups in China,” he added.

China has significant coal reserves to produce syngas from the coal and then convert the syngas into fuel, chemicals, and fertilizers, according to company officials.

At Lu’An’s Changzhi City facility, the coal-to-liquids project will produce mainly diesel fuel and derivatives. Air Products’ ASU trains will include design enhancements to minimize operating costs through energy efficiency.

Technology advancements and other productivity improvements support Air Products’ overall sustainability goals of reducing energy consumption and emissions.

“At Lu’An, we strive to cooperate and grow with industry leaders like Air Products. We look forward to further cooperation between our companies,” said Mr. Jinping Li, chairman of Lu’An.

The Lu’An win is Air Products’ eighth major investment supporting the gasification segment and the second supporting the coal to liquid sub-segment in China.

Once all the projects under construction are completed, Air Products will have 18 ASUs supplying large tonnage quantities of industrial gases to Chinese gasification facilities.

Saudi Aramco starts prequalification for Jizan gasification plant – Mubasher

Saudi Aramco starts prequalification for Jizan gasification plant

11 February 2013 06:08 PM Updated : 11 Feb 2013 06:08 PM

Packages from Jizan refinery to be incorporated into Aramco’s planned power plant

State-owned oil company Saudi Aramco has started the prequalification process for the power plant to be built next to the $7bn Jizan refinery in the southwest of the kingdom, according to MEED.

The scheme will be larger than most conventional power projects, as it has also incorporated packages from the refinery. It will be using technology provided by an international oil company.

Aramco invited international engineering, procurement and construction (EPC) contractors in early February to submit prequalification documents. The deadline for submissions is 17 February.

“This could be the largest Aramco project of 2013,” says an oil and gas executive working in the kingdom. “Most contractors expect the budget to be at least $3bn, but some are saying it could rise to as much as $5bn.”

After the prequalification process has been completed, Aramco will then issue tenders for the packages to the successful EPC contractors. A lump-sum turnkey (LSTK) contract model is being used to execute the project.

The scheme will be split into five packages:

• Air separation unit/oxygen supply

• Combined-cycle power plant

• Gasification

• Offsites and utilities

• Sulphur recovery

The scheme will be an integrated gasification combined-cycle (IGCC) power plant, which will have a capacity of 2,400MW and use technology provided by the UK/Dutch Shell Group.

The US’ KBR is carrying out the front-end engineering and design (feed) as well as the project management consultancy (PMC) for the refinery and power plant.

MEED reported in September that the Jizan Refinery Project will only need about 500MW of power from the proposed IGCC, with the remainder being used to power potential large-scale industrial projects at Jizan Economic City.

The IGCC model is an unconventional method of building a power plant and works by mixing hydrocarbons with oxygen to produce synthesis gas (syngas), which is then used to fire turbines.

The sulphur recovery unit and the fuel gas de-sulphurisation package have already been taken from the Jizan refinery scope and added to the power plant.

MEED reported in March that Aramco was taking over the power plant project from the Saudi Electricity Company (SEC), which was previously in charge of its development.

Source: Mubasher

Vic gas power plant plans shelved

CLP = EnergyAustralia

Vic gas power plant plans shelved

EnergyAustralia has shelved plans to build a gas-fired power station in Victoria due to falling wholesale prices and energy demand.

EnergyAustralia said it had told the Victorian government it had deferred work on its request for planning permission to develop and operate an Open Cycle Gas Turbine power station in Yallourn, east of Melbourne.

The proposal allowed for the plant to be converted to a 1000MW Combined Cycle Gas Turbine plant.

EnergyAustralia’s group executive manager, energy markets, Mark Collette, said the falling wholesale prices combined with the recent further deterioration in energy demand had led to the decision.

He said the falling demand meant the plant was not likely to be required until much later in the decade.

‘We have therefore decided to put the development on hold until market conditions improve,’ he said.

‘We are seeing further deterioration in the energy market and wholesale prices, and we don’t expect conditions to improve in the foreseeable future.

Mr Collette said continuing with the permit stage was not financially sustainable.

The company would review the decision if there were significant improvements in the energy market, he said.

Mr Collette said the decision would not impact the operations of Yallourn Power Station.

In October, EnergyAustralia blamed the carbon price on its decision to close one of its four units at the Yallourn plant.

New targets set for power station emissions

Submitted by calum.gordon on Oct 19th 2012, 5:42pm

News›Hong Kong

Lai Ying-kit

Hong Kong power plants will have to cut their emissions of three key pollutants by up to 17 per cent, starting in 2017, the Environmental Protection Department said on Friday.

In the second air-quality initiative in two days, the new emissions caps were set at 10,399 tonnes for sulphur dioxide, 25,950 tonnes for nitrogen oxides and 750 tonnes for respirable suspended particles.

Those levels represent reductions of 17 per cent, six per cent and 10 per cent in the three pollutants, respectively, compared with caps that will come into place in 2015.

“The tightened emission allowances will help improve the air quality in Hong Kong and the Pearl River Delta region,” the department said.

Power generators accounted for between 16 and 50 per cent of the emissions of the three pollutants across the city, according to government figures.

Officials will table the proposal in the Legislative Council on Wednesday.

The announcement came one day after Environment Secretary Wong Kam-sing said the government may phase out old diesel-powered commercial vehicles.

The new emissions limits were announced as the city recorded very high levels of air pollution in three busy districts.

The pollution index at roadside stations in Central, Mong Kok and Causeway Bay reached 100 on Friday. People with heart or respiratory illnesses are warned to reduce physical exertion and outdoor activities when the reading reaches 100.


Air Pollutionhk_new_pollution.jpg

More on this:

Tough measures considered to get old diesel vehicles off Hong Kong’s roads [1]

Source URL (retrieved on Oct 20th 2012, 6:27am):


EPA publishes first-ever carbon dioxide emissions standard for new power plants with future implications for existing sources

On April 13, 2012, the U.S. Environmental Protection Agency (“EPA”) published its first-ever carbon dioxide emission standards for new fossil fuel-fired power plants (“Draft Rule”).[1] The Draft Rule essentially requires all new fossil fuel-fired power plants to meet the carbon dioxide (“CO2″) emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal plants can be constructed without carbon capture and sequestration (“CCS”) capabilities. Litigation is expected over the Draft Rule due to the novel nature of the Draft Rule in regulating CO2 and EPA’s departure in several instances in the Draft Rule from its usual method of setting new source performance standards (“NSPS”) on a source category by source category basis.

The Draft Rule applies only to new fossil fuel-fired power plants, but we note that the Draft Rule will trigger a requirement under the Clean Air Act for the EPA (in coordination with the states) to address CO2 emissions from existing sources. With approximately 600 existing coal plants in the U.S., this future action to regulate CO2 emissions from existing sources is arguably more significant than the Draft Rule itself.

Below we provide highlights of the Draft Rule. For a more in-depth analysis of the Draft Rule and its implications for your business, please contact Richard Saines, Marisa Martin or Daniel De Deo. Full contact details provided in the left-hand column.


The Draft Rule is the result of litigation that commenced in 2008 between the EPA and several environmental groups, states and the City of New York.[2] The plaintiffs in that litigation challenged a 2006 EPA rule setting NSPS for electricity generating units (“EGUs”) that did not address greenhouse gases (“GHGs”). To resolve the litigation, the EPA and plaintiffs entered into a settlement agreement in December 2010 that required the EPA to take certain actions relating to NSPS for electricity generating units.[3] The EPA agreed to issue a proposed rule under Section 111(b) of the Clean Air Act that includes performance standards for GHGs for new and modified electricity generating units. The EPA also agreed to issue a proposed rule under Section 111(d) of the Clean Air Act setting emission guidelines for GHGs from existing electricity generating units. After nearly a year of delay, the EPA issued the Draft Rule in order to comply with the first requirement in the settlement.[4]

CO2 Emissions Standard & Covered Electricity Generating Units

The Draft Rule establishes a NSPS equal to a single output-based CO2 emission limit of 1,000 lb CO2/MWh (“CO2 Standard”) that is applicable to new electricity generating units (referred to as “Covered EGUs”, defined below). The CO2 Standard is equivalent to the CO2[5] emissions from a natural gas combined cycle power plant. The EPA determined that the CO2 Standard constituted the “best system of emission reduction” (“BSER”) which has been “adequately demonstrated”, which is the definition of “standard of performance” under Section 111(a) of the Clean Air Act.

Notably, the EPA proposes a new TTTT category of “new sources”[6] subject to the CO2 Standard (deemed “Covered EGUs”) that includes both coal and natural gas power plants in one category. Generally, the EPA sets a NSPS based on the type of technology used and does not combine sources into one category with one NSPS. The new TTTT category combines boilers and integrated gasification combined cycle (“IGCC”) units (currently included in the Da category) and combined cycle units that generate electricity for sale and that meet certain size criteria (currently included in the KKKK category). The Draft Rule defines a “Covered EGU” as “any fossil fuel-fired combustion unit that supplies more than one-third of its potential annual electric output and more than 25 MW net-electrical output (MWe) to any utility power distribution system for sale” with some exceptions. Based on this definition, Covered EGUs include electric utility steam generating units (“boilers”); stationary combined cycle combustion turbines and their associated heat recovery steam generator (“HRSG”) and duct burners; and IGCC units, including their combustion turbines and associated HRSGs. Covered EGUs do not include stationary simple cycle combustion turbines (e.g., peakers) or EGUs located in non-continental areas. Also, solid waste incineration units subject to emission requirements under Section 129 of the Clean Air Act are not subject to the Draft Rule.

New coal-fired EGUs would need to capture approximately 50% of the CO2 at the exhaust stream at startup to meet the CO2 Standard. Alternatively, the EPA is proposing a 30-year averaging compliance option that would be available for coal- and pet coke-fired Covered EGUs that did not install carbon capture technology at startup. Under this option, coal- and pet coke-fired Covered EGUs, with EPA’s approval, could comply with a less stringent CO2 annual limit for the first ten years of operation and a more stringent CO2 limit for the last twenty years such that on a 30-year basis, the facility would meet the CO2 Standard. The initial ten-year limit would be 1,800 lb CO2/MWh, which is the best demonstrated performance of a coal-fired facility without CCS. The CO2 limit for the following twenty years would be 600 lb CO2/MWh and beyond the 30th year, the source would be required to meet the CO2 Standard (i.e., 1,000 lb CO2/MWh).

  • Trading of Emission Credits to Meet the CO2 Standard

After the federal cap-and-trade program proposal failed on the national level in 2010, there has been speculation whether the EPA could allow for the trading of emission credits under the existing Clean Air Act. Some commentators interpreted the NSPS provisions in Section 111 of the Clean Air Act to allow EPA to authorize the trading of emission credits to meet a NSPS for greenhouse gases. This is based on the language of Section 111 as well as the fact that the EPA has explicitly determined that a cap-and-trade program constituted BSER for other non-greenhouse gas pollutants (e.g., mercury).[7] Without significant discussion, the Draft Rule states that no averaging or emissions trading among Covered EGUs would be allowed for the CO2 Standard and that each Covered EGU would be required to meet the CO2 Standard. As discussed below, whether trading may be authorized for regulating CO2 from existing power plants (either directly or through state equivalency determinations) remains an open question.

Sources Excluded from the Draft Rule

  • Modified Sources & Reconstructed Sources

Covered EGUs undergoing modifications that increase CO2 emissions and reconstructed sources are not required to meet the CO2 Standard under the Draft Rule. The EPA notes that it had insufficient information to develop a proposal for reconstructed sources or sources that undergo “modifications” that would normally trigger NSPS and subject the source to the CO2 Standard. The EPA states that most modifications that would increase the maximum achievable hourly rate of CO2 emissions would likely be related to the installation of pollution control equipment, which is an action specifically exempted from the definition of modification. Sources undergoing modifications or reconstructed sources would be subject to any future CO2 standards that are issued for existing sources (see further discussion below).

  • Transitional Sources

Notably, the EPA creates a new category of power plants – deemed “transitional sources” – in the Draft Rule. A transitional source is defined as a power plant that has received approval for its Prevention of Significant Deterioration (“PSD”) construction permit by April 13, 2012 (i.e., the date of Federal Register publication of the Draft Rule) and has commenced construction by April 13, 2013. The EPA justifies its exclusion of transitional sources from the Draft Rule based on gaps in information regarding the extent such sources have sunk costs and material commitments such that the CO2 Standard would not be considered BSER.

Approximately 15 power plants are expected to be considered transitional sources and thus not subject to the Draft Rule. The Draft Rule specifically notes that although transitional sources are exempted from the CO2 Standard, they would be subject to the requirements the EPA will promulgate for existing sources under Section 111(d) of the Clean Air Act, which is discussed in more detail below. In addition, a transitional source’s PSD permit may also contain CO2 limits.

Application of CO2 Standard to Existing Sources

The EPA projects in the Draft Rule that most new power plants in the U.S. will be natural gas-fired and thus not required to install any add-on technology to comply with the Draft Rule. Any new coal plant built in the U.S. will be required to install CCS in order to comply with Draft Rule but new coal plants that are not considered “transitional sources” (and exempted from the Draft Rule) are expected to be few, according to the EPA. Because there are hundreds of coal fired-power plants already constructed and operating without CCS, a significant issue will be the extent to which the Draft Rule will affect existing power plant sources.

  • Emission Guidelines for Existing Sources

The EPA emphasizes that the Draft Rule, promulgated pursuant to Section 111(b) of the Clean Air Act, does not affect existing power plant sources. While technically accurate, Section 111(d) of the Clean Air Act requires the EPA, after promulgating NSPS under Section 111(b) for pollutants like CO2 that are not regulated under the National Ambient Air Quality Standards (“NAAQS”) or as a hazardous air pollutant, to issue standards of performance for “existing sources”.[8] Specifically, Section 111(d) states that the EPA “shall prescribe regulations which establish a procedure under which each State shall submit . . . a plan which establishes standards of performance for any existing source for any air pollutant . . . to which a standard of performance under this section would apply if such existing source were a new source.” Because the EPA set NSPS for CO2 for new sources in the Draft Rule, it is obligated under Section 111(d) to set performance standards for CO2 from existing sources.

Under Section 111(d), the EPA issues regulations known as “emission guidelines” that establish binding requirements that the states must address in the development of their state plans. For the CO2 Standard, existing sources would include transitional sources as defined by the Draft Rule, modified sources, reconstructed sources and any other sources that are not new sources. Because many pollutants are regulated under the NAAQS or are hazardous air pollutants, there is little precedent for EPA’s actions under Section 111(d). When it has acted, the EPA has generally issued a model rule that can then be adopted by the states. For instance, for mercury emissions the EPA determined that a national cap-and-trade program was BSER for existing sources and issued a model rule establishing the program for adoption by the States.[9]

States must adopt the emission guidelines for existing sources through a state rulemaking action with EPA review and comment similar to the State Implementation Plan (“SIP”) process. The states and EPA may set less stringent standards or longer compliance schedules for existing sources considering cost of control; useful life of the facilities; location or process design at a particular facility; physical impossibility of installing necessary control equipment; or other factors making such variances appropriate. If the state fails to submit a satisfactory plan, the EPA has the authority under Section 111(d)(2) to prescribe a plan and to enforce the provisions of such plan.

If the EPA fails to address CO2 emissions from existing sources as required by Section 111(d), it could face additional litigation under the Clean Air Act as well as an enforcement action in connection with the 2010 settlement agreement, which required the EPA to issue emission guidelines for existing fossil fuel-fired sources.

  • Equivalent State Programs

Due to the absence of comprehensive climate change policy on the federal level, many states have already implemented programs aimed at controlling greenhouse gas emissions from power plants (e.g., Renewable Portfolio Standards (“RPS”), cap-and-trade programs, state-based CO2 emission limits for power plants). Several states and policymakers have indicated such programs should be considered equivalent to any emission guidelines for existing sources issued by the EPA. For example, the State of California has stated that its greenhouse gas cap-and-trade program that covers power plants should be considered for the purposes of applying the CO2 Standard under the Draft Rule to existing sources. Other commentators have noted that state RPS programs could be similarly treated. Due to the lack of precedent in the area, whether state-based greenhouse gas trading programs (or other state rules that control CO2 emissions) will be considered equivalent to the Draft Rule remains an open question. The EPA could issue a model rule setting forth the necessary requirements of any state program seeking equivalency or could work individually with states to approve programs that it deems would result in equivalent emission reductions.

Next Steps

The EPA is requesting public comment on the Draft Rule, and all comments must be received on or before June 25, 2012. The EPA will hold two public hearings on the Draft Rule on May 24, 2012 in Chicago and Washington, D.C. While the Draft Rule may be changed during the comment period, any power plant constructed after April 13, 2012 is required to meet the CO2 Standard, so it is essentially in force at this time. Regarding the timing of the EPA’s emission guidelines for existing sources, any regulation of CO2 from existing sources will be controversial. It is widely expected that the EPA will not issue a rulemaking for existing sources in advance of the presidential elections in November 2012.

Japan’s Tepco facing uncertain future with surging fuel costs

Japan’s largest power utility Tokyo Electric Power Company, or Tepco, has fallen into sharp deficit for two consecutive years after suffering from nuclear accidents caused by the earthquake and tsunami on March 11, 2011.

Not only does Tepco have to pay a huge amount of compensation for damages caused by the accidents, but rising fuel costs have also harmed the company.

The company, which sells about one third of the electricity generated in the 120 million population country, carries out a vital role in supplying power to people.

But to ensure its survival — and eventual return to profitability — requires a huge injection of government funds and a drastic change in its structure of ownership. And in addition, in a move that is already meeting resistance, a significant increase in its electricity prices.

On May 14 this year, Tepco reported a net loss of Yen 781.6 billion ($9.8 billion) for fiscal 2011-12 (April-March), its second net loss in a row, though narrowing from the record Yen 1.247 trillion loss recorded the previous year. Revenues declined 0.4% year on year to Yen 5.349 trillion because of lower electricity sales. 

Read the full story…

Protesters halt power plant

A town in Guangdong, inspired by the Wukan uprising, wins a temporary stop to a project residents claim will pollute their region and threaten livelihoods

South China Morning Post – 21 Dec.. 2011

Thousands of residents clashed with police yesterday in the Guangdong coastal town of Haimen, near Shantou – inspired in part by unrest in the village of Wukan, 115 kilometres away.

Haimen residents, angered by government plans to build a coal-fired power plant on their doorstep and the pollution it would bring, surrounded the local government building and blocked the Shenzhen-Shantou expressway.

Residents of Wukan, near Lufeng, have been in open revolt against their local government for more than a week in a land dispute that first erupted in September.

Reports circulating online claimed that two people had died during clashes with police in Haimen and that several people had been taken away, but the deaths could not be independently confirmed. Online photos showed a stand-off between residents and riot police. Some postings said police fired tear gas and beat demonstrators who stormed government buildings.

Other photos showed dozens of armed riot police lined up along a road, and protesters surrounding a government building.

Residents blocked the Haimen section of the Shenzhen-Shantou expressway leading into the town after local government officials refused to see them. Traffic authorities in Guangzhou warned drivers to use other routes to Shantou as the expressway was cut in both directions because of a traffic accident.

Authorities in Haimen could not be contacted yesterday. But protesters dispersed in the afternoon after the government said it would temporarily suspend construction.

One Haimen resident, Zheng Yanping, said all the town’s high school students were prevented from leaving school until late yesterday because of concerns they might join the protesters. He said the teachers gave students noodles to eat but prevented them from leaving their classrooms.

“Haimen is a small place, with only 130,000 people, but we try our best to protect our environment,” he said. “We call on the central government to help us and allow overseas media to report what’s happened because local media won’t cover our story. The people of Wukan are a good model. People who fight together can put pressure on the authorities to negotiate.”

Tensions have been rising in Haimen since October, when Shantou officials attended a ground-breaking ceremony for a big Huadian Power International power plant.

The 5.7-billion yuan (HK$6.9 billion) project includes two 600MW generating units that authorities claim are highly efficient and environmentally friendly, as well as a port for unloading coal.

Haimen residents said the coal-fired power plant would ruin the township’s coastal waters and cost fishermen their livelihood

“We already have a power plant that is a major source of pollution,” Zheng said, referring to the Huaneng Haimen Power Plant, the first 6GW “ultra-supercritical” plant in Guangdong, which began operating in the district two years ago.

However, residents say that plant has been a nightmare.

“Since the plant has been running, we often notice bad smells in the air and even see white fog in the sky,” a Haimen resident said of the Huaneng power (SEHK: 0902announcementsnews) plant.