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The global gas turbine service market could reach $41.6 billion (U.S.) annually by 2025, according to a new report by Grand View Research. The global orders for industrial gas turbines totaled 581 in 2016, 12 more than ordered two years earlier, according to Diesel & Gas Turbine Worldwide. The growing market should push for expanded services for inspection, maintenance and repair of facilities. Other key findings from the report include an anticipated 8.5 percent annual growth rate through 2025. The global gas turbine service market was valued at $23.9 billion as of last year. The gas-fired turbine industry is highly consolidated and consists of five major players, the report noted. Those are GE Power, Siemens AG, Mitsubishi Hitachi Power Systems (MHPS), Kawasaki Heavy Industries and MAN Energy Solutions. GE Power, MHPS Americas, Siemens and MAN are scheduled as exhibitors for the POWER-GEN International conference scheduled December 4-6 in Orlando.

https://www.power-eng.com/2018/08/03/report-gas-turbine-service-market-blows-past-41b-by-2025/#gref
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Liputan6.com, Jakarta – Pasokan listrik Indonesia bertambah 85 Mega Watt (MW) dari Pembangkit Listrik Tenaga Panas Bumi (PLTP) Muara Laboh Tahap 1. Pembangkit ini dioperasikan oleh PT Supreme Energy Muara Laboh (SEML), perusahaan patungan PT Supreme Energy, ENGIE dan Sumitomo Corp.

Founder & Chairman PT Supreme Energy, Supramu Santosa, mengatakan PLTP Tahap 1 Muara Laboh yang berlokasidi Kabupaten Solok Selatan, Provinsi Sumatera Barat, baru beroperasi komersial.

Selanjutnya, listrik akan dipasok ke jaringan listrik Sumatera milik PT PLN (Persero) yang dapat didistribusikan ke kurang lebih 340 ribu rumah tangga.

“COD PLTP Muara Laboh tahap 1 dan rencana pengembangan tahap 2 merupakan bukti komitmen yang sangat kuat dari Supreme Energy dan mitra internasional-nya terhadap pengembangan energi panas bumi di Indonesia untuk mendukung Pemerintah Indonesia dalam mencapai sasaran bauran energi tahun 2025,” kata Supramu, di Jakarta, Senin (16/12/2019).
PT Supreme Energy memulai studi pendahuluan dalam proyek pengembangan listrik melalui PLTP Muara Laboh pada tahun 2008. Dilanjutkan penandatanganan Perjanjian Jual Beli Listrik (PJBL) atau Power Purchase Agreement (PPA), pada 2012, kemudian kegiatan eksplorasi. Total investasi untuk pengembangan tahap 1 ini mencapai USD 580 juta.

Saat ini, PT Supreme Energy juga dalam tahap pembicaraan dengan PLN dan Kementerian Energi dan Sumber Daya Mineral (ESDM) untuk pengembangan tahap 2 dengan kapasitas 65 MW. Pengembangan ini membutuhkan investasi USD 400 juta dan akan segera dimulai setelah negoisasi PPA selesai.

“Kami sangat menghargai atas dukungan yang kuat dan terus menerus dari Pemerintah, PLN dan masyarakat Solok Selatan khususnya selama kegiatan eksplorasi dan pengembangan,” ujarnya

Saat ini, PT Supreme Energy juga sedang membangun Proyek PLTP Rantau Dedap berkapasitas 90 MW di Sumatera Selatan. Proyek pengembangan yang digarap oleh PT Supreme Energy Rantau Dedap (SERD) ini dijadwalkan selesai pada akhir tahun 2020. Untuk menyelesaikan proyek ini, SERD akan berinvestasi sekitar USD 700 juta.

Selain itu, melalui PT Supreme Energy Rajabasa (SERB), PT Supreme Energy juga sedang mempersiapkan program eksplorasi untuk Wilayah Kerja Panas Bumi Gunung Rajabasa yang berlokasi di Wilayah Kabupaten Lampung Selatan Provinsi Lampung.

Kegiatan eksplorasi akan dimulai segera setelah negoisasi perpanjangan PPA dengan PLN selesai. SEML dan SERB adalah perusahaan patungan yang terdiri dari PT Supreme Energy, ENGIE dari Perancis dan Sumitomo Corp dari Jepang, sedangkan SERD adalah perusahaan patungan dari PT Supreme Energy, ENGIE, Marubeni Corp dari Jepang dan Tohoku Electric Power of Japan.

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Liputan6.com, Jakarta – Anggota Komisi VII DPR-RI dari Fraksi Partai Keadilan (FPKS) Mulyanto meminta PLN fokus untuk merealisasikan target pemerataan listrik (rasio elektrifikasi) di 2020.

Mulyanto mengatakan, ada dua tantangan besar yang dihadapi PLN dalam mewujudkan target elektrifikasi 100 persen pada 2020. Pertama, kondisi geografis daerah kepulauan dan remote area dan kedua, daya beli masyarakat.

Seperti di Maluku, Papua dan beberapa wilayah terpencil lain, PLN terkendala kondisi geografis untuk mengembangkan jaringan distribusi listrik. Kalaupun kendala pengembangan jaringan ini sudah teratasi, maka tantangan berikutnya adalah soal daya beli.

“Kami masih menemukan banyak masyarakat yang tidak mampu membayar biaya pemasangan sambungan listrik di rumahnya. Biaya sebesar Rp 600 ribu hingga Rp 1 juta masih dianggap memberatkan,” kata Mulyanto, di Jakarta, Jumat (20/12/2019).

Mulyanto pun mendorong pemerintah terus mencari sumber energi listrik yang murah dan relatif mudah didistribusikan ke wilayah-wilayah terpencil untuk mengejar target pemerataan kelistrikan 100 persen. Pemerintah pun diharapkan mampu menciptakan inovasi dan pengadaan listrik bersumber energi baru terbarukan (EBT).

“Sumber baterai dan EBT paling ideal, meski pada daerah yang tertentu, listrik berbasis diesel tak terhindarkan,” ujar Mulyanto.

Mulyanto juga mengusulkan agar Pemerintah mempertimbangkan pengadaan subsidi pemasangan listrik baru bagi masyarakat di wilayah tertinggal, terdepan dan terluar (3T).

“Bila langkah-langkah tersebut tidak secara sigap diatasi maka target elektrifikasi 100 persen di tahun 2020 hanya PHP,” tegas Mulyanto.

Dia pun menyinggung ketidakakuratan data rasio elektrifikasi yang di lapangan dengan yang dimiliki PLN. “Misalnya di Maluku, PLN mengklaim sudah berhasil melakukan elektrifikasi 90 persen tapi berdasarkan pengamatan langsung di lapangan masih ditemukan wilayah-wilayah tertentu yang belum teraliri listrik,” ujar Mulyanto.

Untuk itu Mulyanto meminta Pemerintah membuat definisi ulang yang lebih jelas dan tegas tentang elektrifikasi. Supaya terjadi kesepahaman antara DPR dan PLN tentang indikator keberhasilan elektrifikasi.

“Ini soal akurasi data. Antara PLN dan DPR harus punya acuan dan pengertian yang sama tentang elektrifikasi. Apakah listrik yang diproduksi secara swadaya oleh masyarakat dapat diklaim sebagai pencapaian elektrifikasi oleh PLN. Apakah berbasis desa atau rumah tangga. Bagi PLN mungkin termasuk tapi bagi DPR kan bisa jadi tidak termasuk,” tandasnya.

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Liputan6.com, Jakarta – PT PLN (Persero) berkomitmen menyediakan pasokan listrik untuk industri pengolahan dan pemurnian (smelter). Perusahaan tersebut pun siap dikenakan penalti jika listrik tidak tersedia.

Pelaksana tugas Direktur Utama PLN Sripeni Inten Cahyani mengatakan, ‎PLN telah mengantisipasi meningkatnya permintaan listrik, dengan membangun infrastruktur kelistrikan berupa pembangkit dan jaringan transmisi. Seiring dengan bertambahnya industri khususnya smelter.

“PLN siap melistriki industri smelter dan melakukan best effort untuk menyediakan listrik secara kompetitif,” kata Inten, dalam rapat koordinasi kesiapan PLN melistriki industri smelter, di Kantor Direktorat Jenderal Ketenaga Listrikan, Jakarta, Jumat (20/12/2019).
Menurut Inten, PLN pun siap dipenalti jika tidak mampu memenuhi permintaan listrik dari industri smelter. Namun, dia pun meminta pelaku industri sama-sama berkomitmen menyerap pasokan listrik yang disediakan PLN.

“‎Kami juga mohon komitmen sama-sama, kapan pun PLN akan best effort siapkan listrik dan kami siap dipenalti. Dengan catatan bapak siap kami siap,” tuturnya.

Saat ini total pasokan listrik‎ nasional yang tersedia mencapai 62.372 Mega Watt (MW), transmisi 56.899 Kilo Meter sirkit (KMs), jaringan distribusi 58.081 Mega Volt Amper (MVA).

Untuk mengantisipasi kenaikan kebutuhan listrik, PLN akan menambah pembangunan infrastruktur kelistrikan di wilayah Sulawesi yang menjadi konsentrasi pembangunan smelter, yaitu pembangkit dengan kapasitas total 5.422 MW.

“COD (beroperasi) sampai akhir tahun 2019 1000 MW lagi, mudah-mudahan sisanya 23.000 MW yang masih konstruksi bisa selesai 2020 – 2021,” tandasnya.

https://www.liputan6.com/bisnis/read/4138594/pln-siap-dihukum-jika-tak-mampu-penuhi-listrik-industri-smelter

 

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Mitsubishi Hitachi Power Systems, Ltd. (MHPS) has begun trial operation of gas turbine combined cycle (GTCC) for “Jawa-2 Project” underway by PT. PLN (Persero), Indonesia’s state-owned electricity provider, at the Tanjung Priok Power Plant on Java Island. The project, to construct GTCC natural-gas-fired power generation facilities, is now in its final stage toward completion and commercial start-up this May.
Jawa-2 is a comprehensive project to construct 880 megawatt (MW) GTCC power generating facilities in Tanjung Priok, a port city approximately 10 km northeast of central Jakarta. The full-turnkey order for the power plant’s EPC (engineering, procurement and construction) was received by MHPS in partnership with Mitsubishi Corporation and local construction and engineering firm Wasa Mitra Engineering for the GTCC power generation equipment. MHPS is responsible for providing two M701F gas turbines, two exhaust heat recovery boilers, one steam turbine and auxiliary equipment. Both simple cycle systems were accomplished ahead of schedule – Unit 1 in June 2018 and Unit 2 one month after – and have already gone into commercial operation. Currently, the works are proceeding on schedule toward commercial start-up of the GTCC system. To date, since its start the Jawa-2 project has experienced no accidents or disasters, in recognition of which PLN has given MHPS formal commendation of its safety record.
In addition to Jawa-2, MHPS and Mitsubishi Corporation have jointly received a full-turnkey order for EPC on a 500 MW natural-gas-fired GTCC power plant under construction by PLN at Muara Karang near Jakarta. Installation of the power generation equipment, including an M701F gas turbine, is proceeding smoothly – here again, without accidents or disasters – toward start-up of the GTCC system in December 2019.
Indonesia is currently undertaking a large-scale thermal power expansion program centered on the West Java region around Jakarta, under a government initiative to add 35,000 MW generation capacities in order to meet surging demand for power along with the country’s economic growth. Construction progress at related projects has been widely impeded, however, by impact from natural disasters. But on those projects where MHPS is participating, construction has been moving forward extremely smoothly with respect to safety, quality and construction schedule. As a result, representatives of PLN have expressed their full confidence in MHPS’ work, commenting that the close relationship between PLN and MHPS, already spanning 50 years, is their assurance of full peace of mind.

Source : https://www.turbomachinerymag.com/mhps-begins-gtcc-trial-operation-in-final-stage-of-jawa-2-project-in-indonesia/
 
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Siemens SGT-A65 gas turbine

Gas turbine (GT) OEMs have been racing for decades to deliver bigger machines, higher efficiency and larger combined cycle plants. Siemens scored a world record with a 4,800 MW combined cycle plant in Egypt (Turbomachinery International, Nov/Dec 2018).
GE and Mitsubishi Hitachi Power Systems (MHPS) both claim to have the biggest GT. GE’s 9HA.02 comes in at 557 MW, while MHPS’s M701JAC provides 563 MW. GE, Siemens and MHPS all claim the world record on combined cycle efficiency.
Yet market forces may be dictating a completely different direction — that bigger is not necessarily better. Small and mid-sized turbines are now receiving more attention as the power generation and oil & gas markets diversify. This trend is being driven by distributed generation, renewables, microgrids, combined heat & power (CHP), lower emissions and hydrogen-based generation.
“The industry has been guilty of building ever-larger machines and then trying to find a market for them,” said Mark Axford, President of Axford Consulting. “A better approach would be to find what the market needs and building machines to fit those requirements.”

Solar Turbines
Solar is a leader in small machines, producing GTs ranging from 1.2 MW to 22 MW. Some use a diffusion flame combustor and others a DLE system. The DLE system keeps flame temperature much lower (1,600°C versus 2,300°C) to keep NOx emissions down. Solar machines can operate with LPG, coke oven gas, landfill or digester gas.
“LPGs have become more common due to shale gas offering up more propane at low cost,” said Luke Cowell, Group Manager, Combustion Strategy, Solar Turbines. “This fuel can be burned in a Solar GT with lower NOx emissions and lower particulates compared to diesel.”
The composition of LPG around the globe can shift from 100% butane to 100% propane, said Cowell. With more butane, it is better to run it in liquid phase. Propane, though, has a lower dew point so is better in the gas phase.
At a Caribbean rum distillery in St. Croix, a Solar Centaur 50 is used with LPG for CHP. LPG is much lower priced there than diesel. As it has only 2.5% butane, the Centaur 50 is run in the gas phase with the fuel temperature maintained at around 200°F.
China’s Liheng Steel, meanwhile, is using four Solar Titan 130s operating on coke oven gas with an HRSG and steam turbine.
“LPG is an excellent turbine fuel, but you need to determine whether it is optimum to use it in its gas or liquid phase,” said Cowell.

MHPS
For the mid-sized turbine market, MHPS provides the H-100. At 119.9 MW (50 Hz) shaft power, it is being used to replace less efficient machines without requiring a modification to the bottoming cycle. It is also used in mechanical drive applications.
H-100 specifications: 38.9% efficiency, exhaust flow of 302 kg/s, and an exhaust temperature of 573°C. Its DLE burner is a scaled-down version of the combustor from the MHPS M501G and M501J. It provides 9 ppm NOx and CO.
“The MHPS H-100 GT has been successfully validated with lean gas (up to 40% N2), rich gas with a high calorie value, such as LNG, and on-line switching between lean and rich fuel at a Wobbe Index rate of change up to 0.5% per second,” said MHPS CEO Paul Browning. “It is the world’s largest two-shaft turbine.”
The two-shaft MHPS H-100 is finding a niche in LNG liquefaction as an alternative to the single-shaft GE 7EA, said Browning. The LP rotor has a continuous speed range capability of 70% to 105%. The two-shaft design allows full settle-out pressure starts. MHPS is partnering with MCO Compressor to deliver a complete solution to the oil & gas field.
Another smaller machine gaining traction is PW Power Systems’ FT8, sold in modified form as a “Frack Pack.” It offers 30 MW of mobile power to electrify the well pad. U.S. Well Services in Texas, for example, bought six of these units. Instead of diesel, it uses natural gas from the local site. They move them from well pad to well pad based on demand.
Zorya-Mashproekt from Ukraine offers a series of GTs ranging from 2.5 MW to 114 MW. Some 1,200 have been manufactured to date along with about 2,000 centrifugal compressors.
Despite embargoes from Russia, Forecast International predicts Zorya’s sales to improve over the next decade with 25-to-30 sales per year on average. The UGT-15000, for example, is a 16.9 MW, three-shaft GT with an axial nine-stage low-pressure compressor and 10-stage high pressure compressor.
Vericor has two such gas turbines in its repertoire. The 3.3 MW ASE40 and 3.7 MW ASE50B GTs are compact units for stationary, continuous duty applications. These units boast 60,000 hours between scheduled shop visits.
They can run on natural gas or liquid fuel. In addition, they can be changed over from one fuel source to another while running under full load.
Vericor Power Systems is owned by MTU Aero Engines and is the OEM of the TF series and ASE series GTs. Its aeroderivatives are used in marine, offshore, industrial and mobile power applications.
The TF40 (4,000 hp) and TF50 (5,000 hp) are used in the marine sector. Its VPS3 (TF40F) and VPS4 (TF50F) are favored in oil & gas. Its VPS3 (ASE40) and VPS4 (ASE50) are used mainly in the industrial sector.

Microturbines
The microturbine market has been stable for some time. But that may be about to change. Capstone Turbine, FlexEnergy and Ansaldo Energia are market leaders. Blandon (formerly Bladon Jets), a UK company, Micro Turbine Technology (MTT) from the Netherlands, and Aurelia Turbines from Finland have also entered the market.
Ansaldo’s AE-T100 is a single-shaft, high-speed microturbine that delivers 100 kW. Some 600 have been made since its release in the nineties.
Primary uses include CHP with biogas feedstock, and areas where small amounts of power, less noise, vibration and emissions are needed. The GT comes with a recuperator, electrical system, exhaust gas heat exchanger, control system and a single-stage centrifugal compressor.
Bladon’s MTG12, a 12 kW machine, is designed to power cellular towers for telecom companies. Towers not connected to a grid are in demand, a market historically dominated by reciprocating diesel engines. The MTG 12 is said to have advantages over diesels, such as fuel flexibility and lower maintenance, and to require 90% fewer site visits.
MTT’s EnerTwin can provide 3.2 kW of output for heat or electricity. Potential applications range from larger homes to restaurants and schools.
Aurelia Turbines has introduced a 400-kW model. This microturbine can be used for process steam, chilling and direct current applications. Efficiency is above 40%.

Combined Heat & Power
Smaller gas turbines are in demand in areas where CHP is growing in popularity. The complexity inherent in the development of smaller onsite power and CHP assets is being addressed by regulated utilities supporting and developing projects at customer sites, said Kurt Koenig, Vice President Project Development at DCO Energy.
Instead of fighting CHP and regarding it as a potential competitor, some utilities are embracing it, said Koenig. They realize that they have the grid and technical expertise to develop these projects and partner with industrial customers for mutual benefit.
DCO Energy has identified several major customer groups as CHP collaboration targets: healthcare, government and educational institutions, military, industrial, manufacturing, data centers, gaming and corrections. Projects can either be self-funded, privately funded, publicly funded or can be a combination.
“Drivers for CHP include cost, environmental impact, and fewer service interruptions,” said Koenig.
Where public benefits can be identified, regulated utilities can be a catalyst for CHP and other distributed generation assets. Potential CHP sites may have a strong desire to build onsite power. But they lack the know-how, financing, and grid expertise to achieve it. By involving a willing utility, a mutually beneficial solution can sometimes be achieved.
For example, the local utility facilitated a CHP site at the Hudson Yards real estate project in New York by removing barriers to grid access. It included gas-fired boilers, centrifugal electric-drive chillers, a 7.2 MW GT with a waste heat recovery boiler, and gas-based reciprocating engines that provide, heating, cooling and power to commercial and residential space on Manhattan’s West Side.
In another example, Duke Energy worked with Clemson University on a 15 MW CHP plant on campus. Owned by Duke, the utility provides access to natural gas and the grid. The facility includes natural gas turbines and duct-fired HRSGs. It supplies electricity and steam to Clemson. Duke gains steam and electricity. The campus also gains its own microgrid, partially funded by Duke.
“In this case, the public good was served as the provision of steam drove down rates for electricity,” said Koenig.
A similar example was outlined by Ken Duvall, Managing Partner and CEO at Sterling Energy Group. He believes CHP is vastly underused with only 82 GW existing in the U.S. It is estimated that there is 200 GW of untapped CHP potential in the nation.
“Well applied, CHP is the most efficient method of generating power,” said Duvall. “It is based on established natural gas technology that has very low risk.”
He emphasized that a change of thinking is required. Instead of CHP only being viewed as a customer-owned resource, a variety of ownership and funding options are possible. Some utilities are happy to develop and own the entire facility, arranging attractive, long-term contracts for power supply.
The utility can sell the excess electricity to other customers. With steam as part of the equation, some industrial plants will take up much of the steam and some of the power. Many permutations are possible.
Duvall showcased a CHP project on Amelia Island in northeastern Florida. It serves Rayonier Advanced Materials a supplier of cellulose specialty products. Company expansion called for more steam for industrial processes.
Rayonier leased land to Eight Flags Energy (a subsidiary of Chesapeake Utilities) for the establishment of a CHP plant. Rayonier gains 20-year access to low-cost steam. It receives steam at 160 psi and 420°F. Eight Flags supplies electricity to Florida Public Utility (FPU, part of Chesapeake) to meet about half of Amelia Island’s electricity requirements.
The guts of the CHP system include a 20 MW Titan 250 GT from Solar Turbines and a Rentech HRSG. The facility considered running the GT in simple cycle mode, but that would have given it too low an efficiency to make the project economics work.
Adding an HRSG for combined cycle operation changed the equation. The HRSG recovers around 70,000 pounds of steam per hour and has the capability to increase that amount using Rentech duct burners to 125,000 pounds per hour of process steam.
De-mineralized water provided by Rayonier is channeled through a hot water economizer in the HRSG to increase the water temperature by 70°F. This hot water is sent back to Rayonier for use in production processes.
Eight Flags has a capacity factor of 95%. This 22 MW CHP plant has lowered electric costs by 10%, while lowering NOx by 80% and CO2 by 38%.
“Rayonier receives steam and power, which it needed for expand,” said Duvall. “We built it on an elevated coastal site to be above any storm surge.”
The plant paid nothing for the power and steam plant. As it did not need any additional power, the utility sells electricity to other customers. But the plant would not have been possible without the tight partnership between the local grid authority, the utility, and the industrial customer. Plans are ongoing to open a second CHP plant on the island, said Duvall.
 
FERNANDINA BEACH, FLA. 04/01/14-RAYONIER040114CH- at the Rayonier Performance Fibers Mill in Fernandina Beach, Fla. on April 1, 2014. COLIN HACKLEY PHOTO

Ford goes CHP
Ford Motor Co., with DTE Energy, is building a 34 MW CHP plant at its site in Dearborn, Michigan. The Central Energy Plant, inclusive of the CHP plant, at the Dearborn Campus entails a $300 million investment.
The plant will be owned by DTE Electric, the regulated arm of DTE Energy, and constructed and operated by DTE Energy Services, a non-regulated arm of DTE Energy.
Michael Larson, Director Business Development, DTE Energy Services, said that the plant encompasses several components: 16,000-ton chiller system using mechanical and heat pump chillers; 40,000-ton/hr thermal energy storage; 6,400-ton geothermal system; 156 MMBtu/hr hot water supply system; two 14.5 MW GTs from Solar Turbines; 5 MW steam turbine from Siemens; and 370,000 lb/hr of heat recovery steam generators from Rentech Boiler Systems.
“Over the next 10 years, the steam load will sink and the electric load at the campus will rise while both will continue to have seasonal variations,” said Larson.
That made sizing of the CHP plant more complicated than usual. Ford initially looked at a smaller CHP plant. But that would only provide power for its own need and might not satisfy fluctuating steam and electricity requirements.
In addition, project economics demanded a larger facility that generated enough electricity to sell to external customers. Ford will purchase power and steam from DTE Electric. Construction of the facility is scheduled to be completed by the end of 2019. ■

Sidebar: Customized lubrication
ExxonMobil advises those running small or mid-sized turbines to take care when selecting lubricants. The decision should be based on the application environment and a thorough oil analysis.
Smaller turbines typically use gearboxes that run at a higher speed. However, their efficiency is lower than larger frame machines, which generally do not have gearboxes. For smaller machines, the choice of lubricant is important.
Mike Galloway, Equipment Builder Engineer at ExxonMobil, said the oil type should be tailored to the load. For the 6F, he recommended the Mobil DTE832 or 932GT meeting GE’s required GEK 101941 specification.
“6F turbines run hot and need a thermally stable oil that is oxidation and varnish resistant,” said Galloway. “If poor quality oils are used, varnish can quickly build up, and that can eventually lead to a trip.”
COT-Puritech (a Circor company) also offers value-added service to turbine owners. Christopher Tomerlin, Director of Global Accounts at COT-Puritech, said his company can be called in to flush out the entire lubrication system.
An analysis is done to determine the chemical mix required. To remove varnish, a high-velocity flush is often needed, followed by a purge to get rid of any chemical residues.
“We sample the oil and conduct extensive tests,” said Tomerlin. “This helps determine which process is best for cleaning. For example, a varnish flush might consist of 24 to 48 hours of circulating the chemicals to remove the varnish. Once completed, the system is drained and then purged to extract all the chemistry. After that, the new oil can be introduced.

Sidebar: HYDROGEN TURBINES AND OTHER ALTERNATE FUELS
Hydrogen-fueled gas turbines continue to be an active area of research and development (Turbomachinery International Sept/Oct 2018). Hydrogen has the potential to be a greener and cleaner fuel source for GTs, said Elena McKenzie, Market Analyst at Ansaldo Energia’s PSM division. Faced with the rapid growth of renewables, declining revenue, rising O&M costs, and the demand for cleaner generation, all OEMs are looking at how to further reduce emissions.
One approach is to mix hydrogen with natural gas. As well as lowering emissions, McKenzie touted the use of excess renewable capacity used to generate hydrogen through hydrolysis and then feeding that hydrogen into the combustion process. To meet modern power generation needs, though, all-hydrogen GTs would have to be supported by vast fields of renewable assets and colossal storage facilities.
Ansaldo Energia is currently testing a turbine running on 70% hydrogen. Combining hydrogen with natural gas has several benefits. Some 25% hydrogen offers 9% fuel savings, and a 9% reduction in CO2. Far from being theoretical, a Frame 9E is running in the Netherlands with 25% hydrogen.
“As you add hydrogen, the speed of chemical reaction in the combustor changes,” said McKenzie. “Inert gases, such as nitrogen, tend to reduce the speed of reaction; the flame shifts farther downstream, and you have greater risk of flame outs.”
Hydrogen challenges
More tuning is needed, too, as the hydrogen content rises. PSM has devised an autotune solution to avoid combustor problems and optimize operations.
Most OEMs have an ongoing hydrogen initiative. “The challenge is to keep the flame stable, avoid flashback and at the same time keep emissions down,” said Asa Lyckstrom, Commercial Manager Product Positioning at Siemens Medium GT Fleet. As hydrogen ignites and burns ten times faster than natural gas, the flame forms closer to the injector and has a wider flammable region than a fuel/air mix. However, only a fraction of the ignition energy is needed to get H2 going compared to methane.
Siemens has designed a 3D-printed DLE burner to keep NOx levels down despite rapid burning. It can be used with hydrogen in the Siemens SGT-600, SGT-700, and SGT-800. Inside the 57 MW SGT-800, 30 of these burners operate within the annular combustor. Siemens is also testing a burner running 100% hydrogen. It is confident that it can run the SGT-800 with 50% hydrogen by volume while keeping NOx below 25 ppm.
The Siemens SGT-A65 (formerly the Industrial Trent) can burn 100% hydrogen using a Wet Low Emissions (WLE) burner that keeps NOx at 25 ppm. It is a three-shaft, axial-flow, aeroderivative GT that produces 60 MW to 71 MW depending on its configuration and is suitable for flexible peaking and combined cycle applications.
More than 115 SGT-A65 machines have been manufactured and installed around the world. Some units have also been installed in mechanical load drive duty for gas boosting in Qatar. In mechanical drive applications, its three-independent-shaft design is suited to the higher power, variable-speed demands of applications such as natural gas liquefaction, gas transportation and gas induction for oil recovery.
The SGT-A65 includes a two-stage low pressure (LP) compressor with variable inlet guide vanes (VIGVs). It has a high overall pressure ratio and high thermal efficiency. In addition, the LP compressor boosts the airflow so that the power level is attained at a firing temperature sufficiently low to meet severe NOx requirements. Yet it is sufficiently high to give good cycle efficiency.
The intermediate-pressure (IP) compressor has eight stages and three rows of variable stators. The high-pressure compressor has six stages, with no variable stators. Overall pressure ratio is 34.1:1 for the 50 Hz dry low emissions (DLE) configuration.
Further, the SGT-A65 incorporates a series of staged pre-mix, lean-burn combustion cans that allow the GT to achieve low NOx and CO simultaneously. Eight combustors are incorporated into a single module.
The SGT-A65 has a five-stage LP turbine, a single-stage IP turbine, and a single-stage HP turbine. Each of these turbines drives its own compressor. The SGT-A65 LP Stages 4 and 5 have a larger gas path area and a lower exit Mach number than the Trent aero version.
A Siemens or Allen-Bradley control system provides integrated operation of multiple control functions while offering remote monitoring. The control system is designed for easy site installation by using remote I/O technology to decrease the number of interconnect cables between the unit control panel and the equipment skids. All train control systems are accessed by a Human Machine Interface (HMI) in the main control room.
The composition of fuels used in gas turbines varies considerably

Alternate fuels
GTs can burn a great many fuels including biodiesel, lean methane, hydrogen, liquefied petroleum gas (LPG), propane, and more.
“Gas turbines are flexible by nature and we are seeing many requests for them to burn all kinds of fuel,” said Jeffrey Goldmeer, Director of GT Combustion and Fuel Solutions at GE.
Biodiesel, for example, is experiencing a resurgence in Asia. Indonesia has mandated a blend of palm oil for power generation known as B20 (20% palm oil mixed with diesel). These fuels can be used by GTs.
Gas constituents and contaminants can vary widely depending on the source, said Goldmeer. Biodiesel typically has lower SOx emissions than heavy fuel oil, but its sodium content can be changeable. Sources include soybean oil, animal and vegetable waste, and canola oil.
Another alternative fuel of interest is LPG. However, one challenge is the lack of a universal definition: the propane and butane content can change markedly depending on geography or the season or the source wells. The scale of domestic supply logistics may limit build out in some countries.
GE has been running turbines with medium BTU gas, lean methane and fuels high in N2, CO2 or H2S. In regions with limited access to LNG, such fuels may be all that is available. Goldmeer said GE has over 1 million running hours on its GTs on these fuels.
However, he questioned the viability of what is known as green hydrogen: it is produced through the electrolysis of water and powered by solar generation. In his view, it is unrealistic due to the sheer quantity of water needed for electrolysis. Despite that, he entertained the possibility that LNG could be replaced by hydrogen power by 2050.
“But full decarbonization could double the cost of electricity,” said Goldmeer.
GE’s advanced pre-mixer is available for high hydrogen applications. It can deal with up to 50% of H2 by volume. Existing GTs can be upgraded to accommodate this change in fuel. But the rest of the plant may also have to be upgraded: ventilation, enclosures, safety procedures, and more. Heat Recovery Steam Generators (HRSGs) may have to be adjusted to deal with the presence of far more moisture.
“The more hydrogen you add into the fuel mix, the higher the moisture content,” said Goldmeer. “This also impacts heat transfer in the hot gas path, and HRSG operation.”
GE is putting renewed vigor behind its 6F machine in the medium-sized turbine market. With combined cycle plants owning 68% of the market and growing, GE is focusing the 6F in that niche.
“Given broad market dynamics such as the increasing penetration of renewables, the greater flexibility of combined cycle plants, and its high efficiency, the 6F has the right footprint,” said Aileen Barton, 6F.03 Senior Product Manager for Medium-Sized GTs at GE.
The GE 6F.03 provides 68 MW to 87 MW and offers 57% efficiency in combined cycle mode. It has 32,000-hour combustion and hot gas path inspection intervals. All versions of the turbine can run on gases and liquids, and additional fuels are added with each technology advancement. This includes natural gas, LNG, lean methane, LPG, H2 blends, sour gas, light distillate, oil, naphtha, and light crude oils.
The 6F.03 AGP (Advanced Gas path) upgrade includes the DLN 2.6+ combustor, as well as improved materials, coatings and cooling. Better metal seals reduce leakage and tighter clearances are achieved with abradable coatings. GE is also promoting a way to upgrade a 6B or 6E machine to the 6F. This leads to a 3% efficiency gain and major fuel savings, said Barton.

Source : https://www.turbomachinerymag.com/smaller-gas-turbines-find-their-niche/

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Changes in ambient temperature have an impact on fullload power and heat rate of a gas turbine, but also on part-load performance and optimum power turbine speed. Manufacturers typically provide performance maps that describe these relationships for ISO conditions.
 
The excerpts are taken from a paper “Gas turbine performance” presented by Rainer Kurz of Solar Turbines and Klaus Brun of Southwest Research Institute at the 2015 Middle East Turbomachinery Symposium.
 
The performance curves are the result of the interaction between the various rotating components and the control system. This is particularly true for DLN engines. If the ambient temperature changes, the engine is subject to the following effects:
 
The air density changes. Increased ambient temperature lowers the density of the inlet air, thus reducing the mass flow through the turbine, and therefore reduces the power output (which is proportional to the mass flow) even further. At constant speed, where the volume flow remains approximately constant, the mass flow will increase with decreasing temperature and will decrease with increasing temperature.
 
The pressure ratio of the compressor at constant speed gets smaller with increasing temperature. This can be determined from a Mollier diagram, showing that the higher the inlet temperature is, the more work (or head)is required to achieve a certain pressure rise. The increased work has to be provided by the gas generator turbine, and is thus lost for the power turbine, as can be seen in the enthalpy-entropy diagram. At the same time NGgcorr (ie the machine Mach number) at constant speed is reduced at higher ambient temperature. As explained previously, the inlet Mach number of the engine compressor will increase for a given speed, if the ambient temperature is reduced. The gas generator Mach number will increase for reduced firing temperature at constant gas generator speed.
 
The Enthalpy-Entropy Diagram describes the Brayton cycle for a two-shaft gas turbine. Because the head produced by the compressor is proportional to the speed squared, it will not change if the speed remains the same. However, the pressure ratio produced, and thus the discharge pressure, will be lower than before. Looking at the combustion process, with a higher compressor discharge temperature and considering that the firing temperature is limited, we see that less heat input is possible, ie., less fuel will be consumed .The expansion process has less pressure ratio available or a larger part of the available expansion work is being used up in the gas generator turbine, leaving less work available for the power turbine.
 
On two-shaft engines, a reduction in gas generator speed occurs at high ambient temperatures. This is due to the fact that the equilibrium condition between the power requirement of the compressor (which increases at high ambient temperatures if the pressure ratio must be maintained) and the power production by the gas generator turbine (which is not directly influenced by the ambient temperature as long as compressor discharge pressure and firing temperature remain) will be satisfied at a lower speed. The lower speed often leads to a reduction of turbine efficiency: The inlet volumetric flow into the gas generator turbine is determined by the first stage turbine nozzle, and the Q3/NGG ratio (i.e., the operating point of the gas generator turbine) therefore moves away from the optimum.
 
Variable compressor guide vanes allow keeping the gas generator speed constant at higher ambient temperatures, thus avoiding efficiency penalties. In a single-shaft, constant speed gas turbine one would see a constant head (because the head stays roughly constant for a constant compressor speed), and thus a reduced pressure ratio. Because the flow capacity of the turbine section determines the pressure-flow-firing temperature relationship, equilibrium will be found at a lower flow, and a lower pressure ratio, thus a reduced power output.
 
The compressor discharge temperature at constant speed increases with increasing temperature. Thus, the amount of heat that can be added to the gas at a given maximum firing temperature is reduced.
 
The relevant Reynolds number changes: At full load, single-shaft engines will run a temperature topping at all ambient temperatures, while two-shaft engines will run either at temperature topping (at ambient temperatures higher than the match temperature) or at speed topping (at ambient temperatures lower than the match temperature). At speed topping, the engine will not reach its full firing temperature, while at temperature topping, the engine will not reach its maximum speed. The net effect of higher ambient temperatures is an increase in heat rate and a reduction in power. The impact of ambient temperature is usually less pronounced for the heat rate than for the power output, because changes in the ambient temperature impact less the component efficiencies than the overall cycle output.

Source : www.turbomachinerymag.com
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JAKARTA – PT Pertamina Internasional Eksploration & Production, the upstream subsidiary of PT Pertamina (Persero), which manages oil and gas assets overseas, successfully undertake the tender offer for Maurel & Prom stocks at the first phase.

The results of the tender offer  has been announced by Autorité des Marchés financiers (AMF) of France on January 25th, 2017 local time. Starting from February 1st, 2017, PIEP will control as many as 125.924.574 stocks and the voting rights of Maurel & Prom, which is equivalent to 64.46% of the stocks and 63.35% of the voting rights of Maurel & Prom.

In addition, PIEP also controls many as 6,845,626 ORNANE (Obligation remboursable en numéraire et en actions nouvelles et existantes / Obligations Remboursable for cash and shares) of 2019, equivalent to 46.70% of the outstanding ORNANE of 2019 . PIEP will also hold  3.848.620 ORNANE of 2021, which is equivalent to 36, 88% of the outstanding ORNANE of 2021.

Payments to the owners of ORNANE will be conducted on transaction completion and at once handing over the ORNANE to companies with a value of 17.28 euros per ORNANE of 2019 (i.e. the nominal value plus interest by 0.03 euros), and 11.05 euro per ORNANE of 2021 (i.e. nominal value plus interest by 0.03 euro).

In accordance with article 232-4 from AMF General Regulations, the tender offer will be automatically re-open for 10 working days period. The tender offer schedule will be published soon by AMF.

President Director of Pertamina Dwi Soetjipto says the success of the first phase of tender offer is a good momentum for Pertamina to be more aggressively expand abroad amid the improving global crude oil prices. According to him, after Pertamina become the controlling stockholder (minimum of 51% stockholding), it can further consolidate the Maurel and Prom’s production to PIEP’s production.

“It certainly will improve the performance of Pertamina’s upstream. In addition, ISC is currently also reviewing and preparing  the possibility to make oil production which not only increase Pertamina’s production value, but also strengthen the supply to Indonesia, “said Dwi.

Director of Upstream of Pertamina Syamsu Alam added that the prospect of Maurel and Prom oil and gas assets is very potential to be developed by Pertamina through PIEP, where at the end of 2015 the oil and gas reserves listed has reached 205 million barrels of oil equivalent. With assets spread across Europe, America, Africa and Asia, it can become prove the company’s capabilities in the upstream business on a global scale. “Pertamina is more optimistic to be able to develop its upstream business faster,” said Syamsu Alam.

Meanwhile, Vice President Corporate Communication of Pertamina Wianda Pusponegoro says, “With the success of the first phase of this tender offer, we hope and optimistic that the next stage of the tender offer will run properly and the results will be optimum for PIEP and Pertamina.”

Source From : pertamina.com
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