tata power 石炭火力発電所向け乾式脱硫脱硝システムの ...3.2 事業目的...

平成２９年度

質の高いエネルギーインフラの

海外展開に向けた事業実施可能性調査

（先進火力発電等案件形成調査）

インド・TATA Power石炭火力発電所向け

乾式脱硫脱硝システムの事業実現可能性

調査報告書

平成３０年３月

経済産業省資源エネルギー庁

(委託先)日揮株式会社

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PROJECT SPECIFICATION

TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant

目次第1部. 調査概要 1. 調査概要と報告内容 ........................................................................................................................... 4 2. 略語 .................................................................................................................................................... 4 3. はじめに ............................................................................................................................................. 5

3.1 事業背景 ......................................................................................................................................... 5 3.2 事業目的 ......................................................................................................................................... 5

4. 前提条件 ............................................................................................................................................. 5

第2部. 技術検討と事業性評価 5. 技術概要 ............................................................................................................................................. 6

5.1 石炭灰利用乾式脱硫プロセス ........................................................................................................ 6 5.2 脱硝プロセス .................................................................................................................................. 8

6. 商業装置に関する技術検討と事業性評価 ........................................................................................... 9 6.1 検討条件 ......................................................................................................................................... 9 6.2 Case1における基本設計検討結果 ............................................................................................... 11 6.2.1 プロセスフロー図 .................................................................................................................... 11 6.2.2 Case1 の主要機器 .................................................................................................................... 11 6.2.3 敷地面積 .................................................................................................................................. 12 6.2.4 排出物 ...................................................................................................................................... 12 6.3 Case2における基本設計検討結果 ............................................................................................... 13 6.4 Case3における基本設計検討結果 ............................................................................................... 13 6.4.1 プロセスフロー図 .................................................................................................................... 13 6.4.2 Case3 の主要機器 .................................................................................................................... 14 6.4.3 敷地面積 .................................................................................................................................. 16 6.4.4 排出物 ...................................................................................................................................... 16 6.4.5 集塵機の比較検討 .................................................................................................................... 17

6.4.5.1 比較 .................................................................................................................................. 17 6.4.5.2 集塵機の比較検討の要約 ................................................................................................. 19

6.5 商業装置の事業性評価 ................................................................................................................. 19 6.5.1 検討条件 .................................................................................................................................. 19 6.5.2 Case １の経済性検討結果 ....................................................................................................... 20 6.5.3 Case3 の経済性検討結果 ........................................................................................................ 22

6.5.3.1 集塵機および脱硫システムの経済性検討結果 ................................................................ 22 6.5.3.2 脱硝システムの経済性検討結果 ...................................................................................... 24 6.5.3.3 全体システムの経済性検討結果 ...................................................................................... 25

6.5.4 商業装置の経済性検討結果の要約 .......................................................................................... 28 7. 実証装置に関する技術検討と概算費用 ............................................................................................ 29

7.1 実証装置の基本設計 ..................................................................................................................... 29 7.1.1 ブロックフロー図 .................................................................................................................... 29 7.1.2 既設発電所との取り合い ......................................................................................................... 30 7.1.3 プロセス設計図書 .................................................................................................................... 30 7.1.4 主要機器 .................................................................................................................................. 31 7.1.5 必要敷地面積 ........................................................................................................................... 31

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7.1.6 用役消費量 ............................................................................................................................... 32 7.1.7 排出物 ...................................................................................................................................... 32 7.1.8 実証装置の詳細検討 ................................................................................................................ 33 7.2 実証試験計画 ................................................................................................................................ 34

8. 脱硝触媒の詳細情報 ......................................................................................................................... 35 8.1 インド石炭灰の性状分析 ............................................................................................................. 35 8.2 触媒被毒成分による影響 ............................................................................................................. 37 8.3 ダストの触媒摩耗への影響 .......................................................................................................... 37 8.4 触媒詳細情報 ................................................................................................................................ 41

第3部. 新環境規制に関する調査結果 9. 新環境規制の概要と対応状況の調査 ................................................................................................ 42

9.1 インドのエネルギー部門構成 ...................................................................................................... 42 9.2 新環境規制の概要 ........................................................................................................................ 44 9.3 新環境規制の対象となる発電所の現状と対応状況 ..................................................................... 46 9.3.1 石炭性状の調査 ....................................................................................................................... 46 9.3.2 排ガス性状の検証 .................................................................................................................... 48 9.3.3 新環境規制への対応状況 ......................................................................................................... 50

9.3.3.1 新環境規制への対応状況 ................................................................................................. 50 9.3.3.2 規制対象物質ごとの対応状況 .......................................................................................... 51

9.4 新環境基準を遵守するための課題 ............................................................................................... 52 9.4.1 SOx 排出基準に準拠する為の課題 ......................................................................................... 52 9.4.2 NOx 排出基準に準拠する為の課題 ......................................................................................... 54 9.4.3 規制遵守のための課題の重要度 .............................................................................................. 55 9.5 環境規制対応動向の最新状況と経緯 ........................................................................................... 57 9.5.1 最新状況のヒアリング結果 ..................................................................................................... 57 9.5.2 ヒアリング結果のまとめ ......................................................................................................... 58

第4部. 脱硫および脱硝技術に関する市場の調査結果 10. 脱硫・脱硝システムの市場調査 ....................................................................................................... 59

10.1 インドにおける脱硫・脱硝システムの市場調査結果 ................................................................. 59 10.1.1 カテゴリー(a)：新設発電所への装置導入 ........................................................................... 60 10.1.2 カテゴリー(b)および(c)：既設発電所の改造....................................................................... 64 10.2 脱硫および脱硝設備に対する要求 ............................................................................................... 66 10.2.1 脱硫設備に関する要求事項 ................................................................................................. 66 10.2.2 脱硝設備に関する要求事項 ................................................................................................. 67 10.3 インドにおける脱硫脱硝技術サプライヤーと実績 ..................................................................... 68 10.4 インドにおける乾式脱硫剤原料(消石灰、生石灰)の性状と市場 ................................................ 70

11. まとめ .............................................................................................................................................. 73 第5部. 添付資料添付リスト .............................................................................................................................................. 74

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1. 調査概要と報告内容本報告書は、平成29年度提案公募事業として経済産業省より委託された「インド・TATA Power石炭火力発電所向け乾式脱硫脱硝システムの事業実現可能性調査」の調査結果を纏めたものである。

インド国内の環境規制の動向や各発電所の環境規制への対応の調査結果と合わせて、技術面および

経済性の観点から事業実現の可能性を検討した結果を報告する。 2. 略語

本報告書では、以下の略語を使用する。 A/H : 空気予熱器 (Air Heater) CAGR : 複合年間成長率(Compound Annual Growth Rate) CAPEX : 資本的支出(Capital Expenditure) CEA : インド中央電力庁(Central Electricity Authority) CFD : 数値流体力学 (Computational Fluid Dynamics) GGH : 排ガス再加熱器 (Gas/Gas Heat Exchanger) ECO : 節炭器 (Economizer) EPC : 設計/調達/建設 (Engineering, Procurement, Construction) ESP : 電気集塵機 (Electrostatic Precipitator) FGD : 排ガス脱硫(Flue Gas Desulfurization) MC : マルチサイクロンセパレーター (Multicyclone Separator) MoEF&CC :インド環境・森林・気候変動省

(Ministry of Environment, Forest and Climate Change Government of India) NTPC : インド国営火力発電公社 (National Thermal Power Corporation) OPEX : 運用維持費 (Operating Expenditure) PDP : プロセス設計図書一式 (Process Design Package) SCR :選択的触媒還元(Selective Catalytic Reduction)、本書では触媒脱硝を示す。 SNCR :選択的無触媒還元(Selective Non-Catalytic Reduction)、本書では無触媒脱硝を示す。 SPM : 微小粒子状物質(Suspended Particulate Matter)

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3. はじめに 3.1 事業背景

インド国内では、近年の急速な経済発展に伴い環境規制が年々厳しくなりつつある。2015年には、

インドの環境・森林・気候変動省 (MoEF&CC) は1986年度に発行した環境規制のルールを火力発

電所向けに改訂し、一層の規制強化を図っている (9.2 章参照)。このような状況において、日揮株

式会社、日揮触媒化成株式会社、双日株式会社、および一般財団法人石炭エネルギーセンターの４

社は共同事業体を組織し、経済産業省の委託を受けてインド国内でTATA Power 社が運営する石炭

火力発電所をターゲットとして乾式脱硫脱硝システム導入の事業実現可能性について調査を実施し

た。

3.2 事業目的本事業化調査は、乾式脱硫脱硝システムをインドの石炭火力発電所に導入する場合の実現可能性を

確認することが主要な目的である。その目的に沿って、乾式脱硫脱硝システムと従来の湿式脱硫脱

硝システムの比較を行い、乾式脱硫脱硝システムの優位性の有無を技術的および経済的な観点から

評価する。 4. 前提条件

本事業化調査を開始するにあたり、石炭組成の分析結果、排ガス組成の分析結果と温度・圧力条件

などの前提条件をTATA Power 社と確認した。それらの前提条件の詳細は、本報告書の末巻に添付

する以下の図書を参照すること。 - 添付-1 Basic Engineering Design Information S-1222-001 - 添付-2 Design Basis for Maithon Power Plant S-1222-101 - 添付-3 Design Basis for Jojobera Power Plant S-1222-102

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5. 技術概要 5.1 石炭灰利用乾式脱硫プロセス

石炭灰利用乾式脱硫プロセス (以降、乾式脱硫プロセスと呼ぶ) は1980年代後半に北海道電力で開

発され、苫東厚真第一発電所に導入された。1991年の商業運転開始以降、今日に至るまで順調に操

業を続けている。また、近年、乾式脱硫プロセスは中国の複数のコークス炉ガスの燃焼排ガスの排

煙脱硫装置に適用され、今日に至るまで大きなトラブルも無く順調に操業を続けている。乾式脱硫プロセスは、脱硫塔に脱硫剤を充填・移動層を形成して排煙と接触させて、排煙中の二酸

化硫黄 (SO2) を脱硫剤に吸収して石膏 (CaSO4) に変化させることで二酸化硫黄を除去する。脱硫塔

は上下二段で構成され、塔頂部から塔底部に向かって脱硫剤を降下させることで移動層を形成する (図 5-1参照)。排煙は、脱硫塔下段から導入されて脱硫剤と十字流で接触し、二酸化硫黄の大部分

が吸収される。また同時に、上流の集塵機で除去しきれなかった少量の煤塵が脱硫剤に捕集され

る。その後、脱硫塔下段を通過した排煙は脱硫塔上段に導入され、未使用の脱硫剤と再び十字流で

接触し、排煙の環境規制値に照らして除去すべき残りの二酸化硫黄が全量脱硫剤に吸収される。

図 5-1脱硫塔概略図 - 排煙と脱硫剤の流れ

脱硫剤は消石灰を原料とし、これに石炭灰および石膏を混合した化合物であり、二酸化硫黄を吸収

して石膏を生成する過程は次の化学反応式で表される。 2Ca(OH)2 + 2SO2 + O2 → 2CaSO4 + 2H2O ‐(1)

脱硫剤は固体で、図 5-2に示すようにペレット状に加工されている。図 5-3には、脱硫剤の製造ス

キームを示す。

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図 5-2 脱硫剤の外観

図 5-3 脱硫剤製造スキーム

脱硫剤による二酸化硫黄の吸収は、脱硫剤製造の蒸気養生の工程において生成されるカルシウムシ

リケートが寄与している。使用済脱硫剤はその大部分が石膏となるので、使用済脱硫剤の一部は原

料の石膏の代わりとして再利用される。脱硫剤製造システムの概略図を図 5-4に示す。

図 5-4 脱硫剤製造システムの概略図

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 5.2 脱硝プロセス

脱硝プロセスとして、選択的接触還元触媒を使用する。還元剤として空気で希釈したアンモニアガ

スを触媒の上流に注入し、窒素酸化物（NOx）は以下に示す化学反応式 (2)、(3) および (4) 式によ

りアンモニアと反応して窒素と水に変換される。

4NO + 4NH3 + O2 → 4N2 + 6H2O ‐(2) NO + NO2 + 2NH3 → 2N2 + 3H2O ‐(3) NO2 + 8NH3 → 7N2 + 12H2O ‐(4)

選択的接触還元触媒には、一般的にプレート式とハニカム式が使用されている。ハニカム式は、そ

の構造からプレート式に比べて必要な体積量が小さく抑えられ、従ってプレート式に比べて触媒体

積あたりの効率が良い。但し、高濃度の煤塵を含む排煙に使用する場合には煤塵によって目詰まり

を起こす恐れがあるので、排煙の煤塵濃度が小さい場合に限り使用可能である。

図 5-5 ハニカム型触媒の外観

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6. 商業装置に関する技術検討と事業性評価 6.1 検討条件

既設あるいは新設の石炭火力発電所への乾式脱硫脱硝システムの導入に関して、技術検討および事

業性評価を行った。既設の石炭火力発電所はTATA power 社が保有するMaithon火力発電所1ユニ

ット (発電容量525 MW、排煙量 2,300,000 Nm3/h) を想定した。検討した全3ケースを以下に示

す。

Case1: 既設火力発電所設備の改造（低NOxバーナーへの交換と乾式脱硫プロセスの導入） Case2: 既設火力発電所設備の改造（乾式脱硫脱硝システムの導入） Case3: 新設火力発電所設備への導入（乾式脱硫脱硝システムの導入）

Maithon火力発電所の排煙設備の構成図を図 6-1に示す。ボイラー、節炭器(ECO)からでた排煙は

空気予熱器(A/H)、電気集塵機 (ESP) を通じて煙突から大気へ排出される。

図 6-1 Maithon火力発電所の排煙設備構成図

図 6-2にCase1の排煙処理設備の構成図とプロセス条件を示す。Case1は既設火力発電所に低NOxバーナーを導入することで窒素酸化物を、乾式脱硫プロセスの導入により二酸化硫黄を、それぞれ

表 9-1に示す規定値以下まで除去する。乾式脱硫プロセスは電気集塵機で煤塵を除去した後段に設

置する。

図 6-2 Case1の排煙処理設備の構成図とプロセス条件

図 6-3にCase2の排煙処理設備の構成図とプロセス条件を示す。Case2は既設火力発電所設備に乾

式脱硫脱硝システムを導入することで、窒素酸化物および二酸化硫黄をそれぞれ表 9-1に示す規定

値以下まで除去する。乾式脱硫脱硝システムは電気集塵機で煤塵を除去した後段に設置する。

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図 6-4にCase3の排煙処理設備の構成図とプロセス条件を示す。Case3は新設火力発電所設備に乾

式脱硫脱硝システムを導入することで、窒素酸化物および二酸化硫黄をそれぞれ表 9-1に示す規定

値以下まで除去する。また、Case3では排煙中に含まれる煤塵を除去するためにマルチサイクロン (MC) を導入することを検討する。乾式脱硫脱硝システムはCase1、Case2と同様に煤塵を除去した

後段に設置する。


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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 6.2 Case1における基本設計検討結果

6.2.1 プロセスフロー図 Case1のプロセスフロー図を添付-4に示す。Case1は既設の火力発電所に低NOxバーナーおよび乾

式脱硫プロセスを導入することを想定している。既設の電気集塵機から排出された排煙は脱硫塔 (C-101A~F) へ供給され、脱硫塔内を降下する脱

硫剤と接触することで、排煙中の二酸化硫黄が吸収される。二酸化硫黄を除去された排煙は煙突

より大気へ排出される。脱硫剤は脱硫剤サイロ (V-101A/B) に保管され、脱硫剤計量器 (Z-102A/B) により重量を測定し、必要量の脱硫剤が脱硫剤コンベア (Z-103A/B) により脱硫塔へ供給

される。脱硫塔の塔底部からはおよそ 7.45 ton/hr で使用済み脱硫剤が排出され、使用済み脱硫剤

コンベア (Z-104A/B) により使用済み脱硫剤サイロ (V-102A/B) へ運ばれる。なお、脱硫剤を製造

するために、プロセスフロー図で示す乾式脱硫プロセスの設備に加え、図 5-4に示す脱硫剤製造

設備の設置が別途必要である。

6.2.2 Case1の主要機器 Case1の主要機器は脱硫塔 (C-101A~F) である。脱硫塔1系列の基本設計図を図 6-5、図 6-6に示

す。Case1では、4列で構成される1基の塔を3基連結して1系列の脱硫塔とした。1系列あたりの寸

法は高さ32 m、幅19.6 m、奥行き14 mである。Case1ではこれを2系列設置する。

図 6-5 脱硫塔1系列の基本設計図（Case 1 上面図）

基

列

系列

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図 6-6 脱硫塔1系列の基本設計図（Case 1 側面図）

6.2.3 敷地面積 Case1において、乾式脱硫システムおよび脱硫剤製造装置を設置するのに必要な敷地面積はおよ

そ以下の通り見積もられる。

乾式脱硫システム 1,010 m2 脱硫剤製造装置 1,600 m2 （合計）必要敷地面積 2,610 m2

6.2.4 排出物

設置設備からの排出物は脱硫塔の塔底部から排出される7.45 ton/hの使用済み脱硫剤である。使用

済み脱硫剤の一部 (約30%) は脱硫剤原料である石膏として再利用できる。約70%の使用済み脱硫

剤は埋立て処理か、ヘドロ固化材、脱臭剤などの再利用が可能である。一方で、乾式脱硫システ

ムでは湿式脱硫システムで排出される排水がなく排水処理装置が不要となるため、これは乾式脱

硫システム特有の強みとなる。

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6.3 Case2における基本設計検討結果 Case2では既設火力発電所に乾式脱硫脱硝システムを導入することを想定している。しかし、

Case2では脱硝システムにおける排煙温度が145°Cと低いため、以下の理由により多量の触媒が必

要となる。低温度下での脱硝触媒の活性低下低温 (特に200°C以下) かつ硫黄酸化物（SO3）とアンモニアの共存下で析出する硫酸アンモニウ

ムによる触媒性能の低下各排煙温度に対する脱硝触媒の必要量を検討した結果を図 6-7に示す。排煙温度が低下すると脱硝

触媒の必要量が急激に増加する。これは脱硝触媒を導入する上で設計条件としては現実的ではない

ので、これ以上のCase2 の検討は行わないこととした。

図 6-7 排煙温度と脱硝触媒必要量の関係

6.4 Case3における基本設計検討結果 6.4.1 プロセスフロー図

Case3のプロセスフロー図を添付-5、添付-6に示す。Case3は新設の火力発電所への乾式脱硫脱硝

システムの導入を想定している。また、排煙中の高濃度煤塵を除去する集塵機を設置する。節炭器から排出された排煙は、慣性集塵機およびマルチサイクロン (S-101/102A~H) によって排

煙中に含まれる高濃度の煤塵の大半が除去される。集塵機の底部に堆積した煤塵は、空気輸送に

てダストホッパー (V-103) へ送られる。空気輸送による煤塵の大気放出を防ぐため、ダストホッ

パー上部にダストフィルター (S-103) を設置する。ダストホッパーに集積した煤塵は最終的にダ

ストコンベアー (Z-105) によって埋立地へ運ばれる。集塵機を出た排煙は脱硫塔 (C-101A~H) へ供給され、脱硫塔内の脱硫剤と接触することで二酸化

硫黄が吸収される。さらに、上流の集塵機で除去しきれなかった少量の煤塵は脱硫剤に捕集され

る。脱硫剤は脱硫剤サイロ (V-101A/B) に保管され、脱硫剤計量器 (Z-102A/B) により重量を測定

し、脱硫剤コンベア (Z-103A/B) によって脱硫塔へ供給される。脱硫塔の塔底部から排出されるお

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant よそ7.45 ton/hr の使用済み脱硫剤は、使用済み脱硫剤コンベア (Z-104A/B) によって使用済み脱

硫剤サイロ (V-102A/B) へ運ばれる。なお、脱硫剤を製造するために、プロセスフロー図で示し

た乾式脱硫システムの設備に加え、図 5-4に示すような脱硫剤製造装置の設置が別途必要であ

る。二酸化硫黄および煤塵を除去した排煙は、排煙/アンモニアミキサー (M-301) によって空気で希釈

したアンモニアガスを混合した後、脱硝反応器 (R-301) に送られる。空気で希釈したアンモニア

ガス、はアンモニア注入装置 (Z-301) によって供給される。煤塵、二酸化硫黄および窒素酸化物

を除去した排煙は空気予熱器で熱回収した後、煙突から大気へ放出される。

6.4.2 Case3の主要機器 Case3の主要機器は集塵機、脱硫塔 (C-101A~H) および脱硝反応器 (R-301) である。集塵機は慣

性集塵機 (S-101A~H) とマルチサイクロン (S-102A~H) が一体化した装置であり、合計8基で構成

される。1基あたりの基本設計図を図 6-8に示す。1基あたりの寸法は高さ15 m、幅11m、奥行き

8 mで、マルチサイクロン1基あたり81個のサイクロンが搭載される。

図 6-8 慣性集塵機・マルチサイクロンの基本設計図 (Case 3 側面図および上面図) 脱硫塔1系列の基本設計図を図 6-9、図 6-10に示す。Case3では、4列の脱硫塔で構成される1基が

4基連結して1系列を構成する。1系列あたりの寸法は高さ32 m、幅26 m、奥行き14 mである。

Case3ではこれを2系列設置する。

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図 6-9 脱硫塔１系列の基本設計図 (Case 3 上面図)

図 6-10 脱硫塔１系列の基本設計図 (Case 3 側面図)

脱硝反応器 (R-301) の基本設計図を図 6-11に示す。脱硝反応器は3層 (内1層は予備層) の触媒層で

構成され、寸法は高さ20.5 m、幅15.3 m、奥行き12.3 mである。

基

列系列

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図 6-11 脱硝反応器の基本設計図 (Case 3 側面図および上面図)

6.4.3 敷地面積

Case3において、集塵機、乾式脱硫システム、脱硫剤製造装置および脱硝システムを設置するの

に必要な敷地面積はおよそ以下の通り見積もられる。

集塵機 2,320 m2 乾式脱硫プロセス 1,340 m2 脱硝プロセス 640 m2 脱硫剤製造装置 1,600 m2 （合計）必要敷地面積 5,900 m2

6.4.4 排出物

設置設備からの排出物は使用済み脱硫剤および使用済み脱硝触媒である。脱硫塔底部からはおよそ7.45 ton/hの使用済み脱硫剤が排出され、その一部 (約30%) は脱硫剤原

料である石膏として再利用できる。約70%の使用済み脱硫剤は埋立て処理か、ヘドロ固化材、脱

臭剤などの再利用が可能である。Case1と同様に、乾式脱硫システムでは湿式脱硫システムで排

出される排水がなく排水処理設備が不要となるため、これは乾式脱硫システム特有の強みとな

る。脱硝触媒の設計寿命は、脱硝システムの上流に集塵機および乾式脱硫システムが配置されること

によって煤塵による閉塞や磨耗の可能性が少ないことから、5年で設計した。使用済み脱硝触媒は

インド法令に従って廃棄処理する。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 6.4.5 集塵機の比較検討

6.4.5.1 比較 6.1章のCase 3について、大型のマルチサイクロンセパレーターを商業機に導入するための実現可能

性を検証するために、従来使用されている電気集塵機との比較を行った。比較にあたっては、国内

および海外の複数のベンダーに見積りを依頼し、一部のベンダーから得られた見積り情報を元に比

較検討を行った。各ベンダーの集塵機の仕様、およびその過程で確認された懸念事項を表 6-1に纏め

る。各項目の比較において仕様が劣る方、および懸念事項を青色で示す。

表 6-1 マルチサイクロンセパレーターと電気集塵機の比較

項目マルチサイクロンセパレーター電気集塵機ベンダー A社ベンダーB/C/D社ベンダーB社ベンダーC社ベンダーD社

基数 10

キャンセル

6 8 3 納期 [月] 54 30 12 12 必要面積 [m2] 2,320 3,760 4,620 2,821 CAPEX [-] (注1) 1.15 1.00 0.66 2.21 集塵効率 [%] (注2) 82.0 99.0 99.0 99.0 圧力損失 [mmAq] 72 25 30 25

懸念

偏流大型化に伴い、1基内部で偏流

が起こる可能性がある。無し

負荷変動

低負荷運転により集塵効率が低

下する。無し各基に排煙を均等分配するため

に、各基入口の排煙を流量制御

する必要がある。

その他

大型のマルチサイクロンセパレ

ーターを製作した実績が殆ど無

く、見積りおよび製作に対応で

きるベンダーが殆どいない。

無し

注1: CAPEX はベンダーB社の電気集塵機のCAPEXに対する比率を示す。注2: 集塵効率は各ベンダーの保証値を示す。表 6-1に示す通りマルチサイクロンは必要面積が少ないという点で電気集塵機に対して優位性が

認められる。しかし、集塵効率はベンダー各社の保証値をベースにした比較においては電気集塵

機に遠く及ばない。また大型化に伴い複数の懸念事項が確認されたので、以下に詳細を述べる。偏流: マルチサイクロンセパレーター1基について、内部を流れる排煙の流速分布をCFDで解析した。

その結果を図 6-12に示す。解析の結果、入口の衝突板のすぐ後方では比較的遅く、一方で衝突板

から離れた後方では比較的速い流速分布となることが確認された。この不均一な流速分布は衝突

板の設計を工夫することである程度緩和することは可能と考えられる。しかし、マルチサイクロ

ンセパレーターを大型化する場合には、全ての運転ケースにおいて偏流が起こらないように内部

の構造を詳細に検討し、CFD解析による検証工程が必要となる。

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図 6-12 マルチサイクロンセパレーター内部の排煙の流速分布

付加変動: 低負荷運転において、排煙の流量が減少するのに伴い流速が下がるので、マルチサイクロンセパ

レーターの集塵効率が低下する。集塵効率を維持する方法として、負荷に応じてマルチサイクロ

ンセパレーターの運転基数を変える台数制御運転が必要になると考えられる。また、稼働してい

るマルチセパレーター各基に均等に排煙を分配するために、非対称なダクトのアレンジメントを

避けると共に、少なくとも各基の入口に流量計とダクトサイズに見合った大型の流量制御装置(ダンパーまたはガイドベーン) が必要になると考えられる(図 6-13参照)。これは、電気集塵機の簡素

な構成に比べて技術およびコスト的に不利となる。

図 6-13マルチサイクロンセパレーターのダクトアレンジメント

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant その他の懸念事項:

国内および海外ベンダー数社に見積りを依頼したが、各社ともに大型のマルチサイクロンを設計

施工した実績がほとんど無く、正式に見積りを得られたのは一社のみであった。従って、大型の

マルチサイクロンは市場性が低い、調達の観点でコスト的にも不利となり得る。

6.4.5.2 集塵機の比較検討の要約マルチサイクロンセパレーターは電気集塵機に比べて集塵効率が低いが、それに加えて、大型化

した場合には偏流対策、負荷変動対策、市場性の低さなど様々な懸念があることが分かった。 6.5 商業装置の事業性評価 6.5.1 検討条件

乾式脱硫システムの事業実現性を評価するために、6.1章で述べた乾式脱硫システム Case1 およ

び Case3 について、湿式脱硫システムに対するコスト比較を行った。コスト比較は、運転期間40年を想定してCAPEX およびOPEX の総額を積算する方法で行った。CAPEX およびOPEX は日

本国内の物価をベースに算出した。設備利用率は85%、負荷率は100%を想定した。乾式脱硫プロセス脱硫剤の原料としては、現在稼働している商用機では消石灰 (Ca(OH)2) が使用されている。一

方、消石灰より安価な生石灰 (CaO) を使用した方が、乾式脱硫プロセスのコスト競争力が上が

る。生石灰を使用する方法は未だ工業化されておらずベンチスケールの実証試験の域を出ない

が、有望な選択肢のひとつとして検討条件に加えることとした。本検討においては、石灰製造業

者への問合せをもとに、以下の価格を使用した。消石灰: 20円/kg (カルシウム単価 37 円/kg-Ca に相当) 生石灰: 18円/kg (カルシウム単価 25 円/kg-Ca に相当) ところで、脱硫剤製造装置に関して、その規模が大きい方がスケールメリットによって脱硫剤製

造装置の単位重量あたりのCAPEX は低く抑えられる。これは、近隣の発電所で大規模な脱硫剤

製造装置を共有することで実現可能と考えられ、今回の検討では Maithon 石炭火力発電所とその

周辺のJojoberaおよびIEL石炭火力発電所で脱硫剤製造設備を共有した場合も検討条件に加える

こととした。この場合、脱硫剤製造装置のCAPEX は、各発電所の定格出力の比で配分ることと

した ( Maithon : Jojobera & IEL = 1050 MW : 668 MW) 。湿式脱硫プロセスインド内陸部で最も適用可能性の高く、また乾式脱硫プロセスと競合する代表的な湿式脱硫プロ

セスとして石灰石膏法を想定し、これをケースW-1 とした。なお、他の代表的な湿式脱硫プロセ

スとして水マグ法が考えられるが、これをケースW-2 とした。ただし、水マグ法は小規模向けで

あり、且つ副生成物の硫酸マグネシウム(MgSO4) の河川への放流は許容されないので、あくまで

参考として扱った。乾式脱硫システム Case1およびCase3に対する湿式脱硫システムの設備構成

とプロセス条件を図 6-14および図 6-15に示す。

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図 6-14 Case1における湿式脱硫システムの設備構成とプロセス条件

図 6-15 Case3における湿式脱硫システムの設備構成とプロセス条件

6.5.2 Case１の経済性検討結果 6.5.1章に記載の検討条件をもとに、合計6ケースについて検討を行った。各ケースの詳細条件、

CAPEX および OPEX を表 6-2 に示す。各ケースのCAPEX および OPEX は、ケースW-1をベン

チマークとして、ケースW-1のCAPEXに対する比率で表示した。各CAPEX および OPEX の内

訳を図 6-16 および図 6-17 に示す。また、プラント操業20年間のCAPEX および OPEX の積算

結果を図 6-18に示す。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 表 6-2 経済性比較検討結果

ケース脱硫システム

CAPEX OPEX/年乾式

または湿式脱硫プロセス脱硫剤の原材料

脱硫剤製造装置 (注記1)

D-1 乾式石炭灰利用法消石灰専属 1.14 0.087 D-1a 乾式石炭灰利用法消石灰共有 0.81 0.082 D-2 乾式石炭灰利用法生石灰専属 1.14 0.066 D-2a 乾式石炭灰利用法生石灰共有 0.81 0.062 W-1 湿式石灰石膏法炭酸カルシウム - (該当せず) 1.00 0.076 W-2 湿式水マグ法水酸化マグネシウム - (該当せず) 0.61 0.079

注記1: “共有”とは脱硫剤製造装置を近隣の石炭火力発電所 (Maithon, Jojobera & IE) で共有すること

を示している。一方、”専属”とは、脱硫剤製造装置をMaithon 石炭火力発電所のみに導入することを

示している。

図 6-16 CAPEXの内訳

図 6-17 OPEXの内訳

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図 6-18 積算費用

以上の検討結果から、以下の所見が得られた：ケースD-1 およびD-2のCAPEX 1.14 は、ケースW-1のCAPEX 1.00 より高い。しかし、図

6-16 に示す通り脱硫剤製造装置がCAPEX に占める割合が大きく、近隣の発電所で脱硫剤製

造装置を共有することによるCAPEXの低減が期待される。脱硫剤製造装置を共有した場合

のケースD-1a およびD-2aではCAPEXが 0.81 まで下がり、ケースW-1の1.00 を下回ること

ができる。乾式脱硫システムのOPEX は、図 6-17に示す通りその大半が脱硫剤費用で占められている。

従って、脱硫剤の製造において消石灰より安価な生石灰を原料に使用することでOPEXの低

減が期待され、ケースD-1のOPEX 0.087 はケースD-2のOPEX 0.066 まで下がり、ケース

W-1の0.076 を下回ることができる。更に、脱硫剤製造設備を近隣の発電所で共有すること

によって、OPEXはケースD-2aの0.062まで下げることができる。以上の所見から、ケースW-1に対してCAPEX およびOPEX ともに下回りコスト競争力があるケ

ースとして、ケースD-2aの採用が推奨される。また、ケースW-1よりCAPEXは高いものの、積

算費用が運転開始後14年以上でケースW-1を下回るケースD-2の採用も考えられる。

6.5.3 Case3 の経済性検討結果 6.5.1章に記載の検討条件をもとに、脱硫システム(集塵機を含む)単体、脱硝システム単体、およ

び脱硫・脱硝システムを統合した全体システムについて各々経済性検討を行った。

6.5.3.1 集塵機および脱硫システムの経済性検討結果当初、先のケース１と同様の6ケースについて経済性検討の実施が計画された。これに、集塵機の

選択肢 (マルチサイクロンセパレーターまたは電気集塵機) を掛け合わせると検討ケースは倍にな

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant る。しかし、6.4.5章で検討した通りマルチサイクロンの大型化は難しいので、集塵機は基本的に

電気集塵機を想定し、合計6ケースの検討を行った。各ケースの詳細条件、CAPEX および OPEX を表 6-3 に示す。各ケースのCAPEX および OPEX は、ケースW-1EをベンチマークとしてケースW-1Eの全体システム(集塵機 + 脱硫システム + 脱硝システム)のCAPEXに対する比率で示す。プラント操業20年間のCAPEX および OPEX の積算

結果を図 6-19 に示す。

表 6-3 脱硫システム単体の経済性検討結果

ケース集塵機脱硫システム

CAPEX OPEX/年乾式または湿式脱硫プロセス脱硫剤の原

材料脱硫剤製造装置 (注記1)

D-1E ESP 乾式石炭灰利用法消石灰専用 1.15 0.064 D-1Ea ESP 乾式石炭灰利用法消石灰共有 0.92 0.062 D-2E ESP 乾式石炭灰利用法生石灰専用 1.15 0.050 D-2Ea ESP 乾式石炭灰利用法生石灰共有 0.92 0.048 W-1E ESP 湿式石灰石膏法炭酸カルシウム - (該当せず) 0.91 0.055 W-2E ESP 湿式水マグ法水酸化マグネシウム - (該当せず) 0.65 0.057



示している。

図 6-19 積算コスト(ケース3 脱硫システム単体)

以上の検討結果から、以下の所見が得られた： Case3はCase1より排煙の温度が高いので、Case1より脱硫塔の本数が多くなり（排ガスの体

積流量が大きくなるため）、それに起因してCAPEX はどの乾式脱硫システムのケースにお

いても湿式脱硫システムのケースW-1Eを上回る。しかし、脱硫剤製造装置を近隣の発電所で

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 共有することで、ケースD-1EおよびケースD-2EのCAPEX 1.15 はそれぞれケースD-1Eaお

よびケースD-2EaのCAPEX 0.92 まで下がり、ケースW-1Eの1.00 とほぼ同等まで低減され

る。乾式脱硫システムの脱硫剤の製造において消石灰より安価な生石灰を原料に使用すること

で、ケースD-1EのOPEX 0.064 はケースD-2EのOPEX 0.050 まで下がり、ケースW-1Eの

OPEX 0.055を下回ることができる。更に、脱硫剤の製造装置を近隣の発電所で共有するこ

とで、OPEXはケースD-2Eaの0.048まで低減される。

6.5.3.2 脱硝システムの経済性検討結果 6.5.3.1章で脱硫システム単体について検討を行った6ケースについて、脱硝システム単体での経済

性検討を行った。乾式脱硫システムについては、脱硝システムが集塵機の下流に配置され排煙中

の煤塵が除去されているので、煤塵による脱硝触媒の目詰まりの懸念は無く、従ってハニカム式

触媒を適用して触媒寿命は5年を想定した。一方、湿式脱硫プロセスでは、脱硝システムは集塵機

の上流に配置され煤塵による触媒の目詰まりが懸念されるため、プレート式触媒を適用し、摩耗

による劣化が想定されるので触媒寿命は2年とした。各ケースの詳細条件、CAPEX および OPEX を表 6-4に示す。各ケースのCAPEX および OPEX は、ケースW-1Eをベンチマークとして、プラント操業20年間のCAPEX および OPEX の積算結

果を図 6-20 に示す。

表 6-4 脱硝システム単体の経済性検討結果

ケース脱硝システム

CAPEX OPEX/年触媒

D-1E ハニカム式 0.09 0.074 D-1Ea ハニカム式 0.09 0.074 D-2E ハニカム式 0.09 0.074 D-2Ea ハニカム式 0.09 0.074 W-1E プレート式 0.09 0.100 W-2E プレート式 0.09 0.100

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図 6-20 積算コスト (Case3 脱硝システム単体)

以上の検討結果から、以下の所見が得られた：ハニカム式触媒はプレート式に比べて必要な触媒量が少なく、全体費用(必要な触媒量 x 触媒

単価)の点でプレート式触媒に対してコスト競争力が高いので、乾式脱硫システムの全てのケ

ース(D-1E, D-1Ea, D-2E, D-2Ea)において、OPEXは0.074 となり湿式脱硫システムのケース

(W-1E, W-2E)の 0.100 を大きく下回る。

6.5.3.3 全体システムの経済性検討結果 6.5.3.1章および6.5.3.2章で検討を行った6ケースについて、脱硫システム(集塵機を含む)および脱

硝システムを合わせた全体システムの経済性検討を行った。各ケースの詳細条件、CAPEX およ

び OPEX を表 6-5に示す。CAPEXおよびOPEXの内訳を図 6-21および図 6-22に示す。各ケース

のCAPEX および OPEX は、ケースW-1Eをベンチマークとして、ケースW-1EのCAPEXに対す

る比率で示した。プラント操業20年間のCAPEX および OPEX の積算結果を図 6-23 に示す（プ

ラント操業10年目までの具体的な積算結果の数値を表 6-6 に示す）。

表 6-5 全体システムの経済性検討結果

ケース集塵機脱硫システム脱硝システム

CAPEX OPEX/年乾式または

湿式脱硫プロセス脱硫剤の原材料

脱硫剤製造装置 (注記1) 触媒

D-1E ESP 乾式石炭灰利用法消石灰専用ハニカム式 1.23 0.137 D-1Ea ESP 乾式石炭灰利用法消石灰共有ハニカム式 1.01 0.134 D-2E ESP 乾式石炭灰利用法生石灰専用ハニカム式 1.23 0.124 D-2Ea ESP 乾式石炭灰利用法生石灰共有ハニカム式 1.01 0.120 W-1E ESP 湿式石灰石膏法炭酸カルシウム -(該当せず) プレート式 1.00 0.155 W-2E ESP 湿式水マグ法水酸化マグネシウム -(該当せず) プレート式 0.73 0.157



示している。

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図 6-21 CAPEXの内訳

図 6-22 OPEXの内訳

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図 6-23 積算コスト (ケース3 脱硫・脱硝システム全体)

表 6-6 積算コストの数値データ(Case3脱硫・脱硝システム全体)

ケース運転年数 [年]

備考 0 1 2 3 4 5 6 7 8 9 10

D-1E 1.23 1.37 1.51 1.64 1.78 1.92 2.06 2.20 2.33 2.47 2.61 D-1Ea 1.01 1.14 1.28 1.41 1.55 1.68 1.82 1.95 2.08 2.22 2.35 D-2E 1.23 1.36 1.48 1.60 1.73 1.85 1.97 2.10 2.22 2.35 2.47 D-2Ea 1.01 1.13 1.25 1.37 1.49 1.61 1.73 1.85 1.97 2.09 2.21 W-1E 1.00 1.16 1.31 1.47 1.62 1.78 1.93 2.09 2.24 2.40 2.55 ベンチマーク W-2E 0.73 0.89 1.05 1.20 1.36 1.52 1.67 1.83 1.99 2.14 2.30

脱硫・脱硝システムを合わせた全体について経済性検討を行った結果、どの乾式脱硫システムの

ケースにおいても湿式脱硫システムのケースW-1EのCAPEXより高くなる。しかし、Case1で得

られた所見と同様に脱硫剤製造装置がCAPEX に占める割合が大きく(図 6-21参照)、脱硫剤製造

装置を近隣の発電所で共有することはCase1と同様に乾式脱硫システムのCAPEXを下げる有効な

手段となる。一方、脱硝システムの比較においてプレート式に対するハニカム式触媒の優位性により、乾式脱

硫プロセスのOPEXはどのケースにおいても湿式脱硫システムのOPEXを下回る。更に、脱硫剤

費用がOPEX に占める割合はCase3においても比較的多い(図 6-22参照)。従って、脱硫剤の原料

を消石灰より安価な生石灰に変えることはCase3においても乾式脱硫システムのOPEXをより一

層下げて湿式脱硫システムに対するコスト競争力を向上させるために有効な手段となる。これらの、乾式脱硫システムのコスト競争力を向上させる手段を順次適用することで、乾式脱硫

システムのケースD-1EaおよびD-2Eaの積算コストは湿式脱硫システムのケースW-1Eの全体コス

トを運転開始後1年で下回ることができる。以上の所見から、運転開始後の早期に積算コストがケースW-1を下回るケースD-1EaおよびD-2Ea の採用が推奨される。

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6.5.4 商業装置の経済性検討結果の要約 Case1およびCase 3について経済性検討を行った結果、以下の結論を得た：乾式脱硫システムは排煙温度が低い方が、脱硫塔の本数が少なく（排ガスの体積流量が小さ

くなるため）、従ってより競争力が向上する。乾式脱硫システムの脱硫剤の原料として、消石灰よりも安価な生石灰を使用することは乾式

脱硫システムのコスト競争力を向上する有効な手段となる。乾式脱硫システムを広く商業装

置へ導入するために、生石灰を原料とする脱硫剤製造プロセスの工業化は急務である。脱硫剤製造装置を近隣の発電所で共有することもまた、乾式脱硫システムのコスト競争力を

向上する有効な手段となる。

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7. 実証装置に関する技術検討と概算費用 7.1 実証装置の基本設計 7.1.1 ブロックフロー図

実証試験はTATA Powerが保有するJojobera発電所Unit5での実施を想定し、6章で検討した商業

装置Case3の構成要素である集塵機および乾式脱硫脱硝システムの各性能を実証することを目的

としている。実証装置のブロックフローおよび排煙温度や排煙組成などのプロセス条件を図 7-1に示す。既設の節炭器下流から排煙の一部 (5,000 Nm3/hr) を採取して実証装置で煤煙を浄化した

後、空気予熱器の下流 (電気集塵機の上流) へ戻される。既設設備と実証装置の取り合い部(ガス抜

出・合流部) の条件を表 7-1に示す。

図 7-1 実証装置のブロックフロー図

表 7-1 既設ダクトと実証装置の接続箇所の取合い条件

接続部A (排煙採取) 接続部B (排煙戻し) 流量[Nm3/h] 5,000 5,156 *1) 温度[°C] 310 277 圧力[kPag] -0.15 -1.5 二酸化硫黄[mg/Nm3] 800 < 100 窒素酸化物 [mg/Nm3] 600 < 100 煤塵 [g/Nm3] 100 < 30

*1) 排煙流量は脱硝プロセスにおいて供給される空気希釈アンモニアガス供給量分増加する。

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7.1.2 既設発電所との取り合い実証試験計画にあたり、既設発電所において取合い箇所の詳細確認を行った。実証装置の接続部

を図 7-2に、接続部の詳細図と所掌を図 7-3に示す。接続ダクトの施工は、2017年12月の既設発

電所の定期点検においてTATA Power にて実施される予定である。

エコノマイザ―からの排煙

ESP A/H

煙突

接続部 A

接続部 B

Tie-in A

図 7-2 実証装置の接続箇所

図 7-3 実証装置接続箇所の詳細図

7.1.3 プロセス設計図書

実証装置の基本設計情報はプロセス設計図書一式 (以降、PDPと呼ぶ) として作成した。表 7-2にPDPの図書一覧を示す。

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表 7-2 プロセス設計図書の図書一覧

図書番号タイトル S-1223-051 Process Description for Demonstration Plant S-1224-001 Equipment List S-1224-351 Process Data Sheet for SCR Reactor (R-351) S-1224-352 Process Data Sheet for Flue Gas/NH3 Mixer (M-351) S-1228-151 Process Data Sheet for Multi-Cyclone Separator (S-151/S-152) S-1228-351 Duty Specification for Ammonia Injection Package (Z-351) S-1228-003 Catalyst and Chemical Summary S-1228-004 Utility Summary D-1223-151 PFD for DeSOx Unit D-1223-351 PFD for DeNOx Unit D-1225-051 Plotplan for Jojobera Power Plant D-1225-052 Plotplan for demonstration plant D-1225-101 P&ID for Symbology D-1225-151 P&ID for DeSOx Unit Tie-in from Existing Plant D-1225-152 P&ID for DeSOx Unit Dust Removal and DeSOx Tower D-1225-351 P&ID for DeNOx Unit SCR Reactor D-1225-352 P&ID for DeNOx Unit Dust Blaster and PA Distribution

D-1350-151 Mechanical Drawing for DeSOx Tower (C-151) / Multi-cyclone Separator (S-151/152) / Fresh Agent Hopper (V-151)

D-1350-152 Mechanical Drawing for Ash Feeder (Z-153) D-1350-351 Mechanical Drawing for Dust Blaster (Z-352)

7.1.4 主要機器

実証装置の主要機器は集塵機、脱硫塔 (C-151) および脱硝反応器 (R-351) である。集塵機は慣性集塵機 (S-151) とマルチサイクロン (S-152) が一体化した装置であり、1基設置す

る。マルチサイクロン (S-152) は2個のサイクロンで構成されている。集塵機の寸法は高さ5.455 m、幅3.7 m、奥行き1.2 mである。脱硫塔 (C-151) は1塔設置する。脱硫塔の寸法は高さ13 m、幅4.62 m 、奥行き3.85 mである。脱硝反応器 (R-351) は2層の触媒層から構成される1塔を設置する。脱硝反応器の寸法は、高さ7.1 m、幅0.9 m、奥行き0.9 mである。

7.1.5 必要敷地面積実証装置の設置に必要な敷地面積は約170 m3 (21 m×8 m) である。プロット図を図 7-4に示す。

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図 7-4 実証装置のプロット図

7.1.6 用役消費量

実証装置の運転に必要な用役、触媒および薬品を以下に示す。用役: 電気常用 49.7 kW, 最大 50.1 kW 計装空気常用 1.4 Nm3/h, 最大 11.4 Nm3/h プラント空気常用 0.0 Nm3/h, 最大 100 Nm3/h (間欠使用のみ) 工業用水常用 0.0 ton/h, 最大 3.0 ton/h (間欠使用のみ) 触媒および薬品: 脱硫剤 16.2 kg/h 脱硝触媒 0.63 m3 無水アンモニア 1.48 kg/h (液化アンモニアシリンダー 50kg/本にて供給)

7.1.7 排出物

実証設備より排出される排出物は石炭灰、使用済み脱硫剤および使用済み脱硝触媒である。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 石炭灰：

石炭灰は慣性集塵機(S-151)およびマルチサイクロン(S-152)の底部から合計475 kg/h で排出され

る予定である。排出された石炭灰は、ダスト移送ファン(K-151A/B)によってダストホッパー(V-152)に移送され、最終的に１日１回程度の頻度でトラックにて当該発電所内の既設の灰捨場に移

送される。使用済脱硫剤：使用済脱硫剤は、脱硫塔底部から16.2 kg/hで排出される予定であり、ドラム缶で一時貯留して最

終的に当該発電所内の既設の灰捨場に移送される。使用済脱硝触媒：実証試験運転期間6ヶ月分に相当する脱硝触媒として0.63 m3 が初期充填される。実証試験運転

後、使用済み脱硝触媒はインド法令に従って廃棄処理する。

7.1.8 実証装置の詳細検討効率的に脱硝反応を進行させるには、還元剤であるアンモニアと排ガスが均一に混合している必

要がある。脱硝プロセスにおける詳細検討として脱硝反応器 (R-351) へのアンモニアの均一分散

を確認するため、CFD解析を実施した。解析の結果、以下のアレンジメントによって、濃度変動

幅 +/- 7.0 % の範囲内でアンモニアを均一分散できることを確認した。CFD解析の結果は図 7-6に示した。アンモニアを拡散させるために空気で80倍に希釈して供給。排ガス/アンモニアミキサー (M-351)

4本の分散管に10 mm径の穴を全28個設ける。詳細は図 7-5を参照すること。脱硝反応器との間に最低1カ所のエルボを設ける。脱硝反応器入口より最低6 mの間隙を確保して据え付ける。また、脱硝反応器入口までは

最低3ｍの直管長を確保する。

図 7-5 排ガス/アンモニアミキサー（M-351）の詳細

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図 7-6 空気希釈アンモニアガスの脱硝反応器への分散

7.2 実証試験計画

TATA power 社が保有する火力発電所への乾式脱硫脱硝システムの導入計画スケジュールを図 7-7に示す。実証試験装置の詳細設計、建設および試験は2018~2019年度中の実施を予定してい

る。2018年第一四半期から第二四半期後半に詳細設計、2018年第三、第四四半期内に装置を建設

し、2019年第一四半期から第二四半期に試験運転を実施する計画である。実証試験結果を踏まえ

て、乾式脱硫脱硝システムの商業機への導入について最終投資判断を行う。実証試験終了後は装

置を解体することを予定している。

図 7-7 TATA power社向け乾式脱硫脱硝システム導入計画スケジュール

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8. 脱硝触媒の詳細情報触媒仕様（セル数、組成、触媒量）を検討するにあたり、事前に排ガス中のダストによる触媒性能

への影響を明確にする必要がある。そのため、TATA Power 社所有の石炭火力発電所から石炭灰を

入手し、そのダスト性状の調査およびそれが触媒性能に及ぼす影響について検討した。

8.1 インド石炭灰の性状分析 TATA Power 社所有の石炭火力発電所のうち、Jojobera発電所およびMaithon 発電所の石炭灰を

入手し、その組成および物性を分析した。石炭灰サンプルの採取は、ボイラー排ガス下流の熱交換

器下部ホッパーおよび更に下流の電気集塵機から回収した石炭灰が集約保管される石炭灰サイロか

ら採取した。組成分析にはPHILIPS社製蛍光X線分析装置 MagiX PRO型を、粒度分布測定には

HORIBA社製レーザー回折/散乱粒度分布測定装LA-950型を、SEM観察にはJEOL社製走査電子

顕微鏡 JSM-6010LA型をそれぞれ使用した。各石炭灰の粒度分布測定結果を表 8-1および図 8-1に示す。Jojobera発電所およびMaithon発電所の

石炭灰のメジアン径はそれぞれ28.9μmと23.3μm、平均粒径は45.0μmと45.2μmであり、日本

国内で入手できる一般的な石炭灰よりも大きい傾向を示した。またこれらインド発電所の石炭灰の

粒度分布は、いずれも、約10～20μmの第1ピークおよび約60～100μmの第2ピークをもつ二山の

粒度分布であり、約11μmにピークを持つ国内石炭灰とは異なる粒度分布を示した。

表 8-1 石炭灰の粒子径

図 8-1 石炭灰の粒度分布

Jojobera Maithon 国内（参考）

メジアン径 μm 28.9 23.3 11.7

平均径 μm 45.0 45.2 16.8

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant これらのSEM写真を図 8-2に示す。国内石炭灰は10μm級の比較的微小な粒子が多く、粗大粒子は

わずかであるに対し、インド石炭灰は微小な粒子の中に50 μm以上（100 μm級）の不定形の粗大

粒子を多く含んでいることが観察された。この観察結果は粒度分布測定結果と一致している。

a) Jojobera

b) Maithon

c) 国内(参考)

図 8-2 石炭灰のSEM像

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組成分析結果を表 8-2に示す。インド石炭灰の成分は共にSiO2とAl2O3の合計が80%以上を占め、次

いでFe2O3、TiO2、K2Oの順に多く含まれていた。触媒被毒物質であるアルカリ金属（K2O）は国

内石炭灰の約2倍量が含まれていた。一方、同じく触媒被毒物質であるCaOの含有量は約1/3であっ

た。そのほか、P2O5、MgO、BaO、SO3、Na2Oが微量含まれていた。

表 8-2 組成分析結果

8.2 触媒被毒成分による影響排ガス中のダストに含まれる触媒被毒物質には、アルカリ金属（Na, K）やアルカリ土類金属

（Mg,Ca）の他、As, Pb, Pなどが挙げられる。インド石炭灰中に含まれるKの含有量が国内灰の約

2倍であることから、Kによる触媒性能劣化への影響は高いことが推察されるが、その一方でCaの含有量は国内灰の約1/3であることからCaによる性能劣化への影響は低いと推察される。また、そ

の他の被毒物質はごく微量であり大差ない。これらのことを総合的に判断すれば、インド石炭灰の

被毒による触媒性能への影響は、国内石炭灰と大差ないものと推察される。従って、インド石炭火

力向けの脱硝触媒設計を行う際は、触媒性能劣化率を日本国内の経験値と同等のものとして考慮す

ることでよいと考えられる。

8.3 ダストの触媒摩耗への影響排ガス中のダストによる脱硝触媒の摩耗への影響を調査するため、石炭灰を模擬した摩耗材（珪

砂）を用い、各種条件におけるハニカム脱硝触媒の摩耗率を測定した。脱硝触媒サンプルには、除

塵後の低濃度ダスト排ガス処理を想定し、ハニカム型高活性触媒（当社仕様、4.9 mmピッチ）を

選定した。摩耗率は、脱硝触媒サンプルを所定の形状に切り出し、摩耗試験装置（図 8-3参照）に

設置した後、触媒サンプル端面に摩耗材を含むガスを30分間吹き付け、試験前後の脱硝触媒サンプ

ルの重量差を測定することにより算出した。摩耗試験用の摩耗材にはメジアン径が80 μm、52

Jojobera Maithon 国内（参考）

SiO2 53.9 56.1 59.1

Al2O3 30.2 30.0 21.9

Fe2O3 6.8 6.0 6.5

TiO2 2.7 2.6 1.8

K2O 2.2 1.8 1.1

CaO 1.8 1.3 6.1

P2O5 1.3 0.8 0.6

MgO 0.4 0.5 1.1

BaO 0.2 0.2 0.2

SO3 0.2 0.2 0.7

Na2O <0.1 0.1 0.4

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant μm、20 μmの硅砂を用い、表 8-3に示すダスト濃度、ガス流速の条件にて摩耗試験を実施した。

図 8-3 磨耗試験装置

表 8-3 磨耗試験条件一覧

Test No. ダスト濃度 (g/Nm3)

ダスト平均粒子径 (μm)

ガス流速 (Nm/s)

1 70 52 40

2 30 52 40

3 5 52 40

4 70 80 40

5 70 20 40

6 70 52 30

7 70 52 20

ダスト摩耗試験の結果より得られた、ダスト濃度と摩耗率の関係、ダスト粒径と摩耗率の関係、断

面ガス流速と摩耗率の関係をそれぞれ図 8-4、図 8-5 および図 8-6に示す。

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図 8-4 ダスト濃度と磨耗率の関係

図 8-5 ダスト粒径と磨耗率の関係

図 8-6 断面ガス流速と磨耗率の関係

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試験条件の範囲において、図 8-4および図 8-5に示すとおり、ダスト濃度が高いほど、またダスト

粒径が大きいほど摩耗率は直線的に増加する。その一方で図 8-5は、ダスト粒子が小さくとも、ダ

スト濃度がある程度高ければ摩耗することを示している。また図 8-6に示すとおり、摩耗率はダス

ト流速の3.8 乗に比例して増加する。従って、触媒摩耗を抑制するためには、触媒層へ到達するダ

ストが、低濃度、小粒子径、低流速となる装置構成（設計）をすることが望ましい。当社の脱硝触媒の商業実績、石炭灰の分析結果および摩耗試験結果から次のことが言える。

1) インド国内の石炭灰は日本国内の石炭灰に比べて粒径が大きく、50μm 以上の粗大粒子を多く含

むことから、石炭灰それ自体の触媒摩耗への影響は大きいと考えられる。 2) しかし、マルチサイクロン（MC）と乾式脱硫或いは電気集塵機で除塵した後の脱硝では、ダス

ト濃度は数 10 mg/Nm3 であり、かつ祖大粒子が除去された微粒子であるため、摩耗への影響は

ごく軽微と思われる。 3) 実際に当社商業実績において、上記レベルのダスト濃度、かつ SCR 設計ガス流速 2～3Nm/s の

領域では、ダストによる摩耗は無視できるレベルである。 4) 除塵をしないダスト濃度 100g/Nm3 のケースは、摩耗試験結果から外挿して 20g/Nm3 の数倍の

摩耗率を示すものの、この濃度領域では、部分的な閉塞と摩耗が同時進行すると考えられるため、

単に摩耗だけを推定することは難しい。 5) 日本国内の一般的な石炭火力発電におけるダスト濃度は 20g/Nm3 程度であるが、当社の石炭火

力用脱硝触媒は、標準摩耗試験条件において摩耗率が約 14％以下に調整され、4～6 年の機械寿

命実績が認められている。 6) 本摩耗試験で使用した触媒サンプルは低濃度ダスト用触媒であるため、石炭火力用触媒と比較し

て 2 倍程高い摩耗率であるが、商業機および実証機のダスト濃度は日本の約 3 桁低く、ほとんど

摩耗しないと予測されるため、4～6 年の機械寿命は十分に期待できる。

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8.4 触媒詳細情報商業機および実証試験装置のそれぞれの設計条件を基に設計した触媒仕様を表 8-4に示す。

表 8-4 触媒設計条件と触媒仕様

1) Inlet Gas Condition Commercial Plant

Demonstration Plant

Flow Rate Nm3/h 2,300,000 5,000

Temperature °C 270

Gas

Composition

O2 vol% 3.3 - 4.5

CO2 vol% 15 – 16

H2O vol% 10

N2 vol% Balance

NOx mg/Nm3 600

SOx mg/Nm3 100

Dust mg/Nm3 30

2) Requirement Commercial Plant

Demonstration Plant

Outlet NOx mg/Nm3 100

Leak NH3 ppm ≦ 5

Life time year 2 1

3) Specification Commercial

Plant Demonstration

Plant

Catalyst Type - Honeycomb

Catalyst model - NRU-5

Cell Number - 35

Catalyst Section Size mm x mm 150 x150

Number of Catalyst - 100 25

Number of Module - 80 1

Number of Layer - 2 2

Catalyst Length mm 905 560

Catalyst Volume m3 325.8 0.63

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9. 新環境規制の概要と対応状況の調査本章ではインドにおけるエネルギー消費の現状や、MoEF&CCから2015年12月に発行された新環

境規制など、インドの発電業界をとりまく背景情報についてまとめる。さらには新環境規制の対応

状況や課題、インド政府内での最新の議論状況などについて調査した結果をまとめる。

9.1 インドのエネルギー部門構成インドの各発電設備の設備容量比率を図 9-1に示す。2017年3月時点における設備容量の60%は石

炭で、エネルギー部門は熱源および電力ソースとして化石燃料への依存度が高いことがわかる。

2016年4月~2017年3月における総発電量の86%は火力発電に拠るものであった。インド政府の再

生可能エネルギーへの期待は増してきているものの、石炭のエネルギーミックスの観点、ベース

ロード電源としての役割を考慮すると、少なくとも予想できる将来の範囲内では石炭が今後も重

要なエネルギー源であり続けると考えられる。

図 9-1 インドの各発電設備の設備容量比率（2017年3月31日時点）

図 9-2はインドにおける年間エネルギー需要の推移を示す。年間エネルギー需要はCAGR 5.2%で

過去10年以上にわたり成長し、2016~17年の年間エネルギー需要は11,430 億kWhに達している。

図 9-3はインドにおける発電用途での年間石炭消費量の推移を示す。インドにおける年間石炭消

費量は2015~16年で546百万トンに達し、2004~05年から2015~16年にかけてCAGR 6.33%で増加

している。電力需要が高まるにつれて石炭火力発電の設備容量が増えてきたことがわかる。

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図 9-2 インドにおける年間エネルギー需要の推移 (Source: CEA, Power Supply Position Reports)

図 9-3 インドにおける発電用途での年間石炭消費量の推移

(Source: Coal Directory of India, Coal Controller’s Organization, Govt. of India) 図 9-4に示す通り2007年から2017年の発電設備容量は CAGR7.62%と増加している。その中でも

再生可能エネルギー発電の発電設備容量はCAGR 22.4%と最も増加しており、続いて火力発電の

発電設備容量がCAGR 9.26%と続く。再生可能エネルギー発電は高成長率ではあるが、全体の

67%の設備容量を占める火力発電に対して、再生可能エネルギー発電は全体の18%程度と小規模

である。

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図 9-4 インドにおける発電設備容量の推移（2007－2017年）

(Source: CEA, Installed Capacity and Executive Summary Reports) 9.2 新環境規制の概要

電力庁（Ministry of Power, MoP）およびCEAの資料等により、排ガス規制動向を調査した。

CEAによる電力計画（ドラフト版）および19期電力調査レポートの要約を以下に述べる。 2017~2022年までに石炭火力56,400 MW、ガスおよび水力38,040 MWの容量増を予定するが、

更なる追加は予定しない。2022-2027年5カ年計画は今後の需要による。 2022年までは、新環境規制の遵守には技術的、財政的および規制適用の問題がある。石炭火力のPlant load factor（PLF）は、電力需要や新設発電所（化石/非化石）の稼動などの

影響により、50%から60%の間で推移する。 2021~22年の石炭需要は約7億3,000万から8億トンと予想。 2021~22年までに再生可能エネルギー比率を20%とする. 2022年3月までの新規容量の47%は非化石燃料ベース電源となる。今後系統変動が大きくなるため、石炭火力でも負荷変動対応の向上、最低負荷率の低減が必要と

なるが基本的には負荷変動対応となるミドル電源はガスおよび水力が主力となるべき。石炭火力については、新しくより高効率で低環境負荷な技術を導入していく。発電分野においては高効率で低環境負荷技術の導入を目指している。環境負荷に関して、石炭火力

からの排出抑制を強化するために、MoEF&CCは2015年12月に新環境規制を発行した。表 9-1に示すように、大気への排出についてはSPM、 SO2、NOxおよび水銀が規制されている。用水につ

いても表 9-2に示すように厳しく規制されることとなった。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 表 9-1 新排出規制（2015年12月7日）

2003年12月31日以前

運転開始

2004年1月 ~2016年12月運転開始

2017年1月以降

運転開始

Capacity MW Less than 500

500 and above

Less than 500

500 and above

SPM mg/Nm3 100 50 30 SO2 mg/Nm3 600 200 600 200 100 NOx mg/Nm3 600 300 100 Hg mg/Nm3 Not

regulated 0.03 0.03 0.03

出典: CEA

表 9-2 用水使用規制（2015年12月7日）

MoEF & CCによる火力発電所の用水使用規制

1. 還流タイプの冷却システムを持つ発電所全ては冷却塔を設置し、今後2年以内に発電量

当り使用水を3.5 m3/MWhとすること。

2. 冷却塔を持つ発電所は、今後2年以内に発電量当り使用水を3.5 m3/MWhとすること。

3. 2017年1月1日以降に運開予定の発電所は発電量当り使用水を2.5m3/MWhとし、排水ゼ

ロを達成すること。出典: CEA

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9.3 新環境規制の対象となる発電所の現状と対応状況 TATA Power社に加えて主要州電力会社としてMaharashtra州有電力公社であるMAHAGENCO、

主要民間電力会社としてReliance Power社の使用炭性状および排ガス特性、各社の新環境規制対応

状況等をヒアリングにより確認した。そのヒアリング結果を報告する。

9.3.1 石炭性状の調査各電力会社の使用炭性状を表 9-3に示す。なお、一部性状の特異性を確認するために、旧グレード

CからEの標準炭の分析を追加実施した。

表 9-3 各電力会社の使用炭性状一覧

Max. Min. Ave.

Middling MCL SECL,MCL, WCL

G6-8 G8-11 G11-14

Gross air dried Kcal/ kg 4474 3283 4671 5707 3750 4561 3731 3500 3655 3646 5880 5640 4943

Total Moisture % ar 4.05 12.50 7.11 16.72 4.1 5.95 10.8 12 11.65 12 6.1 6.6 5

Moisture % ad 1.06 5.43 5.63 0.97 1.44 4.9 4.3 3.4

Ash Content % ad 41.72 45.15 36.19 49.72 29.52 40.71 33.76 41.2 36.66 33.52 10.6 16.4 25.5

Volatile Matter % ad 19.03 22.87 15.92 23.71 13.56 16.51 26.61 21.56 24.4 21.4 32.2 29.3 28.1

Fixed Carbon % ad 38.19 26.55 40.78 52.51 31.05 41.34 28.83 25.5 27.25 52.2 50 43

Total Carbon Content % daf 47.84 61.4 40.8 48.58 40.34 35.87 40.58 38.3 77.06 78 76.17

Total Hydrogen Content % daf 2.89 3.58 2.81 3.15 2.61 2.66 2.46 3.7 4.6 4.71 4.87

Total Nitrogen Content % daf 1 1.07 0.25 0.61 0.97 0.72 0.85 0.96 1.76 1.68 1.63

Total Sulphur Content % daf 0.39 0.93 0.3 0.52 0.63 0.59 0.31 0.46 0.3 0.38 0.51

Oxygen Content (diff.) % daf 4.58 13.414 3.909 6.07 10.8 12 6.98 16.38 15.3 16.89

Combustible Sulphur % daf

Mercury in coal mg/kg 0.045 0.013 0.049

SiO2 % db 64.45 50.46 59.43 57.2-63.8 59.7 56.26 44.3 52.6 69.04

Al2O3 % db 33.32 22.08 27.13 26.7-31.8 28.35 27.71 26.72 27.31 22.54

Fe2O3 % db 15.44 3.49 6.63 2.0-7.2 4.1 7.14 16.3 13.5 3.11

CaO % db 2.32 0.08 0.82 1.1-1.6 2.05 0.66 5.1 1.56 0.8

MgO % db 1.44 0.32 0.59 0.4-1.0 1.5 0.66 0.81 0.37 0.53

Na2O % db 5.41 0.062 0.79 NA 2.37 0.02 0.03 0.04

K2O % db 2.05 0.946 1.41 NA 1.22 0.46 0.49 1.04

TiO2 % db 2.102 1.46 1.72 1.0-1.5 0.02 2.14 1.8 1.49

Mn3O4 % db

P2O5 % db 0.951 0.241 0.56 0.2-0.8 0.9 0.04 1.89 0.98 0.1

SO3 % db 1.28 0.09 0.27 Traces 0.35 0.2 1.93 0.8 0.49

MnO % db 0.23 0.037 0.08 0.15

V2O5 % db 0.04 0.03 0.03

Li2O % db

Grade Standard

Grade-C Grade-5 Grade-E

MAHAGENCO Koradi Reliance

CCL

5esign Actual 5esign Actual

ASH ANALYSIS

Source CCL, .CCL

Actual 5esignActual

CALORIFIC VALUE

CHEMICAL ANALYSIS

ULTIMATE ANALYSIS

Thermal Power Station

Items＿＿_____＿＿＿＿＿＿＿＿＿

＿

TATA PowerJojobera Maithon Power Limited

Design：設計炭、Actual：実績値、MCL：Mahanadi Coalfield Ltd、CCL：Central Coalfield Ltd、BCCL：Bharat Coking

Coal Ltd、SECL：South Eastern Coalfield Ltd、WCL：Western Coalfield Ltd、Middling：選炭品

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発電所により分析項目が異なるが、傾向として発熱量は3,000~4,500kcal/kg、灰分は30~50％、硫

黄分は0.3~1.0%程度であった。インドでは一般的発電所向け石炭はG12からG14とされているが、

今回はTATA Power Maithon発電所の高位炭、Jojobera発電所選炭品を除いて発電所用グレードで

あることがわかる。これら灰分および硫黄分を図 9-5および図 9-6に示す。なお、全体傾向を見る

ための比較として、JCOALが保有しているインド火力発電所から代表的データをリファレンスと

して図示している。Maithon発電所の高位のみG6相当で原料炭データと推察されるが、同等グレー

ドの標準的な性状（緑プロット）より、灰分、硫黄分ともに高めであった。

0

10

20

30

40

50

60

2000 2500 3000 3500 4000 4500 5000 5500 6000

Ash

(%)

GCV (kcal//kg)

AshContent

ReferencesG12G13G14

図 9-5 発電所使用炭の発熱量と灰分の関係

註：リファレンスはインドの他発電所データ（JCOAL調べ、プロットのみ）

0

0.2

0.4

0.6

0.8

1

1.2

2000 2500 3000 3500 4000 4500 5000 5500 6000

Sulp

hur

(%)

GCV (kcal//kg)

SulphurContentReferences

G12G13G14

図 9-6 発電所使用炭の発熱量と硫黄分の関係

註：リファレンスはインドの他発電所データ（JCOAL調べ、プロットのみ）

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 揮発分や固定炭素など、基本的性状は瀝青炭質を示しているため、発熱量は灰分と逆比例傾向にあ

る。発熱量の幅が広い理由としては、受入れ炭のばらつきがあるため、発熱量調整で高発熱量炭を

使用しているためと予想される。灰成分に関しては、シリカが多い傾向にある。これらを含む排ガスはボイラーおよびエアヒータ等

で高い磨耗性を持つ懸念があり、灰分総量も高いことから、今後環境装置の対応にはこれらの耐久

性が課題となる懸念がある。また、ボイラー伝熱効率に影響するスラッギングインデックス

（SI）、ファウリングインデックス（FI）を灰分組成から計算したところ、SIで0.02～0.07（標準

試料0.03~0.09）、FIで0～0.34（標準試料0~0.01）であり、どの石炭も付着性の懸念は低いことが

判明した。規制対象である水銀については、インド側での分析値が得られていないので、標準炭の

データを参考にしたが、排出規制値の0.03 mg/kgと同等レベルであり、現状の集塵（ESP）でかな

り除去されていることを考慮すると、規制内には収まっていると考えるのが妥当である。

9.3.2 排ガス性状の検証それぞれの石炭性状から算出した排ガス性状を表 9-4および図 9-7に示す。ガス量の計算に必要な

元素分析値まで得られた石炭性状について、酸素過剰率を一律6%として算出した。SPMの値はボ

イラー出口濃度としている。NOx は石炭中のN分由来より燃焼条件に依存して生成するので、本計

算には含めていない。 SOx濃度については全ての計算結果が規制値を上回り、脱硫への対応が必要になると推測される。

ESPの性能面では、MPLの場合入り口濃度が20 g/Nm3台であるのに対して50 mg/Nm3以下まで落

ちており、高い性能を示している。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 表 9-4 石炭性状より計算した排ガス性状

Max. Min. Ave.


Gross air dried Kcal/ kg 4474 3283 4671 5707 3750 4561 3731 3500 3655 3646

Total Moisture % ar 4.05 12.50 7.11 16.72 4.1 5.95 10.8 12 11.65 12

Moisture % ad 1.06 5.43 5.63 0.97 1.44

Ash Content % ad 41.72 45.15 36.19 49.72 29.52 40.71 33.76 41.2 36.66 33.52

Volatile Matter % ad 19.03 22.87 15.92 23.71 13.56 16.51 26.61 21.56 24.4 21.4

Fixed Carbon % ad 38.19 26.55 40.78 52.51 31.05 41.34 28.83 25.5 27.25

Total Carbon Content % daf 47.84 61.4 40.8 48.58 40.34 35.87 40.58 38.3

Total Hydrogen Content % daf 2.89 3.58 2.81 3.15 2.61 2.66 2.46 3.7

Total Nitrogen Content % daf 1 1.07 0.25 0.61 0.97 0.72 0.85 0.96

Total Sulphur Content % daf 0.39 0.93 0.3 0.52 0.63 0.59 0.31 0.46

Oxygen Content (diff.) % daf 4.58 13.41 3.91 6.07 10.8 12 6.98


Mercury in coal % dbCalculated dataFlue gas (Excess O2 = 6%) Nm3/kg-fuel 0 0 17 21 15 17 14 12 14 15SOx mg/Nm3 460 890 406 602 917 963 441 604PM g/Nm3 21 24 20 24 25 34 26 22

5esign Actual

CCL

ULTIMATE ANALYSIS

5esign Actual

Source CCL, .CCL

CALORIFIC VALUE

CHEMICAL ANALYSIS


Items＿＿_____＿＿＿＿＿＿＿＿＿＿


MAHAGENCOKoradi Reliance Power

Actual 5esignActual

0

200

400

600

800

1000

1200

0 10 20 30 40 50

SO2

(cal

c.)

(mg/

Nm

3)

PM (calc.) (g/Nm3)

Coal data

References

MPL(Calculated) MPL

(Actual)

Jojobera(Actual)

図 9-7 SPM（ESP入口）およびSO2濃度の計算値

表 9-5に各発電所の実排ガスの性状データを示す。各ユニットの排出規制値も示す。緑色で示す値

は規制値以内であり、黄色は規制値上限に近い（規制値の90％以上）、赤色は規制値を超えている

ことを示す。SOx濃度の計算値と実測値はほぼ同等の値であり、脱硫への対応が必要であることが

わかる。また、同様に脱硝への対応が必要であることがわかる

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 表 9-5 各発電所の実排ガスの性状データ

ReliancePower

Unit-1 Unit-2 Unit-3 Unit-4 Unit-5 Unit-1 Unit-2

Gas Temperature deg C 127 133 138 127 133 136 137 110-135

O2 Concentration % dry 7.2 7.4 7.2 6.8 7 8.8 7.7 5.5-6.5

Exces Air Ratio - 35

H2O Concentration % wet 6.86 7.63

CO2 Concentration % dry 11.4 11.8 11.6 11.8 11.8 10.6 11.6 13 - 15

NOx Concentration mg/Nm3 322.8 334.7 326.2 297.3 290.3 405 446 250-400

SOx Concentration mg/Nm3 563.6 577.2 572.3 524 534.9 827 793 550-800

5ust Concentration mg/Nm3 74.5 74.7 74.6 49.5 49.6 48.9 25.8 40-70

Hg Concentration mg/Nm3 <0.1 <0.1 <0.1 <0.1 <0.1 <0.01 <0.01

Load MW 54 120.31 107.46 119.8 119.59

NOx mg/Nm3 600 600 600 600 300 300 300 300SO2 mg/Nm3 600 600 600 600 600 200 200 600SPM mg/Nm3 100 100 100 100 50 50 50 50Hg mg/Nm3 0.03 0.03 0.03 0.03


Items＿＿_____＿＿＿＿＿＿＿＿＿

TATA Power Jojobera Maithon Power Limited

Criteria

9.3.3 新環境規制への対応状況新環境規制への対応状況について、各発電所に加え政府および中央電力会社にも状況をヒアリング

した。新環境規制への対応状況および取り組みにあたっての諸課題について以下に述べる。

9.3.3.1 新環境規制への対応状況 CEAは地域電力委員会や発電会社と会合を重ね、速やかに環境対応を実施するように働きかけてき

た。MoPの指示によりCEAは表 9-6に示すように2018年から2022年までを対象とした段階的な導

入計画を検討している。この計画によると、約66GW（222ユニット）はESPの強化に合意してい

る。また約161GW（414ユニット）はFGDの導入に合意している。SCRは実証に至っていない

が、NTPCが自社で使用している高灰分炭でのSCR/SNCRのパイロットテストを実施中である。新環境規制により、FGD設備への莫大な需要が創出されたが、同時に非常に厳しい時間的制約も課

されている中、供給者には既存供給能力とその増強を限られた期間に対応することが求められてい

る。特に2021年および2022年では、年間約170ユニットの脱硫設備導入が必要であり、設備メーカ

ーの対応能力が懸念される。また、州電力および民間電力各社には環境対応に多くの投資が必要で

あり、電力料金への影響が避けられないとしており、この状況にインド政府がどのような政策対応

を取っていくのかは注視が必要である。

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表 9-6CEAによる環境装置段階計画（Phasing Plan）

Year NOx SOx SPM

Capacity (MW) Units Capacity (MW) Units Capacity (MW) Units

2018

Pilot project by NTPC is underway. Phasing Plan for de-NOx will be finalized in 2018

500 1 500 1

2019 4,940 8 1,300 2

2020 27,230 55 10,705 28

2021 64,027.5 172 23,495 97

2022 64,704.5 178 28,525 94

total 161,552 414 65,925 222

Source: CEA

9.3.3.2 規制対象物質ごとの対応状況浮遊粒子状物質 (SPM) 新環境規制を遵守するために電気集塵機（ESP）の強化が必要とされている発電所のユニット数を

表 9-7に示した。273 ユニット（設備容量にして72,659 MW）の発電所で強化が必要である。この

うち、2018年から2022年までの期間中に対応が必要とされているのは全体の85%にあたる231ユニ

ット（設備容量にして65,925MW（全体の90%））となっている。 ESP強化にあたっては、既設ESPの改造／交換またはバッグフィルターの導入等の対応が想定され

る。発電所の状況により、既設設備のレイアウト変更を伴う可能性もある。

表 9-7 ESP強化が必要な発電所のユニット数

ユニット数容量(MW)

ESP強化対応の必要なプラント 273 72,659

2018-2022年でESP強化対応検討中のプラント 231 65,925

硫黄酸化物 (SOx) 既設、新設を問わずあらゆるユニットについて、新環境規制を遵守するためには例外なくFGDの導

入が必要となるが、これに伴う主な導入課題と障壁は以下のとおりである。なお、導入課題につい

ては9.4.1章にて詳細を述べる。設置スペースの制約高品質の石灰石供給および副生石膏の処理期限内での技術保有メーカーおよびその供給能力 FGD導入による所内電力消費率の上昇（コスト増）

500MW以上の新設プラントに関しては計画時に用地内FGDスペースを織り込んでおり、また石灰

石の供給も検討済みである。また、FGDに必要な石灰石は500MWユニットに対して年間60,000トン必要で、計画中のプラント

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 向けも含めた250GWの石炭火力全体では約3,000万トン／年が必要と試算されている。

一方、500MWユニットのFGDでは年間85,000トンの石膏が副生される見込みで、インド全体では

4,200万トン／年の石膏が生産されることになる。FGD導入による所内電力消費率の上昇は、ユニ

ット効率で1.0~1.5%の影響と予想されている。

表 9-8 FGD装置の設置が必要なユニット

ユニット数容量(MW)

FGD設置が必要なプラント 482 170,931

2018-2022年でFGC設置検討中のプラント 415 161,552

窒素酸化物 (NOx) 新環境規制の規制値のうち600 mg/Nm3については低NOxバーナの利用など燃焼側での対応が可能

である。しかし、燃焼側の対応だけでは300 mg/Nm3および100 mg/Nm3の規制値は達成できず、

SCRやSNCR等の脱硝設備の追設が必要となる。ただし、海外で実用化されているSCRはダストを

多く含むインドの排ガス処理では実証されていない。またSCR導入による発電量の内部消費率上昇

も懸念される。

水銀世界的に見ても水銀除去の確立された技術はないが、ESP、脱硫設備および脱硝設備において水銀

も除去されているため、新環境規制の基準を満たしている。

9.4 新環境基準を遵守するための課題 9.4.1 SOx排出基準に準拠する為の課題

新排出基準が導入されるまではインドにはSO2排出に関する国家基準が存在しておらず、国営お

よび私営の火力発電所におけるSO2排出量のモニタリングが行われていたものの、脱硫技術は導

入されていなかった。結果として、インドの発電部門における脱硫技術の導入実績は非常に限定

的なものとなっている。インドの既存の発電設備に対するSO2排出基準は600 mg/Nm3、および

200 mg/Nm3であるが、インド産の石炭の硫黄含有量は輸入石炭に比べて非常に低い事実を考慮

すると他国の基準に比べ大きく緩和されたものであることがわかる。（中国や米国の基準は100 mg/Nm3）しかし、インドにおける脱硫技術導入には大きな課題が2つ存在する。一つ目は設備導

入スペースの不足と二つ目はファイナンスの制約である。設備導入スペースの不足 FGDは排ガス中のSO2を低減する技術であり、新環境基準に準拠する為にはFGDの導入が必要と

なる。FGD設備の導入には脱硫装置の設置スペース、および脱硫剤に用いる石灰、副生物となる

石膏の保管スペース等が必要である。2007年のCEAのレポートによると、500 x 2MWの石炭火

力発電所向け湿式FGD（石灰石膏法）の導入に28,500m2もの敷地が必要という報告もある。石灰

の代わりに海水の使用が可能な発電所では湿式FGD（海水法）を導入することで必要な敷地が約

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 30％低減可能である。特に、インドの2003年以前に稼働した500MW以下の火力発電設備におい

ては、設計当時に十分な敷地面積が確保されていなかったため、FGD導入に必要な空間の確保が

困難である。従って、FGDの設備投資費用が確保できたとしても、設備導入の為の空間不足が問

題となり導入には至らないことが想定される。しかしながら、標準的な設計が施された500MW以

上の発電設備においては、空間不足がFGD導入の為の障壁となることは考えにくい。一般的に湿

式脱硫装置の設置スペースは、煙突手前の誘引ファンと煙突との間が使われる。ファイナンスの制約 FGD導入にともなう費用を表 9-9に示す。この費用はNTPCの入札に基づくものである。参考ま

でにNTPCによるFGD技術の比較一覧も表 9-10に示す。FGDの導入のための初期投資、および

発電所停止による経営状況の悪化は予見でき、設備導入に際し関税の優遇やMoPからの補助金が

なければ発電所の経営者は設備投資費用の確保が困難である。残余寿命が短い発電設備に対してFGDを導入することはさらに困難な課題と言える。FGD導入の

ための空間の確保が可能な場合であっても、設備投資費用に見合った投資であるかが問題とな

る。そのため、電力販売契約などの契約の見直しが必要となることが考えられる。CEAによると

27の発電設備が既に稼働後30年が経過しており、その設備容量の合計は5,301MWであるが、こ

れらの発電設備にとって設備投資費用は大きなインパクトとなる。

表 9-9 インドにおける湿式FGD導入に要するコスト見積り Wet FGD system Seawater FGD system Capital cost, US$/MW 90,910 70,300 Fixed operating costs, cents/MWh 37.9 28.8 Variable operating costs, cents/MWh 0 0 Auxiliary consumption, % 1.5 1.25 FGD efficiency, % 90 90

(Source: Disease Control Priorities Third Edition, Injury Prevention and Environmental Health [2016])

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 表 9-10 FGD 技術の比較

Wet FGD Dry FGDCommerciallyavailable range

~ 1,100 MW 300~400 MW single absorberFor novel integrated desulphurization(NID) each module of 75MW

Types 1) Seawater2) Freshwater

1) Spray dry absorber (SDA)2) Circulating dry absorber3) NID.

SO2 removalefficiency

Upto 99 per cent Upto 99 per cent (90~95 per cent forSDA)

Capital cost 1) Seawater FGD: ~40 lakhs/MW2) Freshwater FGD: ~50 lakhs/MW

~35 lakhs/MW

Sorbent 1) Seawater FGD: No sorbent2) Freshwater FGD: CaCO3

CaO/Ca(OH)2

Sorbent use Approximately 1.5~2 tonne limestoneconsumed per tonne SO2 removal

Approximately 0.75~1.5 tonne limeconsumed per tonne SO2 removal

Sorbent cost(Rs/tonne)

~2000 ~6000

Water consumptionin m3/MWh

0.2~0.25 m3/MWh for power plantsbetween 200~500MW;0.25~0.3 m3/MWh for power plantsbetween 50~200MW;0.3~0.45 m3/MWh for power plantsbetween 50~70MW

0.1~0.2 m3/MWh for power plants up to200MW.The semi dry system is not recommendedfor power plant > 200MW

Auxiliary powerconsumption

1) Seawater FGD: 0.7~1.5 per cent2) Freshwater FGD: 0.7 per cent

1~2 per cent

Condition ofexixting stack

Existing stacks to be modified in allcases

Existing stackes can be used withoutmodification

FGD by-product 1) Seawater FGD: No by-product2) Freshwater FGD: gypsum

CaSO3/CaSO4: Has to be landfilled

Waste water Generates Doesn't generateErection period Up to 50MW: 12~14months

50~200MW: 14~18months200~500MW: 18~24months>500MW: 24~30months

Up to 50MW: 12~14months50~200MW: 14~18months

Downtime Up to 50MW: 2~3weeks50~200MW: 3~4weeks200MW and above: 4~6weeks

4~6 months (due torenovation/modification in existing PMcontrol equipment such as bag filter/ESP)

Source: NTPC *Assuming sulphur content 0.5 percent in coal and stoichiometric consumption of sorbents.

9.4.2 NOx排出基準に準拠する為の課題 SO2排出基準同様に2015年12月以前はNOxの排出に関る国家基準は存在していなかった。殆どの

発電設備がNOx排出量をモニターしていたものの、SCRやSNCR等の脱硝設備を有してはいなか

った。新排出基準の発表以前より各発電所は国家公害防止員会（State Pollution Control Board, SPCBs）によって発行された環境許可（Environmental Clearance, EC）、建設許可（Consent to Establish, CTEs）等に基づきNOxの低減を実施していた。NOx排出量はプロセスおよび設備

の改修（バーナーにおける空気の多段化、燃料の多段化、煙道ガスの再循環等）または排出口に

おける除去（SCR,およびSNCR）および抑制技術の採用（低NOxバーナー等）により低減可能で

ある。NTPC、中央電力規制庁 (Central Electricity Regulatory Authority, CERC)、CEA等のス

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant テークホルダーはインドの火力発電所は脱硝技術の導入、燃焼システムの変更等の大規模な投資

無しには新排出基準への準拠が困難であると考えている。脱硝技術の導入に関しては、脱硫技術

の導入で課題としてあげた設備導入スペースの不足、ファイナンスの制約に加え、技術的な課題

も残っている。設備導入スペースの不足脱硫技術に比べ、脱硝技術は巨大なスペースを必要とはしない。しかし、既存の火力発電設備に

脱硝設備を導入するには燃料や空気を通す配管のレイアウト、排ガスを通すダクトのレイアウト

等、プラントのレイアウト変更が必要となる。脱硝設備は高温での運転が必要であるため、エコ

ノマイザーと空気予熱機の間に設置されることが通常であるが、スペースの制約が多いため、脱

硝設備を既設の発電設備に導入することは容易ではない。建設中の火力発電設備についても配管

やダクトレイアウトの変更が必要な可能性があるが対応は既設の発電所よりは容易と思われる。ファイナンスの制約 NTPC、CEA、CERC等は脱硝技術に必要な資本コストを1MW当たり2万USD程度と見積もって

おり、500MWの発電設備では操業費は年間で370-440万USD程度増加すると試算している。これ

らのコストが各発電所の財務状況に与える影響は大きく、各発電所が電力販売契約（PPA）等の

既存契約の改訂を求める可能性もある。また残余寿命が短い発電設備に関しては脱硝設備関連の

投資が妥当かどうか商業的に見極める必要がある。技術的な課題 SCRおよび低NOxバーナー技術がNOx排出量をコントロールする最も一般的な方法ではあるが、

これらの技術はインド産の石炭を原料とした火力発電所での実証試験は全くと言っていいほど行

われていない。何らかの理由で海外から導入された脱硝技術が期待通りの成果を出さない場合は

深刻な技術的問題となり、NOxの排出基準遵守が大きく遅れる可能性がある。

9.4.3 規制遵守のための課題の重要度 MoEF&CCにより発行された新排出基準は既にキャッシュフローや、設備スペース不足、設備の

残余寿命の短さ等で困っている発電事業者（特に州政府運営）にとって大きな課題である。 SOx排出基準への対応に向けた課題の重要度についてまとめたマトリクスを表 9-11に示す。各欄

の色はそれぞれ、赤色は深刻度合が高い、黄色は深刻度合が中程度、緑色は深刻度合が低いこと

を表す。設備容量が500MW以上の発電所の多くはFGD導入の為のスペースを有しているが、既

設の500MW以下の発電設備では設備導入スペースの余裕を有していないことが課題となる。ファ

イナンス上の課題は、既設発電所では規模によらず課題となる。また、設備製造能力の不足も大

きな課題となる。 NOx排出基準への対応に向けた課題の重要度についてまとめたマトリクスを表 9-12に示す。SOx排出基準と同様に、既設の発電所では設備導入スペースの余裕を有していないことやファイナン

ス上の課題が挙げられる。導入実績や実証実績が無いことなどの技術的な課題も重要である。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 表 9-11 SOx排出基準遵守に向けた課題の重要度

Capacity(MW)

Installedbefore2003

Installedafter 2003to 2016

Underconstruction

Units to beinstalledpost 2017

< 500≥ 500< 500≥ 500< 500≥ 500< 500≥ 500< 500≥ 500

Space

Financial

Technology

Supply of Equipmentand material

Capacity Building

表 9-12 NOx排出基準遵守に向けた課題の重要度

Installedbefore2003


Underconstruction


Space

Financial

Technology


Capacity Building

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9.5 環境規制対応動向の最新状況と経緯 9.3.3章に関連して、以下の関係機関との打合せを通じ環境規制対応の最新状況を確認した。本章で

はその結果を述べる。政策側：インド中央電力庁（CEA、2018年2月13日）発電側：NTPC（2018年2月14日）電力コンサル：STEAG Energy Service India Ltd.（2018年2月14日）環境シンクタンク：Centre for Science and Environment (CSE、2018年2月14日)

9.5.1 最新状況のヒアリング結果環境規制対応期限規制への対応については、既存のプラントのうち2003年以降にCODとなったプラントは2015年12月7日の新規制成立から2年後の2017年末まで（2018年1月、と言う表現）との期限が設定されてい

た。しかしながら、設備設置のための基本的な調査検討および入札等手続、関連事業者の量的対応

能力に鑑みこの期限を遵守するのは困難である、との議論は規制成立前からあり、この間の政府機

関間の議論は対応の必要性は所与のものと捉えながら期限を中心に展開されてきた。 MoP/CEA-MoEF&CCとの交渉経緯 2016/9 MoPはCEA長官の下に規制対応行動計画策定とそのための委員会設置を指示。CEAは段階

的な規制対応計画（Phasing Plan）策定を進めてきた。2017/5 取り組み状況を懸念した

MoEF&CCがCEA、NTPC、中央汚染管理局（CPCB）を招集。2017/6 MoPよりMoEF&CCあ

て、規制対応に関し、現状設定されている期限での対応を困難にしている諸課題について申し立て

る親書が送られた。そこで示されている主要な諸課題は以下のとおり。・要対応既存プラントでのESP追加／新規設置にあたり4-6カ月は機器停止となることによる供

給への影響懸念。・SOx対応については、基本設計から入札、施工までに要する期間が不足。また施工に伴う機器

停止の影響、事業者の供給能力に加え計画済の新設プラントの計画変更のため供給計画に支

障を来すおそれがある。・NOxに関しては、SNCRまたはSCRの設置が必要と見込まれるが、世界的に確立されている

技術とは言えインドにおいては実証されていない。このためさらに猶予が必要であるとし、

2024年までに146GWのSCR/SNCR対策を実施する案を提示。・この他、3,205MWは対応済との申告があるが、規制当局による確認が必要である、とし諸制

約によりFGD設置が困難な16,789MWについては、検討の結果再生可能エネルギー導入に当

たっての調整弁として当面必要なため、所定の年限に停止するまでFGDなしでの運転を認め

てもらいたい、とした。・また、2003年12月31日以前に運開したプラントについては600 mg/Nm3を達成するまで3年の

猶予を、その他のプラントについては3年の猶予期間を設け当該期間中は300 mg/Nm3 → 600 mg/Nm3、100 mg/Nm3 →300 mg/Nm3の規制値で運転を認めてもらいたい、とした。

・SPMに関しては、CEAが策定したPhasing Planに沿った期限を認めてもらいたい、とした。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 2017/9 MoEF&CCはMoPとの会議の場で、提案されている7年のFGD設置計画は長すぎる、と

し、全ての汚染物質について2018年から2022年の間に対策が実施されなければならない、とし

た。 2017/10 MoPより、ESP設置検討対象設備数273ユニット中231ユニット（64.5GW）について、

FGD設置検討対象設備数482ユニット中415ユニット（161.4GW）について、いずれも2022年を期

限として設置を進める旨の修正計画が提出された。 2017/10 CEAが、MoPに対し、関係電力会社と協議を行った結果に基づく懸案事項を報告するとと

もに、全発電所のユニットごとに環境設備設置予定／設置不可(スペース上の観点から)のリストを

提出した。その概要は次のとおり。・煙突の高さの規制緩和：FGD設置による腐食防止のため、煙突内部にライニングが必要とな

るが、既存の煙突にライニングを施すためには長期間の運転停止が求められる。これを避け効

率的に設置工事を進めるには、環境対策の効果も考慮した煙突高さの規制緩和が必要。ライニ

ングをした煙突を新たに建設することで運転停止を可能な限り短期間とできる。・新環境規制では水消費量の規制について、海水脱硫設備を伴う発電所と淡水脱硫（sweet

water based TPS）を伴う発電所とが区別されていない。海水脱硫設備の場合、当該規制内容

では事実上使えないことになる。海水脱硫は有効な選択肢であり、その利用のためにも水に関

する規制を改定する必要がある。・多くの電力会社が所管の規制委員会に環境設備設置に伴う料金改定を申請しているが、ペンデ

ィングとなっており承認には長期間を要する見通し。CERC/SERCにより料金改定が認められ

ないとFGDの資金源はない。MoPによる早急な対応を要望する。・同様に、全般に資金的根拠がないため策定されたPhasing Planの実施に支障を来す可能性が

ある。関係電力各社は、National Clean Energy Fund（NCEF）やPower Sector Development Fund(PSDF)による資金の投入を要望している。

・多数のFGD設置の同時進行が求められる中で、関係事業者の供給対応能力が懸念される。 2017/12 CPCBはMoEF&CCに対し、最終的に汚染源を問わず期限を2022年とする旨を報告。最高裁による審理手続前項の政府機関間の合意による実質的な期限延期について、現在関連団体により最高裁への申し立

てが行われ、審理が進められている。2018年2月14日には申し立て側による宣誓供述書

（affidavit）の提出が行われ、2018年3月7日にヒアリングが実施される。申し立て側の支援を行っ

ている研究機関CSEによると、今後電力会社に対しヒアリングが行われるとのことであるが、ヒア

リングがどのレベルおよび範囲で行われるのかは未詳である。

9.5.2 ヒアリング結果のまとめ客観的に見れば、環境設備設置の対応には2022年の期限でもかなり厳しいと思われるが、

MoEF&CCまでがMoP以下電力セクターに加担するのか、と言ったメディアの論調を見ていると、

最高裁での審理は比較的迅速に進められるのではないかと思われ、今後の動向を引き続き注視して

いく必要があると考える。

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10. 脱硫・脱硝システムの市場調査本章では、インドの最新の現地情報をもとにインド国内における脱硫脱硝システムの潜在需要を調

査、分析した結果を報告する。さらに、脱硫脱硝技術サプライヤーとその実績等の調査結果や、脱

硫剤製造の原料である消石灰や生石灰の市場情報についても報告する。

10.1 インドにおける脱硫・脱硝システムの市場調査結果インド国内における脱硫脱硝システムの市場調査結果の概要は以下のとおりである。 9章において報告したように、インドの火力発電所におけるSOx、NOxの排出基準がMoEF&CC により2015年12月に発行された（表 9-1および表 9-2を参照）。新排出基準の対象は遡及的であり、

新設・既設問わず、また稼働年に関わらず稼働中の全火力発電設備に新排出基準が課される。それ

ぞれの火力発電設備が新排出基準を遵守するための課題と対応難易度により、潜在需要は以下の

(a)~(c)までの3つのカテゴリーに分けることが可能である。 (a) 新設発電所約64 GW の設備容量：

計画中、設計中または建設中の発電所。3つのカテゴリー内では、新環境基準への対応難易度が

比較的低い。（10.1.1章を参照） (b) 既設発電所(環境装置が設置可能) 約 122 GWの設備容量：

既設発電所のうち、設備投資費用の確保や技術的課題に取り組めば、環境装置を導入可能な発

電所。（10.1.2章を参照） (c) 既設発電所(環境装置が設置不可能) 約 72 GW の設備容量：

設備設置スペースおよび設備投資費用が確保できない、または火力発電所の残余寿命が少ない

ため、新排出基準への対応が不可能な発電所。（10.1.2章を参照）インドにおけるFGDおよびSCRの潜在需要は、カテゴリー(c)を除いた、カテゴリー(a)および(b)の合計である186GWに達し、これは世界全体の需要の約13％にあたる。186GWの内、カテゴリー(a)の64GWは今後10年間で出現する見通しであり、カテゴリー(b)の122GWは既に存在する需要であ

る。潜在需要186GWの発電所全てにFGD、SCRが導入され、排出基準に準拠するには設備供給能

力の制限から10年以上の期間が必要であると考えられる。 CEAが2016年に発表した国家電力計画案によると、2027年以降の石炭火力発電の新設は計画され

ておらず、再生可能エネルギー発電、および原子力発電が石炭火力発電の代替になりつつある。し

かし、石炭資源が潤沢であることを考慮すると石炭火力発電所の新設が全く無いということは考え

にくく、石炭火力発電は今後も総発電量の大きな割合を占めると共に、ベースロード電源としての

役割を担うと考えられる。一方で、設備設置スペースおよび設備投資費用等の問題で新排出基準への対応が困難なカテゴリー

(c)の72GWの発電所についてもすぐに廃止するとは考えにくく、MoEF&CCによる72GWの発電所

廃止計画、もしくは新排出基準のさらなる猶予期間設定が今後発表される可能性も予想される。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 10.1.1 カテゴリー(a)：新設発電所への装置導入

脱硫および脱硝技術の潜在需要として、2021年までに稼働が予定されている、計画または建設中

の発電所およびそのFGD導入状況を表 10-1に示す。上述した通り、これらの合計容量は約64GWとなる。これらの発電所のほとんどが入札条件に、実績の多い湿式脱硫(石灰石膏法もしくは海水

法)を指定している。

表 10-1 計画中・建設中の発電所リストとFGD導入状況(2021年までに稼働予定のもの) S. No.

Name of the Plant Location Sector Owner No. of

units Capacity (MW) FGD Status

1 Barh STPP St-I Dist: Patna, Bihar Central NTPC 3x660 1980 Order not yet placed

2 Nabinagar TPP Aurangabad, Bihar Central NTPC 4x250 1000 Order not yet placed

3 Lara STPP Raigarh, Chhattisgarh Central NTPC 2x800 1600 Order not yet placed

4 North Karanpura STPP

Chatra, Jharkhand Central NTPC 3x660 1980 Order not yet placed

5 Kudgi STPP St-I Bijapur, Karnataka Central NTPC 3x800 2400 Order not yet placed

6 Solapur STPP Solapur,Maharashtra Central NTPC 2x660 1320 Order not yet placed

7 Gadarwara STPP, St–I

Narsinghpur Madhya Pradesh

Central NTPC 2x800 1600 Plant not yet completed

8 Khargone STPP Khargone,Madhya Pradesh Central NTPC 2x660 1320 Plant not yet

completed

9 Darlipalli STPPSt-I

Sundergarh, Odisha Central NTPC 2x800 1600 Order not yet placed

10 Telangana TPP (Ph-I)

Karim Nagar Telangana Central NTPC 2x800 1600 Order not yet placed

11 Meja STPP Allahabad, U.P. Central NTPC & UPRVUNL 2x660 1320 Plant not yet

commissioned

12 Tanda-II STPP, Ambedkar Nagar, U.P. Central NTPC 2x660 1320 Plant not yet

completed

13 Barsingsar TPP ext

Bikaner, Rajasthan Central NLC 1x250 250 Plant under

construction

14 Bithnok TPP Bikaner, Rajasthan Central NLC 1x250 250 Plant under

construction

15 Chhabra SCTPP Baran, Rajasthan State RRVUNL 2x660 1320 No data

16 Suratgarh Super Critical TPP

Ganga Nagar, Rajasthan State RRVUNL 2x660 1320 No data

17 Obra-C TPP Sonebhadra, U.P. State UPRVUNL 2x660 1320

Plant construction started. No data on FGD

18 Jawaharpur STPP Etah, U.P. State JVUNL 2x660 1320

Commissioning of units I & II are scheduled for 12.2020

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 19

Rayalaseema TPP St-IV

Cuddapah, Andhra Pradesh State M/s. APGENCO 1x600 600

To be commissioned in 2017. No data on FGD

20 Sri Damodaram Sanjeevaiah TPP St-II

Nellore, Andhra Pradesh State APPDCL 1x800 800 Boiler erection yet to

start

21 Dr. Narla Tata Rao TPP

Vijayawada, Andhra Pradesh State APGENCO 1x800 800 Construction under

way. No data on FGD

22 Kothagudem TPS –VII

Kammam, Telagana State TSGENCO 1x800 800


23 Bhadradri TPP Kammam, Telagana State TSGENCO 4x270 1080


24 Yelahanka Combined Cycle Power plant

Karnataka State 1x370 370 To be commissioned in 2017-18. No data on FGD

25 Ennore SEZ SCTPP Thiruvallur, TN State TANGEDCO 2x660 1320

To be commissioned in 2018-19. No data on FGD

26 Uppur SCTPP Ramnad, Tamil Nadu State TANGEDCO 2x800 1600 Under construction.

No data on FGD

27 Ennore SCTPP Thiruvallur, TN State TANGEDCO 1x660 660 To be commissioned in 2018. No data on FGD

28 TuiticorinTPP St-IV

Tuticorin, Tamil Nadu State SEPC Power

Pvt. Ltd 1x525 525 To be commissioned in 2019. No data on FGD

29 Malibrahmani TPP Angul, Odisha State M/s Monnet

Ispat 2x525 1050 Construction under way. No data on FG5

30 KVK Nilachal TPP, Ph-I Kandarei

5henkanal, Odisha State M/s KVK

Nilanchal Ltd. 3x350 1050

Unit 1 commissioned. No work is under progress presently. No data on FG5

31 Namrup Replacement Power Project

5ibrugarh, Assam State APGCL 1x98.4

0 98.4 To be commissioned. No data on FG5

32 PRAYAGRAJ TPP Bara, Allahabad Private

M/s Prayagraj Power Generation Co. Ltd.

3x660 1980 No data

33 Kashipur Gas Based CCPP, Ph-II

Udhamsingh Nagar, Uttarakhand

Private M/s Sravanthi Energy Private Limited

3x75 225 To be commissioned in 12/17. No data on FGD

34 BETA CCPP, Module-I


Private M/s BETA INFRATECH PRIVATE LTD.

3x75 225 To be commissioned in 12/17. No data on FGD

35 Uchpinda TPP Unit-1(Ph-I) Unit-2,3&4(Ph-II)

Janjgir Champa District, Chhattisgarh

Private R.K.M Power 4x360 1440

2 units commissioned, 2 units to be commissioned in

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2017 and 2018. No data on FGD

36

Lanco Amarkantak Mega TPS, Phase-II

Korba, Chhattisgarh Private M/s LAP Pvt.

Ltd. 2x660 1320 No data

37 Salora TPP Korba, Chhattisgarh Private M/s Vandana

Vidyut Ltd 2x135 270

First unit commissioned. 2nd unit uncertain. No data on FGD

38 Singhitarai TPP Janjgir Champa District, Chhattisgarh

Private M/s Athena Chhattisgarh Power Ltd

2x600 1200 To be commissioned in 2018. No data on FGD

39 Binjkote TPP Raigarh, Chhattisgarh Private SKS power Gen.

Ltd. 4x300 1200

2 units to be commissioned in 2017. 2 uncertain. No data on FGD

40 Nawapara TPP Raigarh, Chhattisgarh Private M/s TRN Energy

Pvt Ltd 2x300 600 No data on FGD

41 Mahan TPP Singrauli, MP Private Essar Power MP Ltd., 2x600 1200 No data on FGD

42 Gorgi TPP Singrauli, MP Private DB Power (MP) Ltd., 1x660 660 Construction started.

No data on FGD

43 Niwari TPP Narsinghpur, MP Private BLA Power Ltd. 1x45 45

Commissioning date uncertain. Work at site on hold. No data on FGD

44 Amravati TPP , Ph-II,

Amravati, Maharashtra Private

M/s RattanIndia Power Ltd

5x270 1350

Commissioning date uncertain. Work on hold. No data on FGD

45 Nasik TPP, Ph-I Nasik, Maharashtra Private

M/s RattanIndia Nasik Power Ltd.

5x270 1350

Unit 1 commissioned. Other units to be commissioned in 2017. No data on FGD

46 Nasik TPP , Ph-II Nasik, Maharashtra Private


5x270 1350 Work on hold. No data on FGD

47 Lanco Vidarbha TPP

Wardha, Maharashtra Private

M/s Lanco vidarbha Thermal Power Ltd.

2x660 1320 To be commissioned in 2019. No data on FGD

48 Bijora Ghanmukh TPP

Yavatmal, Maharashtra Private

M/s Jinbhuvish Power Generations Pvt. Ltd. (JPGPL)

2x300 600 UNCERTAIN. Work put on hold

49 Shirpur Power Dhule, Maharashtra Private Shirpur Power

Private Ltd. 2x150 300 To be commissioned in 2017. No data on FGD

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 50

Thamminapatnam TPP Ph-II

Nellore, Andhra Pradesh Private M/s Meenakshi

Energy Pvt.Ltd. 2X350 700 To be commissioned in 2017 and 2018. No data on FGD

51 Bhavanapadu TPP Ph-I

Srikakulam, Andhra Pradesh Private M/s East Coast

Energy Pvt. Ltd. 2x660 1320

To be commissioned in 2018-19. No data on FGD. Currently work on hold

52 Tuticorin TPP Tuticorin, Tamil Nadu Private Ind. Barath

Power Limited 1x660 660 To be commissioned in 2018. No data on FGD

53 Barauni Extn TPS Begusarai, Bihar Private BSPGCL 2x250 500

To be commissioned in 2017 and 2018. No data on FGD

54 Siriya TPP .anka, .ihar Private JAS INFRA 4x660 2640 Presently no work is in progress at site

55 Matri Shri UshaTPP

Latehar, Jharkhand

Private M/s Corporate Power Ltd. 4x270 1080

Construction under way. 5ate of commissioning uncertain. No data on FG5

56 Tori TPP Latehar, Jharkhand

Private Essar Power (Jharkhand) Ltd.

3x660 1980

Presently no work is in progress due to financial constraints

57 Ib Valley TPP Jharsaguda, Odisha

Private OPGC 2x660 1320

To be commissioned in 2018. FG5 Plant: Management approval for award of consultant for tender specification in progress

58 Ind .arath TPP Jharsaguda, Odisha

Private M/s Ind-.arath Energy (Utkal) Ltd.

2x350 700

Unit 1 commissioned. Unit 2 to be commissioned in 2017. No data on FG5

59 Lanco .abandh TPP

5henkanal, Odisha

Private M/s Lanco .abandh Power Ltd.

2x660 1320

To be commissioned in 2018 and 2019. No data on FG5

60 India Power (Haldia) TPP

East Medinipur, West .engal

Private India Power Corporation (Haldia) Ltd

3x150 450

Unit 1 commissioned. Other 2 units to be commissioned in 2018. No data on FG5.

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 10.1.2 カテゴリー(b)および(c)：既設発電所の改造

既設発電所のうち、カテゴリー(b)に分類した脱硫設備を設置可能な発電所の容量を地域別、部門

別に分類した分析結果を表 10-2に示す。既設発電所における脱硫装置の需要の48%はインド西部

に、次いで22%が北部に存在していることがわかる。部門別にみると、21%が国営、35%が州

営、44％は私営であり、国営発電所よりも、州営発電所や私営発電所の方が需要が大きいことが

わかる。

表 10-2 脱硫および脱硝設備を設置可能な地域別、部門別の発電容量（既設発電所） Region

No Capacity No Capacity No Capacity No Capacity Northern 10 4,690 40 11,775 20 10,940 70 27,405 Western 15 7,640 63 19,055 67 31,662 145 58,357 Southern 8 4,000 20 10,250 13 5,990 41 20,240 Eastern 20 9,660 4 1,220 15 5,790 39 16,670 Total 53 25,990 127 42,300 115 54,382 295 122,672

PrivateTotalSector (Capacity is in MW)

Central State

註：CEA 分析、国営および民営火力発電所の見解、独自の分析結果に基づく

表 10-2に基づき、既存火力発電所の全発電容量（カテゴリー(b)と(c)の合計）に占める潜在需要の

割合を表 10-3に示した。例えば、北部地域の国営発電部門では12,630 MWの設備容量のうち37%（4,690 MW）が潜在需要となる。本分析によると国営発電所よりも州営発電所の方が環境装置

設置の潜在需要は大きいことが分かる。

表 10-3 既設発電所全容量における地域別、部門別の潜在需要の割合 Region

Total Capacity

Market Potential in % of Total Capacity

Total Capacity


Total Capacity


Total Capacity


Northern 12,630 37 17,098 69 22,760 48 52,488 52 Western 14,317 53 22,280 86 33,385 95 69,982 83 Southern 13,425 30 17,832 57 12,124 49 43,381 47 Eastern 14,256 68 6,570 19 6,225 93 27,051 62 Total 54,628 48 63,780 66 74,494 73 192,902 64

Sector (Capacity is in MW) TotalCentral State Private

カテゴリー(c)に該当する72GWのうち36 GWは、スペースの制約があるが、設備稼働年数は20年以下の比較的新しい火力発電所である。これらの発電所に脱硫技術を導入するためには、省スペ

ースで排ガス処理可能な新技術の早期開発が求められる。36 GWもの発電設備を新環境基準に適

合するための排ガス処理技術を導入できないという理由で閉鎖することは、莫大な費用をかけた

インフラ設備を無駄にすることとなってしまう。既設発電所における脱硫設備の導入時期について、CEAはPhasing plan(表 9-6参照)を発表して

いるが、それらの潜在需要を地域別、部門別に分析をする。前提条件として、直近2年間に稼働開

始した火力発電所は脱硫および脱硝設備を設置するスペースを工場敷地内に有しており、2019年までに新環境基準に対応すると考えられる。2010~2015年に稼働した発電所は今後3年以内に設備

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 導入し、2020年までには新環境基準に対応すると推測した。一方、2010年以前に稼動した発電所

は設備設置のスペース不足およびファイナンスの制約などの課題から新環境基準への対応が困難

である。これら発電所は新技術の導入と新環境規制への適合にさらに時間を要すると考えられる

ため、2023年までの猶予期間が設けられると推測した。これらの前提条件に基づき、脱硫設備の潜在需要の年度別推移を図 10-1および表 10-4に示す。潜

在需要は2021年まで上昇し、大多数の発電所が新環境基準に対応すると予想される2023年にかけ

て減少することを示している。設備供給側にとっては、2021~2023年の間にピークに達する脱硫

設備の需要を獲得する準備を整えることが求められる。

図 10-1 脱硫装置の需要トレンド予測

表 10-4 脱硫・脱硝技術の潜在需要の年度別予測

Compliance Timeline Sector

Northern Region

Western Region

Southern Region

Eastern Region

# Capacity (MW) # Capacity

(MW) # Capacity (MW) # Capacity

(MW)

2019

Central 0 0 1 660 2 1,000 6 2,400 State 3 1,600 8 3,570 6 4,100 1 500

Private 9 5,160 16 8,180 7 4,280 3 1,200 TOTAL 12 6,760 25 12,410 15 9,380 10 4,100

2020

Central 7 3,480 8 4,480 5 2,500 9 4,760 State 10 3,550 12 5,610 8 4,310 0 0

Private 11 5,780 42 21,490 1 600 9 3,840 TOTAL 28 12,810 62 31,580 14 7,410 18 8,600

2023

Central 3 1,210 6 2,500 1 500 5 2,500 State 27 6,625 43 9,875 6 1,840 3 720

Private 0 0 9 1,992 5 1,110 3 750 TOTAL 30 7,835 58 14,367 12 3,450 11 3,970

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10.2 脱硫および脱硝設備に対する要求 NTPCなどの電力会社、もしくはBHEL (Bharat Heavy Electricals Limited)のような重電メーカ

ーは、発電所に新たな設備導入を計画する際には入札者を募るため、入札条件の公示が行われる。

入札条件の公示情報から電力会社や重電メーカーが脱硫および脱硝設備に求める仕様に関する情報

を収集した。脱硫設備に関してはNTPCによる入札公示情報から、脱硝設備に関してはBHELによ

る入札公示情報から得られた要求事項をそれぞれ10.2.1章、10.2.2章に述べる。

10.2.1 脱硫設備に関する要求事項 NTPCは発電設備からのSOx排出量を過去3-4年計測しているが、その計測データは外部には公開さ

れていない。NTPCの分析によるとインド産の石炭は0.3-0.5 %の硫黄を含んでおり、石炭に含まれ

る硫黄0.1％当たり200 mg/Nm3のSOx が発生すると簡易試算によると、SOx排出量は600-1000 mg/Nm3と推測される。 Telangana Super Thermal Power Project Phase-Iにおける2x800 MWの発電設備用の脱硫設備へ

の要求事項を以下に示す。 1) 石灰石膏プロセスの実績のある設備製造者(QFGDM) 排ガス処理能力 2,300,000 Nm3/hr以上、脱硫効率90%以上 2) QFGDMと技術移転協定を締結している石灰石膏プロセスの設備製造者排ガス処理能力600,000 Nm3/hr以上、脱硫効率85%以上なお、Telangana Super Thermal Power plantは現在建設中であり、ボイラーはBHELにより建設

中、タービンはAlstom Bharat Forge Ltd製を使用することが決定している。 2017年7月に公示されたKhargone Super Thermal Power Plant（Madhya Pradesh 州）における

1,320MW（660MW x 2）の発電設備用の脱硫設備への入札では、業務範囲として「設計、エンジ

ニアリング、製造、工場製作、仮組立、工場での形式試験、設備の梱包/移送/荷卸し/ハンドリング/現場での保全、設備稼働を含めた完全な建設サービス、建設監督、仮試運転、製造場所での試運転

と性能試験、石灰石のハンドリング/貯蔵/粉砕、石膏のハンドリング/貯蔵、短い湿式煙突やそれら

に付随する補助電源/制御/計装/土木/構造物/建築物の副資材のハンドリング、貯蔵」が含まれてお

り、要求事項は以下に示す通りである。なお、本設備はL&T Ltd.により現在建設中である。 1) QFGDMである場合排ガス処理能力2,000,000 Nm3/hr以上、脱硫効率90%以上 2) QFGDM以外排ガス処理能力600,000 Nm3/hr以上、脱硫効率85%以上 NTPCはJharkhand州Chatra のNorth Karanpura Thermal Power Station (3x660 MW) に関して

も同様の入札を公示している。また、NTPCは直近で以下の発電設備に関する正式な入札の公示を

行った。これらの入札要求事項はTelangana Super Thermal Power Project Phase-I (2x800 MW)と同様である。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant - Mouda STPP, Stage-II (2X660 MW)

- Kudgi STPP, Stage-I (3X800 MW) - Solapur STPP (2X660 MW) - Lara STPP, Stage-I (2X800 MW) - Nabinagar Thermal Power Project (4X250 MW), BRBCL - Meja Thermal Power Project (2X660 MW) - Barh STPP, Stage-I (3X660 MW) - Gadarwara STPP, Stage-I (2X800 MW) - Darlipalli STPP, Stage-I (2X800 MW) - Tanda STPP, Stage-II (2X660 MW) - Nabinagar STPP (3X660 MW), NPGCPL - Muzaffarpur Thermal Power Project, Stage-II (2X195 MW), KBUNL - Feroze Gandhi Unchahar Thermal Power Project, Stage-IV (1X500 MW) - Mauda STPP, Stage-I (2X500 MW) - Barh STPP, Stage-II (2X660 MW) - Rihand STPP, Stage-II (2X500 MW) & Stage-III (2X500 MW) - Vindhyachal STPP, Stage-III (2X500 MW) & Stage-IV (2X500 MW)

10.2.2 脱硝設備に関する要求事項 BHELにより公示された入札情報によると、脱硝設備に対する要求事項は以下の通りである。 250MWの発電容量または蒸気容量が810 ton/hr以上の発電設備向けには、脱硝効率75%以上無水アンモニアのハンドリングや貯蔵に係る設備は既存設備と同じ仕様とすること無交換で16,000時間以上の稼働実績を有すること（脱硝設備、脱硝触媒ともに）設計寿命は25年 SO2のSO3への酸化反応を最小限に抑えること硫酸アンモニウム生成の防止触媒の運用計画、定期保証を可能とするモジュール構造- 実際の入札案件の事例として、BHELのPatratu発電所(3x800 MW)での要求事項を以下に示す。 1) 実績を有する脱硝設備製造・供給者

500MWの発電容量または1,500 ton/hrの蒸気容量を有する発電設備に対して、脱硝効率75%以

上の設備設計、導入の実績がある。 2) SCRの主要機器に関する選定基準を有する

- アンモニアのハンドリング、貯蔵設備：500MW以上の発電容量または1,500 ton/hrの蒸気

容量を有する発電設備向けに1年以上稼働実績のあるのアンモニアのハンドリング、貯蔵設

備の設計・導入の実績があること。 - SCR触媒： 500MW以上の発電容量または1,500 ton/hrの蒸気容量を有する発電設備向けに

供給実績のある触媒製造者から供給されること。加えて、無交換で16,000時間以上の稼働

実績を有する触媒であること。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant - SNCRシステム： 500MW以上の発電容量または1,500 ton/hrの蒸気容量を有する発電設備

への設計・導入の実績があること。加えて、導入設備に1年以上の稼働実績があること。

10.3 インドにおける脱硫脱硝技術サプライヤーと実績 BHELおよびNTPCの入札公開情報から脱硫および脱硝技術の供給業者情報を確認し、入札に参加

実績のある供給業者を表 10-5に示す。またNTPCやBHELによれば、脱硝装置に導入する触媒のサ

プライヤーとしては以下の9社が関心を示している。 NANO, Korea IBIDEN Co. Ltd., Japan Yara International, Norway Johnson Matthey, USA Mitsubishi Hitachi Power Systems, Japan Cormetech Inc, DRPley , Germany Haldor Topsoe , Denmark JGC Catalyst & Chemical, Japan

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 表 10-5 脱硫および脱硝技術の供給業者

S. No.Name of theCompany

FirmLocation/Headquarters

Manufacturing in India orimported and supplied inIndia

Firm Turnover(2016)

Past Clients in(Already runningsystems)

TechnologyUsed such asSCR/SNCR

TechnologyEfficiency (%Removal)

-Riikinvoima Oy,Finland-Energoinstal S.A. /SEJ S.A., Poland- MSE MjölbySvartadalen EnergiAB, Sweden

2 ERC EmissionReduction Concepte

Germany Exclusively in Germany NA (Privatecompany)

NA SCR, SNCRand ERC-plusprocess

- Jingfeng Power Plant,Beijing- Yixing Power Plant,Jiangsu, China- Dairen Chemical,Jiangsu, China

4 Wuhan KaidiElectric PowerEnvironmental Co.,Ltd

China

- Most of the pastprojects in China. Noproject in India- eg. Datang BinchangPower Plant 2x600MW denitrificationproject EPC

FGD (Limestone /Seawater} 90%;FGD (Dry/ Semi Dry)60%-85%;SCR System 90%

7 Ducon Technologies India Amalgamation with DuconInfratechnologies Limited

INR 4082.49 lacs WienerbergerKarnataka

FGD 99%

8 Alstom India (HQ: France) EUR 6.9 Bn National ThermalPower Corporation

FGD and SCR FGD 98%;

SCR 95%

9 Chanderpur WorksPvt. Ltd

India USD 30 Million JSW Cement, HyundaiHeavy Industry, NCC

FGD

10 Thermax India Manufacturing in India Rs. 4287 Cr. WetScrubbers,FGD, SNCR

FGD <15ppm

11 Ljungström AdvX™Technology/ARVOSGroup

India Wet FGD,SCR

99.80%

12 Siemens India INR 7,948 Cr. FGD and SCR

>=80% (<90mg/Nm3)

6 Indure India Alliance with RAFAKO S.A,Poland

INR 1650 Cr FGD and SCR

5 CHINA DATANGTECHNOLOGY &ENGINEERING CO.,LTD.

China Manufacturing of catalystusing foreign technologies

Registered CapitalUSD 2.9 Billion

<= 100 mg/Nm3

3 LP Amina USA and China Manufacturing in USA andChina only

NA SCR andSNCR andLow-NOxburners

>80%

1 Andritz Energy andEnvironment

Austria No manufacturing in Indiaof air quality managementsystems. However, Andritzitself will provide the main(SCR) equipment

MEUR 6,039.0(sales of the Andritzgroup)

FGD and SCR

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant NTPCは2016年10月に脱硝技術(SCRもしくはSNCR)に関する実証を自社発電所で実施するプロジ

ェクトの関心表明を行っている。このプロジェクトの入札には合計10社の業者が応札しており、

NTPCは9つの脱硝技術プロジェクトを進行・計画している。約2%の排ガスを発電所システムから

実証試験用に抜き出し入札参加業者に供給し、実証試験用装置は入札参加業者の費用負担にて設置

する。NTPCにより開示されているこれら各プロジェクト内容および業者リストを表 10-6に示す。

業者リストは直接の供給者、EPCコントラクターおよび主要機器メーカーが名を連ねる。

表 10-6 NTPCの脱硝技術実証プロジェクトへの参加業者 S.N.

Name of Company SCR/SNCR Test Allocated NTPC Plant

1. BHEL 2 Nos. SCR Test Simhadri Unit No. 1 2. GE-Alstom India Limited 1 No. SCR and 1 No SNCR Vindhyachal unit No 13 3. L&T-MHPS Boiler Private

Limited (LMB) & MHPS 1 No SCR Sipat Unit No 4

4. Termokimik Itlay with Indure 1 No SCR Singrauli Unit no 6/7 5 Shanghai 1 No SCR Talcher Unit No 6 6 Andritz 1 No SCR Korba Unit No 7 7. ERC 1 No SNCR Korba Unit No. 7 8. Yara Norway 1 No. SCR and 1 No SNCR Rihand Unit No 4 9. Thermax Ltd 1 No SCR Ramagundam Unit No 7 10. Doosan 1 Nos. SCR Kahalgon Unit no 6.

10.4 インドにおける乾式脱硫剤原料(消石灰、生石灰)の性状と市場乾式脱硫技術に用いる脱硫剤の原料である消石灰および生石灰のインドにおける性状と市場を調査

した。図 10-2に石灰石の鉱山の分布を示す。主要産地はインド北西部のRajasthan州のJodhpur周辺、もしくはインド南部から東部にかけて延びる地域に存在していることがわかる。石灰石の用途

はセメント、ガラス、セラミックス、建設用に使われ、カルシウム含有量は45~52%と比較的良質

である。また、高品質な生石灰に関しては、オマーン、UAEのRas al Khaimah等から輸入してい

る実績があり輸入量は年間600万トンを超える。これらの生灰石はカルシウムの含量が55%を超え

ており非常に高品質であり、製鉄用途に適している。

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Mahendragarh

Pali

Sirohi ChittaurgarhBanaskantha

RajkotBhavnagarJamnagar

Amreli

SatnaRewa

Katni

Palamau

SinghbhumSundargarh

Sambalpur

KoraputBalaghat

Adilabad

KarimnagarWarangalGulbarga

BagalkotBelgaum

Simoga

ChitradurgaTumkur

Guntur

Cuddapah

PalghatSalem

Peramblur

TiruchirapalliVirdhunagar

Tirunelveli

Rajasthan is the main source of lime stone.

Limestone Mines

図 10-2 インド内での石灰石鉱山の分布図

表 10-7に石灰石算出の主要地域であるRajasthan周辺の石灰石供給業者の供給量と情報をまとめ

る。Jodhpur地域の主要メーカーであるSigma Minerals社は自動垂直炉を有し、他方Tara Minerals 社はポット炉を有し品質の良い生石灰を製造している。600社もの小規模な生石灰製造

業者がJodhpur、Gotan、Khimsar地区周辺に存在しており、全てポット炉で生石灰を製造して

いる。焼成燃料として石油コークス、木材、石炭、木炭等が使用される。比較のためにJIS規格特号の生石灰および消石灰の仕様を表 10-8に示した。カルシウム純度の観

点で、JIS規格特号相当の原料が入手可能であることがわかる。

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TATA power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant 表 10-7 生石灰（CaO）と消石灰（Ca(OH)2）の供給会社

State Site Companyname Website

Capacity ofCalcium

Oxide(CaO)Spec

Capacity ofCalcium

HydroxideCa(OH)2

Spec

NagourMayur

InorganicsLtd.

http://www.mayurinorganics.com/about.htm 27,000MT/Y 10,000MT/Y

Jodhpur SigmaMinerals Ltd.

http://www.sigmaminerals.com/

Ca(OH)2 > 96%

JodhpurTara Minerals& Chemicals

Pvt. Ltd.

http://www.taraminerals.co.in/home/

CaO > 96% Ca(OH)2 > 96%

KimsarGaurikaMinerals

http://www.essemmetachem.com/limestone-

rajasthan.html24,000MT/Y CaO > 87% 24,000MT/Y Ca(OH)2 > 90%

Jaisalmer

RajasthanState Mines& Minerals

Ltd.

http://www.rsmm.com/profile.htm CaO > 95%

Rajasthan

表 10-8生石灰（CaO）と消石灰（Ca(OH)2）の品質 (JIS規格より抜粋) 種類等級 CaO含有量 % 生石灰 (CaO) 特号 93.0以上消石灰 (Ca(OH)2) 特号 72.5以上

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11. まとめ

本事業実施可能性調査の結果、インド国内には186 GW (全世界の需要の13%) に相当する巨大な脱

硫脱硝システムの市場があることが分かった。環境装置の設置は、環境装置供給メーカーの製造能

力の制限により段階的に進むものと考えられるが、2021年頃に需要のピークを迎えるものと予想さ

れる。この大きな需要に応えるべく、脱硫脱硝システム導入を推進していくことが望ましい。本事業実施可能性調査で提案を行ったシステムについて、集塵機はマルチサイクロンセパレーター

の導入は克服すべき課題が多く、従来通り電気集塵機の使用が相応しいとの結論に至った。脱硝シ

ステムについては、集塵機および乾式脱硫システム下流の煤塵濃度の低い煙道に配置してハニカム

式触媒を使用することにより、対抗する従来技術（プレート式触媒を煤塵濃度の高いボイラー出口

に配置) に比べて非常に競争力が高いことが確認された。一方、乾式脱硫システムについては、排

ガス温度が低い（排ガスの体積流量が小さく脱硫塔の基数が少ない）方が競争力がある。これに加

えて、脱硫剤製造装置を近隣の発電所で共有し、脱硫剤の製造は消石灰よりカルシウム単価が安い

生石灰を原料とするプロセスを工業化して導入することで、競合する湿式脱硫システム(石灰石膏

法) に対する競争力を生み出せることが分かった。今後は、インド国内での乾式脱硫システムの早期導入を図るべく、生石灰を原料とする脱硫剤製造

プロセスの工業化を急ぐとともに、乾式脱硫システムの競争力および優位性（水の消費量が少なく

排水を出さないなど）が存分に発揮される案件を見極めて導入推進を図って行く予定である。

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添付リスト添付-1. Basic Engineering Design Information (S-1222-001) 添付-2. Design Basis for Maithon Power Plant (S-1222-101) 添付-3. Design Basis for Jojobera Power Plant (S-1222-102) 添付-4. PFD for DeSOx unit - Case 1 (D-1223-101) 添付-5. PFD for DeSOx unit -Case 3 (D-1223-102) 添付-6. PFD for DeNOx unit -Case 3 (D-1223-301)

FORM 1005-1

JOB No. DOC. No. REV.

0-7745 S-1222-001 1

DATE 2017 11 02 SHEET 1 OF 16

PREP’D M. Hatayama

CHK’D H.Isobe

APP’D T. Kayukawa

REV. DATE PAGE DESCRIPTION PREP’D CHK’D APP’D

2017-06-21 All For Discussion (DRAFT) MH TK MM

2017-08-15 All First issue MH HI TK

1 2017-11-02 All For quotation MH HI TK

DIST’N CLIENT

H.OFFICE

FIELD

JGC

CP

Instrument

Electrical

Civil

Piping

Equipment

Process

T&I

PJ

FIELD

TATA Power Co., Ltd. Project specification

4

DeSOx & NOx System for Coal-fired Power Plant

A

0

BASIC ENGINEERING DESIGN INFORMATION

JOB No. DOC. No. REV. 0-7745 S-1222-001 1

SHEET 2 OF 16

FORM 1005-2 3


TATA Power Co., Ltd. DeSOx & NOx System for Coal-fired Power Plant

Contents 1. SCOPE ....................................................................................................................................................... 3 2. GENERAL ................................................................................................................................................. 3 3. COMMUNICATION CHANNEL LIST OF CONTACT .......................................................................... 3 4. UNITS OF MEASURE .............................................................................................................................. 4 5. CLIMATIC DATA .................................................................................................................................... 5 6. UTILITY CONDITIONS AT B/L ............................................................................................................. 6

6.1 Steam and Condensate .......................................................................................................................... 6 6.2 Water ..................................................................................................................................................... 6 6.3 Chemicals .............................................................................................................................................. 8 6.4 Air and Nitrogen ................................................................................................................................... 8 6.5 Electrical Power .................................................................................................................................... 9

7. NUMBERING SYSTEM ......................................................................................................................... 10 7.1 Unit numbering ................................................................................................................................... 10 7.2 Equipment Numbering ........................................................................................................................ 10 7.3 Instrument Numbering ........................................................................................................................ 11 7.4 Line Numbering .................................................................................................................................. 12

8. PROCESS DESIGN PHILOSOPHY & INFORMATION ...................................................................... 13 8.1 Design Margin ..................................................................................................................................... 13 8.2 Design Pressure ................................................................................................................................... 13 8.3 Design Temperature ............................................................................................................................ 13 8.4 Standard Corrosion allowance ............................................................................................................ 14 8.5 Critical Service Rotary Machinery ...................................................................................................... 14

9. EQUIPMENT DESIGN PHILOSOPHY & INFORMATION ................................................................ 15 9.1 Vessels ................................................................................................................................................ 15 9.2 Pumps .................................................................................................................................................. 16 9.3 Induced Draft Fan ............................................................................................................................... 16

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1. SCOPE

This document firstly covers general information of the project such as client, plant location, communication channel, and secondly covers design basis information such as units of measure, utility conditions, numbering system. JGC basically proceeds with the basic design work based on information listed by this document.

2. GENERAL

Client: TATA Power Company Ltd. Project name: DeSOx & NOx System for Coal-fired Power Plant Plant location: Jojobera Power Plant Unit 5, Jharkhand, India Type and capacity of the plant: Flue Gas DeSOx & NOx

(457,999 Nm3/hr of flow rate for commercial unit) (5,000 Nm3/hr of flow rate for demonstration plant)

3. COMMUNICATION CHANNEL LIST OF CONTACT

(1) Client: TATA Power Company Ltd. (2) Consortium Leads: JGC Corporation

Attention: Mr. Tomoki Kayukawa, Project Manager, Technology Innovation Center ([email protected])

Address: 2-3-1, Minato Mirai, Nishiku, Yokohama City 220-6001, Japan Phone: +81-45-682-8371

(3) Consortium Member: JGC C&C

Attention: Mr. Jin Abe, Assistant Manager, Business Planning Group, Sales Division ([email protected])

Address: Solid Square East Tower 16F, 580 Horikawa-cho, Saiwai-ku, Kawasaki city, Kanagawa Pref. 212-0013, Japan

Phone: +81-44-556-9158 Consortium Member: Sojitz Attention: Mr. Kentaro Hiiragi, Manager Section 3, Advanced Materials Dept.

Chemicals Division ([email protected])

Address: 1-1, Uchisaiwaicho 2-chome, Chiyoda-ku, Tokyo 100-8691, Japan Phone: +81-3-6871-2775 Consortium Member: JCOAL Attention: Mr. Masahiro Ozawa, Deputy Director, Power Generation & Infrastructure

Development Group, Business Development Department ([email protected])

Address: 3F Daiwa Nishi-shimbashi Building, 3-2-1 Nishi-shimbashi, Minato-ku, Tokyo 105-0003 Japan

Phone: +81-3-6402-6104

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4. UNITS OF MEASURE

SI is used on this project. Specific units of measure are listed below.

The normalized conditions for gas measurement are:

Normal : 101.3 kPa, 0 °C (Nm3/h)

SI (New Metric) Temperature °C Pressure MPa, kPa Vacuum kPa Weight kg, ton Volume m3 Flow of Process fluid Liquid - Mass flow kg/h, ton/h - Volume flow m3/h Gas - Mass flow kg/h - Volume flow m3/h, Nm3/h - Mole flow kmol/h Flow of steam kg/h Enthalpy kJ/kg Heat duty kW, kcal/h Power kW, MW Transfer rate W/(m2.°C) Fouling resistance m2.°C/W Viscosity mPa.s, cP Equipment size mm Pipe length m Pipe diameter mm Vessel nozzle sizes mm

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5. CLIMATIC DATA

These data may not be required for BDP preparation. They may be indicated if needed.

● Maximum temperature:

● Design maximum ambient temperature:

● Minimum temperature:

● Winterizing temperature:

● Design minimum temperature:

● Relative humidity - Average:

- Maximum:

● Dry bulb temperature:

● Barometric pressure - Minimum:

- Maximum:

- Average:

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6. UTILITY CONDITIONS AT B/L

Except otherwise specified, all the following conditions are at the battery of the owner plant.

The pressure of the B/L is on the basis of ground elevation at the owner’s B/L.

6.1 Steam and Condensate

Low pressure steam Pressure(MPa) Temperature(°C)

Normal: 0.35 150

Mechanical design: 0.7/FV 180

Fouling factor: 0.0001(m2.°C/W)

Steam condensate

Condensate from Low pressure steam system will discharge to Demineralized water system for recovering.

6.2 Water

Industrial water Pressure(MPa) Temperature(°C)

Normal: 0.4 Ambient

Mechanical design: 0.8 80

pH(25°C): 6.5-8.5

Industrial water quality

pH(25°C): 6.5-7.5

Conductivity(H conductivity at 25℃): ≤0.3(μS/cm)

Hardness: ~0(μmol/L)

SiO2: ≤20(μg/L)

Fe: ≤30(μg/L)

Cu: ≤5(μg/L)

Cooling water - Supply Pressure(MPa) Temperature(℃)

Normal: 0.4 30

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Cooling water - Return Pressure(MPa) Temperature(℃)

Normal: 0.25 40


Cooling water quality

Turbidity: ≤ 20(NTU)

pH: 6.8-9.5

Alkalinity methyl orange as CaCO3: ≤ 1100(mg/L)

(Calcium carbonate saturation index): LSI ≥ 3.3

Ca2+ Hardness: ≤ 200(mg/L)

(Temperature of water side of heat transfer surface):

≥ 70°C

Total Fe: ≤ 1.0(mg/L)

Cu2+: ≤ 0.1(mg/L)

Cl-: ≤ 700(mg/L)

SO42- +Cl-: ≤ 2500(mg/L)

Silica as SiO2: ≤ 175(mg/L)

Mg2+×SiO2 as CaCO3: ≤ 50000(mg/L) pH≤ 8.5

Free chlorine: ≤ 0.2～1.0 In CW return header

NH3-N: ≤ 10(mg/L)

Oil: ≤ 5(mg/L)

CODcr: ≤ 100(mg/L)

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6.3 Chemicals

Ammonia Anhydrous ammonia liquid is supplied by cylinder at the local site.

6.4 Air and Nitrogen

Instrument air Pressure(MPa) Temperature(℃)

Normal: 0.6 Ambient


Instrument air specification

Dew point temperature: ≤ -40℃

Dust particle size: ≤ 3(μm)

Dust content: ≤ 1(mg/m3)

Oil content: oil free

Plant air Pressure(MPa) Temperature(℃)

Normal: 0.6 Ambient


Plant air specification



Nitrogen Pressure(MPa) Temperature(℃)

Normal: 0.7 Ambient


Nitrogen specification

Purity: ≥ 99.99

O2 content: ≤ 100(vppm)


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6.5 Electrical Power

Motor

Motor power range Voltage(V) Phase Frequency(Hz)

≥ 180 kW 10000 3 50

< 180 kW 380 3 50

Control Voltage(V) Phase Frequency(Hz)

220 1 50

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FORM 1005-2 3



7. NUMBERING SYSTEM

7.1 Unit numbering

Unit numbering is defined as following;

Unit name Unit number

Dust Collection 1

DeSOx 2

DeNOx 3

7.2 Equipment Numbering

Equipment shall be identified by a tag number as the following format: D-EFFA/B/C Where, D: Equipment code (see the equipment codes given below) EFFA/B/C: E is the unit No. of plant deficed as Chapter 7.1. FF is the sequence numbers for equipment, A/B/C is the code to denote identical equipment used for the same purpose.

Equipment codes

NO EQUIP. CODE

First letters for

1 C Columns: tray columns, packed columns etc.

2 E Unfired heat transfer equipment, heat exchangers, condensers, air cooled heat exchangers, reboilers, electric heaters

3 K Compressors, blowers, fans 4 M Mixers, stirrers, mixing nozzles, blenders, steam desuperheaters 5 P Pumps 6 R Reactors

7 S Gravity and mechanical separators, e. g. thickeners, cyclones, expellers, centrifuges, filters, dust collectors, sieves, helical separators

8 V Vessels including pressure storage vessels, silos and hoppers 9 Z Miscellaneous equipment, e.g. conveyor, blasters

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7.3 Instrument Numbering

Instruments shall be identified by a tag number as the following format: ABB-CCC Where, ABB: A is the first letter of instrument function code, BB is the succeeding letters with 2 (or 1) chatacters of instrument function code (see the functional identification letters given below)

CCC: Sequence numbers for instruments.

Functional identification letters

First letters Succeeding letters

Measured or initiating variable

Modifier Measured or initiating variable

Output function Modifier

A Analysis Alarm B Burner, Combustion C Control D Differential

E Voltage Sensor

(Primary element)

F Flow rate Ratio (Fraction)

G Gas Gauge,

Viewing device

H Hand High I Current (Electrical) Indicate J Power Scan

K Time, Time schedule Time rate of change

Control station

L Level Light Low

M Momentary Middle,

Intermediate N O Orifice, Restriction P Pressure, Vacuum Point (test) connection

Q Quantity Integrate, Totalize

Quantity

R Radiation Record S Speed, Frequency Safety Switch,Sequence T Temperature Transmit U Multivariable Logic Multifunction Multifunction Multifunction

V Vibration, Mechanical analysis

Valve, Damper, Louver

W Weight, Force Well X Event state or pressure X axis Unclassified Unclassified Unclassified

Y Compute in DCS Y axis Relay,Compute,

Convert

Z Position, Dimension Z axis Driver, Acutuater,

Unclassfide final control element

Functional identification letters are also referred to the legend sheets of P&ID

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7.4 Line Numbering

Lines shall be identified by a tag number as the following format: AA-BBB-CCC-DD-E-F

Where,

AA: Nominal pipe size in mm

BBB: Fluid code (see the fluid codes given below)

CCC: Sequence numbers for lines

DD: Piping material class

E: Insulation type F: Trace type.

Fluid codes (Process)

FLUID CODE Fluid name

FG Flue Gas

DS DeSOx Adsorbent

AW Ammonia Water

Fluid codes (Utility and common)


CWS Cooling water (supply)

CWR Cooling water (return)

IA Instrument air

IW Industrial water

LPS Low pressure steam

N2 Nitrogen

PA Plant air

SC Steam condensate Fluid codes are also referred to the legend sheets of P&ID.

Notes:

Numbering starts from 001.

The number changes after control valves and main equipment.

The number is different for the lines connected to equipment in parallel.

Each type of fluid has a separate numbering sequence.

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8. PROCESS DESIGN PHILOSOPHY & INFORMATION Design Electric equipment such as heater, pump and compressor is on the basis of the following regulation/code/standard.

8.1 Design Margin

Design margins of each equipment item are as follows :

(1) Pumps

Charge pumps Flow rate 10% %

(N/A) Req’d head 0% %

Product pumps Flow rate 10% %


Reflux pumps Flow rate 20% %


(2) Electric heater : Duty 10% %

8.2 Design Pressure

Positive Design Pressure shall be no less than the expected maximum operating pressure. If the

maximum pressure cannot be expected, it shall be

1.1 times the normal operating pressure (gauge pressure) or the normal operating pressure +

1.8 kg/cm2, whichever is bigger.

Electric part such as control panel and its components has the certificate of XXX Marking (India Certification) or the equivalent as CE Marking (Conformity European).

8.3 Design Temperature

Hot Design Temperature above 0C shall be no less than the expected maximum operating

temperature. If the maximum temp. cannot be expected, it shall be

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the normal operating temperature + 25C rounded to nearest 5C as standard.

Cold Design Temperature below 0C shall be no less than the expected minimum cold operating

temperature. If the minimum temperature cannot be expected, JGC will recommend and specify it.

8.4 Standard Corrosion allowance

(1) Standard corrosion allowance for internal surface of pressure vessel are :

for carbon steel, mm mm

for low alloy steel, mm mm

for stainless steel, mm mm

for non-ferrous material, mm mm

(2) Standard corrosion allowance for each side of vessel/reactor internal, such as coil, are :





8.5 Critical Service Rotary Machinery

JGC will specify critical service steam or power driven rotary machinery which must be maintained in

the event of power failure in order to protect personnel, equipment, or catalyst, and design them

accordingly.

JGC will consider the following equipment as critical service rotary machinery according to

Owner’s requirement, etc. : Later

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FORM 1005-2 3



9. EQUIPMENT DESIGN PHILOSOPHY & INFORMATION

9.1 Vessels

(1) Dimension indication

inside diameter & tangential lines’ distance

The equipment (columns, vessels & tubular heat exchangers*, etc.) nominal diameter (ID) should meet

Indian standard listed below as far as possible.

(2) Head shape

ASME 2:1 elliptical heads normally & hemispherical heads for high pressure vessels

by Licensor

(3) Size limitation for transportation of shop fabricated vessels N/A

Diameter limitation m

Length limitation m

(4) Connection on equipment

flanged

by Licensor

(5) Small nozzle installed directly on equipment

(a) Minimum connection size : 25 mm 20 mm

(b) Flange rating

same as the rating of the connecting part of equipment even for 25 mm or smaller

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FORM 1005-2 3



- Application of the above criteria a) & b) for tanks Yes No

for shell & tube exchangers Yes No

(6) Separate steam-out connection on vessel

is not required. Utilize drain connection etc. on associated piping of vessel.

be provided. Size : inch

(7) Manhole

(a) Minimum manhole size : 450 mm nominal diameter

9.2 Pumps

● 10% oversizing will be specified.

● Electrical motor drivers will be specified.

● Driver output will be specified minimum 110% to pump break horse power.

9.3 Induced Draft Fan



● Installation of induced draft fan will be unsheltered, outdoor.

FORM 1005-1


0-7745 S-1222-101 0

DATE Jul 21 2017 SHEET 1 OF 7


CHK’D T. Kayukawa

APP’D M. Morita


2017/7/21 All For Discussion (DRAFT) MH TK MM

2017/8/15 All Data provided by TATA Power MH HI TK

DIST’N CLIENT

H.OFFICE

FIELD

JGC

CP

Instrument

Electrical

Civil

Piping

Equipment

Process

T&I

PJ

FIELD



A

0

4

Design Basis for Feasibility Study of

DeSOx & DeNOx System at Maithon Power Plant

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FORM 1005-2 3


Maithon Power Ltd. DeSOx & NOx System for Coal-fired Power Plant

Contents

1. Introduction .......................................................................................................................................... 3

2. Plant Capacity for Commercial Plant ................................................................................................. 3

3. Specifications of Feedstock and Product ............................................................................................. 3

4. Catalyst Characteristics ...................................................................................................................... 3

Attachment-1 ............................................................................................................................................... 4

Attachment-2 ............................................................................................................................................... 7

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1. Introduction

JGC’s DeSOx & DeNOx system is the combination of the flue gas desulfurization (FGD) with dry

type adsorbent and the selective catalytic reduction (SCR) of NOx with honeycomb type catalyst.

In order to apply this system to high content of dust in flue gas, pretreatment with dust removal

unit is also combined to the system. This system can be applied for treatment of any kinds of flue

gas from industrial facilities, e.g. power plant, coke oven or cement kiln. The treated gas satisfies

environmental regulations.

This document presents fundamental information regarding the basis for the process design of

the DeSOx & DeNOx System in a commercial plant.

2. Plant Capacity for Commercial Plant

Capacity 525 MW subcritical,

Coal Consumption 293.48 T/hr, Indian Coal

Air Consumption 1,824.73 T/hr

Gas Flow Rate 2,342,569 Nm3/hr (at stack inlet)

Plant location Maithon, Dombhuin Village

Turn Down 60% (55% as per new regulation)~100%

DeNOx Catalyst Life 2 years

3. Specifications of Feedstock and Product

Attachement-1 defines the specifications of feedstock and product.

4. Catalyst Characteristics

Attachment-2 contains the information on the catalyst for DeNOx unit. An MSDS (Material

Safety Data Sheet) will be issued at the time of catalyst delivery.

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Attachment-1 Specifications of Feedstock and Product

A) Feedstock Specifications

A-1. Fuel (Coal)

The information of design coal is required to check flue gas composition for the study. The

following items are typical one, but not limited to them.

No. Particulars Units Design

1.0 PROXIMATE ANALYSIS By Weight

1.1 Moisture (Total) % 7.11

1.2 Ash % 36.19

1.3 Fixed Carbon % 40.78

1.4 Volatile Matter % 15.92

1.5 Total % 100

1.6 Gross Calorific Value kcal/kg 4671

2.0 ULTIMATE ANALYSIS

2.1 Carbon % 47.85

2.2 Hydrogen % 2.89

2.3 Sulphur % 0.39

2.4 Nitrogen % 1.00

2.5 Moisture % 7.11

2.6 Ash % 36.19

2.7 Oxygen (by difference) % 4.58

2.8 Total % 100

3.0 Hard Groove Index 50

4.0 Ash Fusion Range

4.1 Initial Deformation Temp. °C

4.2. Hemispherical Temp. °C

4.3 Fusion Temp. °C To be confirmed

A-2. Ash

The following information is based on the analytical results of an ash sample, named as “MPL

(Maithon Power Limited)”. “MPL” ash was selected as design case.


(MPL)

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5.0 Chemical Composition

5.1 Silica (SiO2) % 56.11

5.2 Alumina (Al2O3) % 29.96

5.3 Iron oxides (Fe2O3) % 6.00

5.4 Titania (TiO2) % 2.62

5.5 Potassium oxide (K2O) % 1.83

5.6 Lime (CaO) % 1.31

5.7 Phosphoric Anhydride (P2O5) 0.84

5.8 Magnesia (MgO) % 0.48

5.9 Sulphuric Anhydride (SO3) % 0.23

5.10 Sodium oxide (Na2O) % 0.11

5.11 Balance Alkalis (by difference) % 0.50

6.0 Particle Size Distribution

6.1 D10 μm 7.74

6.2 D50 μm 23.33

6.3 D90 μm 111.02

6.4 Detail distribution (Attach-1B)

7.0 Density

7.1 True density (Pycnometer) g/ml 2.25

7.2 Apparent density (close pore included) g/ml 0.64

A-3. Flue Gas (Maithon Power Plant)


8.0 Gas Condition

8.1 Location Outlet of

Economizer

Outlet of ESP

8.2 Total Gas Flow Rate

(wet)(TMCR)

kg/hr 2,050,000 2,200,000

8.3 T/h 2,050 2,200

8.4 Gas Temp. (TMCR) °C 322 114

8.5 Gas Pressure (TMCR) mmH2OG -60 -276

8.6 Gas viscosity cP Not available Not available

8.7 Gas density kg/Nm3 0.875 0.939

9.0 Flue Gas Composition

9.1 Oxygen vol %-wet

9.2 vol %-dry 3.56 8.7

9.3 H2O vol %-wet

9.4 CO2 vol %-dry 15.43 10.7

9.5 NOx kg/hr 2,062 1,119

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9.6 mg/Nm3-

dry

@6%O2

880 (100%TGMCR) 477.5

(100%TGMCR)

9.7 NO2 kg/hr 300 163

9.8 mg/Nm3-

dry

@6%O2

128 (assumed as

NO2 mol/NO mol =

1/9)

70 (assumed as NO2

mol/NO mol = 1/9)

9.9 SOX kg/hr 1,931 1,687

9.10 mg/Nm3-

dry

@6%O2

824 (Design Coal

TGMCR)

720 (Design Coal

TGMCR)

9.11 Dust kg/hr 117,129 84

9.12 mg/Nm3-

dry

@6%O2

50,000

(100%SGMCR)

35.85

(100%SGMCR)

B) Product Specification

B-1. Emissions Norm required for the Existing Plant

Permissive level: SO2 200 mg/Nm3 (for > 500MW), NOx 300 mg/Nm3, SPM 50 mg/Nm3

B-2. Treated Gas (Commercial Plant)

Treated gas shall satisfies specifications notified by Ministry of Environment, Forest and

Climate Change on 7th December, 2015.

No. Particulars Units Design Coal

12.0 Gas Condition

12.1 Location Outlet of SCR

12.2 Gas Pressure mmH2OG By Contractor

13.0 Treated Gas Composition

13.1 NOx mg/Nm3-dry

@ 6%O2

< 100

13.2 SOx mg/Nm3-dry

@ 6%O2

< 100

13.3 Dust mg/Nm3-dry

@ 6%O2

< 30

13.4 Leak Ammonia ppm < 5

JOB No. DOC. No. REV. 0-7745 S-1222-101 0

SHEET 7 OF 7

FORM 1005-2 3



Attachment-2 SCR Catalyst Characteristics Including Chemical and Physical Properties

A) Catalyst Name NRU-5

B) Manufacturer JGC Catalysts and Chemicals Ltd.

C) Application & Process SCR

D) Chemical Properties

Active component V2O5

Support carrier TiO2-WO3

E) Physical Properties

Form Honeycomb type, 35cell x 35 cell (typical)

Approx. bulk density 0.5 ton/m3

FORM 1005-1


0-7745 S-1222-102 1

DATE 2017 11 02 SHEET 1 OF 8


CHK’D H.Isobe

APP’D T.Kayukawa



2017-08-15 All Data provided by TATA Power MH HI TK


DIST’N CLIENT

H.OFFICE

FIELD

JGC

CP

Instrument

Electrical

Civil

Piping

Equipment

Process

T&I

PJ

FIELD



A

0

4

Design Basis for Basic Design of Demonstration Plant of

DeSOx & DeNOx System at Jojobera Power Plant

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 2 OF 8

FORM 1005-2 3



Contents

1. Introduction .......................................................................................................................................... 3

2. Plant Capacity for Commercial Plant (for Reference) ........................................................................ 3

3. Plant Capacity and Inlet Condition for Demonstration Unit ............................................................ 3



Attachment-1 ............................................................................................................................................... 4

Attachment-2 ............................................................................................................................................... 8

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 3 OF 8

FORM 1005-2 3



1. Introduction








the DeSOx & DeNOx System in a commercial plant and a demonstration unit.

2. Plant Capacity for Commercial Plant (for Reference)

Capacity 120 MW subcritical

Coal Consumption 70 T/hr, Indian Coal

Air Consumption 442 T/hr

Gas Flow Rate 457,999 Nm3/hr

Plant location Tata Power Co. Ltd, Jojobera Power Plant Unit 5, Jamshedpur.

Turn Down 100%


3. Plant Capacity and Inlet Condition for Demonstration Unit

Plant location Jojobera Power Plant Unit 5, Jharkhand, India


Gas composition SOx 800 mg/Nm3-dry@ 6%O2

NOx 600 mg/Nm3-dry@ 6%O2

Dust 100 g/Nm3-dry@ 6%O2

DeNOx Catalyst Life 1 year






JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 4 OF 8

FORM 1005-2 3





A-1. Fuel (Coal)




1.0 PROXIMATE ANALYSIS By Weight C7 July 2017


1.2 Ash % 39.40



1.5 Total % 100.0

1.6 Gross Calorific Value kcal/kg 4,281.77


2.1 Carbon % 49.30

2.2 Hydrogen % 3.32

2.3 Sulphur % 0.43

2.4 Nitrogen % 1.03

2.5 Moisture % 0.00

2.6 Ash % 41.37


2.8 Total % 100.0



4.1 Initial Deformation Temp. °C >1,332

4.2. Hemispherical Temp. °C >1,332

4.3 Fusion Temp. °C >1,332

A-2. Ash

The following information is based on the analytical results of 2 kinds of ash samples, named

as “Jojobera” and “MPL (Maithon Power Limited)”. “MPL” ash was selected as design case

since the particle size of “MPL” ash is smaller than that of “Jojobera”, and it should be safer to

design dust removal unit.

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 5 OF 8

FORM 1005-2 3



No. Particulars Units Reference

(Jojobera)

Design

(MPL)


5.1 Silica (SiO2) % 57.60 56.11

5.2 Alumina (Al2O3) % 28.80 29.96

5.3 Iron oxides (Fe2O3) % 5.87 6.00

5.4 Titania (TiO2) % 1.59 2.62

5.5 Potassium oxide (K2O) % 1.67 1.83

5.6 Lime (CaO) % 1.14 1.31

5.7 Phosphoric Anhydride (P2O5) 0.74 0.84

5.8 Magnesia (MgO) % 0.61 0.48

5.9 Sulphuric Anhydride (SO3) % 0.15 0.23

5.10 Sodium oxide (Na2O) % 1.30 0.11

5.11 Balance Alkalies (by difference) % 0.53 0.50


6.1 D10 μm 8.92 7.74

6.2 D50 μm 28.94 23.33

6.3 D90 μm 102.43 111.02

6.4 Detail distribution (Attach-1A) (Attach-1B)

7.0 Density



A-3. Flue Gas (Jojobera Power Plant Unit 5)


8.0 Gas Condition


Economizer

Outlet of

Air Heater

Outlet of

ESP

8.2 Total Gas Flow

Rate (wet)

kg/hr Not available Not available 600,610

8.3 Nm3/h Not available Not available 457,999

8.4 Gas Temp. °C 314/310 145/140 129/124

8.5 Gas Pressure mmwc -15.37 Not available -220/ -217

8.6 Gas viscosity cP Not available Not available Not available

8.7 Gas density kg/Nm3 Not available Not available 1.31


9.1 Oxygen vol %-

wet

4.1/4.5 6.47/6.6 4.61

9.2 vol %-dry 5.09

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 6 OF 8

FORM 1005-2 3



9.3 H2O vol %-

wet

9.32

9.4 CO2 vol %-

wet

14.5/14.6 11.5/12.6 13.06

9.5 NOx kg/hr 290

9.6 mg/Nm3-

dry

@6%O2

655

9.7 NO2 kg/hr 30

9.8 mg/Nm3-

dry

@6%O2

65

9.9 SOx kg/hr 540

9.10 mg/Nm3-

dry

@6%O2

1225

9.11 Dust kg/hr 45.8

9.12 g/Nm3-

dry

@6%O2

0.1



Permissive level: SO2 600 mg/Nm3, NOx 300 mg/Nm3, SPM 50 mg/Nm3

B-2. Treated Gas (Demonstration Unit)




14.0 Gas Condition

14.1 Location Outlet of Demonstration Unit

14.2 Gas Pressure mmH2OG -150

15.0 Treated Gas Composition (Note 1)

15.1 NOx mg/Nm3-dry

@ 6%O2

< 100

15.2 SOx mg/Nm3-dry

@ 6%O2

< 100

15.3 Dust mg/Nm3-dry < 30

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 7 OF 8

FORM 1005-2 3



@ 6%O2


Note1 : The treated gas composition shall be achieved for the inlet gas composition defined in

the Section 3.

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 8 OF 8

FORM 1005-2 3













F

E

D

C

B

A

8 7 6 5 4 3 2 1

F

E

D

C

B

A

8 7 6 5 4 3 2 1

S. Kameda

JOB CODE

NO. DATE DESCRIPTIONS APPDCHKDPREPD

REVISIONS

PREP’D CHK’D APP’D

DWG. NO.B

DATE： SCALE None

SIZE REV.

TATA Power Co., Ltd.Process Flow Diagram for DeSOx unit

Commercial Plant - Case 1

T. Kayukawa

0 7 7 4 5

H. Isobe

0

2017-10-XX

2017-10-XX0 For preliminary study S.K H.I T.K

02

D-1223-101

0 0 0 0

DRAFT

(NOTE1)

NOTE:

FROM ELECTROSTATIC PRECIPITATOR(EXISTING)

V-101A/BFRESH AGENT HOPPER

C-101A~FDeSOx TOWER

V-102A/BSPENT AGENT

HOPPERZ-103A/BFRESH AGENT CONVEYER

WC INV

B/LFLUE GAS

Z-102A/BFRESH AGENT WEIGH SCALE

WC INV

V-101B

Z-102A

Z-103A

Z-102B

Z-103B

Z-104A/BSPENT AGENT CONVEYER

Z-104A

Z-104B

V-102A

NOTE2

101

102A

102B

103B

103A104

NOTE2

1. MAXIMUM 10％ HEAT LOSS IS ASSUMED.

M

M

M

2. SPENT AGENT IS RECYCLED AS PART OFFRESH DESULFURIZING AGENT, OR SOLDTO CUSTOMER, OR DISPOSED FOR LANDFILL.

3. TYPICAL FOR EACH DeSOx TOWER.

C-101B

LSL

LSM

INV

MMMM

MMMM

C-101C

NO

TE 3C-101A

MM

M M

C-101D

LSL

LSM

INV

MMMM

MMMM

C-101F

NO

TE 3C-101E

MM

M M

V-102B

M

V-101A

TO STACK (EXISTING)

B/LTREATED FLUE GAS

101 102A/B 103A/B 104Flue gas fromexisting plant

DeSOx unitinlet gas

DeSOx unitoutlet gas

DeSOx unitoutlet gas (total)

Vapor Vapor Vapor Vapor℃ 145 145 130 130

KPaG -2.3 -2.3 -3.8 -3.8Nm3/h 230,000,000 115,000,000 115,000,000 230,000,000

SOx mg/Nm3 800 800 100 100NOx mg/Nm3 300 300 300 300

mg/Nm3 50 50 50 50

Stream No.

Fluid

Phase

Concentration

Dust

TemperaturePressureFlow rate

F

E

D

C

B

A

8 7 6 5 4 3 2 1

F

E

D

C

B

A

8 7 6 5 4 3 2 1

S. Kameda

JOB CODE


REVISIONS


DWG. NO.B

DATE： SCALE None

SIZE REV.



T. Kayukawa

0 7 7 4 5

H. Isobe

0

2017-10-XX


02

D-1223-102

0 0 0 0

DRAFT

(NOTE1)

NOTE:

TO DeNOx UNIT

FROM ECONOMIZER (EXISTING)

S-102A HMULTICYCLONE

FLUE GASD-1223-301

S-101A HINERTIA DUST

COLLECTOR


C-101A~HDeSOx TOWER

V-102A/BSPENT AGENT

HOPPER Z-103A/BFRESH AGENT CONVEYER

WC INV

B/LFLUE GAS


WC INV

V-102B

V-103DUST HOPPER

C-101B

V-101B

V-101A

Z-102A

Z-103A

Z-102B

Z-103B


Z-104A

Z-104B

Z-105DUST CONVEYOR

V-102A

NOTE2

M

S-101A HS-102A H

101

102A

102B

103B

103A 104

LSL

LSM

INV

LSL

LSM

INV

LAND FILL

V-103

Z-105

TO ATM AT SAFETY

LOCATION

M M M M M M M M

M MM MM MM M

NOTE2


MMMMMM

M MMMMM

MMMMMM

M MMMMM

M

M

M


C-101C C-101D

C-101F C-101G C-101H

M

NO

TE 3


NO

TE 3


DeSOx unitinlet gas




KPaG -0.2 -2.2 -3.7 -3.7Flow rate Nm3/h 230,000,000 115,000,000 115,000,000 230,000,000

SOx mg/Nm3 800 800 100 100NOx mg/Nm3 600 600 600 600

mg/Nm3 100,000 1,000 30 30

Stream No.

Fluid

Phase

Concentration

Dust

TemperaturePressure

S-103

S-103DUST FILTER

C-101A

MM

M M

MM

MM

C-101E

F

E

D

C

B

A

8 7 6 5 4 3 2 1

F

E

D

C

B

A

8 7 6 5 4 3 2 1

S. Kameda/M. Hatayama

JOB CODE


REVISIONS


DWG. NO.B

DATE： SCALE None

SIZE REV.

TATA Power Co., Ltd.Process Flow Diagram for DeNOx unit

(Commercial Plant Case-3)

T. Kayukawa

0 7 7 4 5

H. Isobe

0

2017-10-XX

2017-10-XX0 For preliminary study S.K/M.H H.I T.K

02

D-1223-301

0 0 0 0

DRAFT

FROM DeSOx UNIT

FLUE GAS

R-301

M

301

303

304

M-301

M-301FLUE GAS/NH3 MIXER

R-301SCR REACTOR

Z-302DUST BLASTER

D-1223-102

B/LTREATEDFLUE GAS

TO AIR HEATER

Z-301AMMONIA INJECTION PACKAGE

NOTE:

DUSTCOLLECTION

1. THE CONFIGURATION IS PRELIMINARY ANDSHALL BE UPDATED BASED ON VENDORINFORMATION DURING DETAIL ENGINEERING.

302

Z-301

PA

IW

ｖ v v v

FC

TO GRADE

NH3（VAPOR）

NH3（LIQUID）

BY VENDOR

BY CONTRACTOR

NOxSOxO2

AI

Z-302

NOTE1

E

TS

LS

301 302 303 304

Flue Gas_Main NH3 + Air SCR inlet gas SCR outlet gas


KPaG -3.7 15 -4.1 -6kmol/hr 102,679 3,197 105,876 105,887Nm3/h 2,300,000 71,612 2,371,612 2,371,876

SOx mg/Nm3 100 0 97 97NOx mg/Nm3 600 0 582 97

mg/Nm3 30 0 30 30

Concentration

Dust

Flow rate

Stream No.

Fluid

PhaseTemperature

Pressure

NOxSOxO2NH3

AI

Technical and Cost Comparison Report

on Dry-DeSOx and DeNOx System

for TATA power

March 2018

Agency for Natural Resources and Energy,

Ministry of Economy, Trade and Industry

JGC CORPORATION


0-7745 0

SHEET 2 OF 81

FORM 1005-2 3


TATA power Co., Ltd.


Contents

Part-I. Outline of Study

1. Executive Summary .......................................................................................................................... 4

2. Abbreviation ...................................................................................................................................... 4

3. Introduction ...................................................................................................................................... 5

3.1 Project Background .................................................................................................................... 5

3.2 Study Objectives ......................................................................................................................... 5

4. Design Basis ...................................................................................................................................... 5

Part-II. Technical and Economic Study

5. Technology ........................................................................................................................................ 6

5.1 Dry DeSOx Process .................................................................................................................... 6

5.2 DeNOx Process ........................................................................................................................... 8

6. Technical and Economic Study for Commercial Plant .................................................................... 9

6.1 Study Case .................................................................................................................................. 9

6.2 Basic Design Information for Case 1 ....................................................................................... 11 6.2.1 PFD ...................................................................................................................................... 11 6.2.2 Major Equipment ................................................................................................................. 11 6.2.3 Required Area ...................................................................................................................... 12 6.2.4 Effluent ................................................................................................................................ 13

6.3 Basic Design Information for Case 2 ....................................................................................... 13

6.4 Basic Design Information for Case3 ........................................................................................ 14 6.4.1 PFD ...................................................................................................................................... 14 6.4.2 Major Equipment ................................................................................................................. 14 6.4.3 Required Area ...................................................................................................................... 16 6.4.4 Effluent ................................................................................................................................ 17 6.4.5 Comparison of Dust Removal System................................................................................. 17

6.4.5.1 Comparison ................................................................................................................... 17 6.4.5.2 Short Summary ............................................................................................................ 20

6.5 Economic Study ........................................................................................................................ 20 6.5.1 Conditions ............................................................................................................................ 20 6.5.2 Economic Study for Case 1 .................................................................................................. 22 6.5.3 Economic Study for Case 3 .................................................................................................. 24

6.5.3.1 DeSOx System including Dust Removal System ........................................................ 24 6.5.3.2 DeNOx System ............................................................................................................. 26 6.5.3.3 Overall system (DeSOx system + DeNOx system)...................................................... 27

6.5.4 Short Summary ................................................................................................................... 30

7. Technical and Cost Information for Demonstration Plant ............................................................ 31

7.1 Basic Design Information ........................................................................................................ 31 7.1.1 BFD ...................................................................................................................................... 31 7.1.2 Tie-ins to / from the Existing Plant .................................................................................... 32 7.1.3 PDP ...................................................................................................................................... 32 7.1.4 Major Equipment ................................................................................................................. 33 7.1.5 Required Area ...................................................................................................................... 33 7.1.6 Consumption of Utility, Catalyst and Chemical ................................................................. 34


0-7745 0

SHEET 3 OF 81

FORM 1005-2 3



DeSOx & NOx System for Coal-fired Power Plant 7.1.7 Effluents ............................................................................................................................... 35 7.1.8 Detailed Engineering ........................................................................................................... 35

7.2 Schedule .................................................................................................................................... 36

8. Detail Information of DeNOx Catalyst .......................................................................................... 38

8.1 Analysis of Indian coal ash ...................................................................................................... 38

8.2 Influence of Catalyst Poisoning Components on Performance of DeNOx Catalyst .............. 41

8.3 Influence of Dust on Erosion of DeNOx Catalyst ................................................................... 42

8.4 Design information of DeNOx catalyst ................................................................................... 44

Part-III. Survey Results of New Environmental Norms

9. Outline of New Environmental Norms and Status ....................................................................... 46

9.1 Background of Energy Sector in India .................................................................................... 46

9.2 Outline of New Environmental Norms ................................................................................... 48

9.3 Present Status of TPPs and Corresponding Status to New Environmental Norms ............. 49 9.3.1 Coal Properties Survey ........................................................................................................ 49 9.3.2 Flue Gas Properties Survey ................................................................................................ 52 9.3.3 Corresponding Status for New Environmental Norms ...................................................... 53

9.3.3.1 Corresponding Status for New Environmental Norms .............................................. 54 9.3.3.2 Corresponding Status with Respective Items ............................................................. 54

9.4 Challenges in Complying with New Environmental Norms .................................................. 56 9.4.1 Challenges in Complying with SOx norms ......................................................................... 56 9.4.2 Challenges in Complying with NOx norms ........................................................................ 58 9.4.3 Challenge Level in Complying the New Environmental Norms ....................................... 59

9.5 Latest Situation of Interactions about New Environmental Norms ..................................... 61 9.5.1 Present situation for New Environmental Norms ............................................................. 61 9.5.2 Short Summary ................................................................................................................... 63

Part-IV. Survey Results of Market

10. Market Information ........................................................................................................................ 64

10.1 Market Survey of DeSOx and DeNOx system ........................................................................ 64 10.1.1 Category (a): Installation of DeSOx and DeNOx system to New TPPs ............................ 65 10.1.2 Category (b) and (c): Retrofit of Existing TPPs .................................................................. 70

10.2 Requirement for DeSOx and DeNOx system .......................................................................... 72 10.2.1 Requirement for DeSOx system .......................................................................................... 72 10.2.2 Requirement for DeNOx system ......................................................................................... 74

10.3 DeSOx and DeNOx Suppliers in India and Their Activities .................................................. 75

10.4 Properties and Market of Raw Materials for Dry Desulfurizing Agent ................................ 77

11. Conclusions and Recommendations ............................................................................................... 80

Part-V. Attachment

Attachment List ..................................................................................................................................... 81


0-7745 0

SHEET 4 OF 81

FORM 1005-2 3




1. Executive Summary

This document presents the results of a feasibility study and technical information regarding the

introduction of the dry DeSOx process and DeNOx process into coal-fired thermal power plants

owned by TATA Power Co., Ltd. in India. In addition, commercial and market information

associated with the dry DeSOx process and DeNOx process is included.

2. Abbreviation

The following abbreviations are used in this document:

A/H : Air Heater

BFD : Block Flow Diagram

CAPEX : Capital Expenditure

CAGR : Compound Annual Growth Rate

CEA : Central Electricity Authority

CF : Capacity Factor

CFD : Computation Fluid Dynamics

COP : Conference of the Parties

DeSOx : Desulfurization

DeNOx : Denitrification

ECO : Economizer

ESP : Electrostatic Precipitator

FGD : Flue Gas Desulfurization

GCV : Gross Calorific Value

GGH : Gas/Gas Heat Exchanger

INDC : Intended Nationally Determined Contributions

MC : Multicyclone Separator

METI : Japanese Ministry of Economy, Trade of Industry

OPEX : Operating Expenditure

PDP : Process Design Package

PFD : Process Flow Diagram

P&ID : Piping and Instrument Diagram

PLF : Plant Load Factor

RE : Renewable Energy

SCR : Selective Catalytic Reduction

SNCR : Selective Non-Catalytic Reduction

SPM : Suspended Particulate Matter

TPP : Thermal Power Plant

TPS : Thermal Power Station


0-7745 0

SHEET 5 OF 81

FORM 1005-2 3




3. Introduction

3.1 Project Background

Associated with rapid economic growth, environmental norms are tightening in India, and the

Ministry of Environment, Forest and Climate Change (MoEF&CC) published the New

Environmental Norms (hereinafter called “the Norms”), 2015 for thermal power plants (TPP) to

amend the Environment (Protection) Rule, 1986 (refer to Table 9-1 and Table 9-2). Under these

circumstances, JGC, JGC C&C, SOJITZ and JCOAL organized a consortium, with the financial

assistance of the Japanese Ministry of Economy, Trade of Industry (METI), in order to meet the

needs for flue gas treatment in coal-fired TPP by exporting the exclusive dry DeSOx process and

DeNOx process.

3.2 Study Objectives

The main objective of this study is to confirm the feasibility of introducing the dry DeSOx

process and DeNOx process into coal-fired TPP in India. For this purpose, the competitiveness

of the dry DeSOx process and DeNOx process over the conventional wet DeSOx process and

DeNOx process was be assessed from technical and commercial aspects.

4. Design Basis

This feasibility study was conducted based on several conditions confirmed with TATA Power

Co., Ltd. Those conditions (such as coal analysis data, flue gas compositions and conditions, etc.)

are specified in the following documents in Attachments 1, 2 and 3.

- Basic Engineering Design Information S-1222-001

- Design Basis for Maithon Power Plant S-1222-101

- Design Basis for Jojobera Power Plant S-1222-102


0-7745 0

SHEET 6 OF 81

FORM 1005-2 3




5. Technology

5.1 Dry DeSOx Process

The dry DeSOx process (i.e., dry-FGD process) was developed by Hokkaido Electric Power Co.,

Inc. in Japan in the late 1980’s and applied to its own coal-fired TPP. The TPP is operating

commercially from 1991 up to the present date. In addition, the dry DeSOx process was applied

for treating the flue gas from coke oven in China in the past 2~3 years and those plants are

operating up to the present date without any major troubles.

The dry-DeSOx process uses a desulfurizing agent to absorb sulfur dioxide (SO2) and convert it

to calcium sulfate (CaSO4) through a DeSOx tower. The DeSOx tower comprises two stages of

moving beds with the desulfurizing agent, which is supplied from the top and discharged to the

bottom hopper zone (refer to Figure 5-1). The flue gas is fed to the lower stage and contacted

with the desulfurizing agent by cross flow. In this stage, in addition to absorbing sulfur dioxide

(SO2), the remaining dust is trapped by the desulfurizing agent. The flue gas is exit from the

lower stage and fed to the upper stage. In this stage, the flue gas is contacted with fresh

desulfurizing agent by cross flow and sulfur dioxide (SO2) is absorbed to the desulfurizing agent,

again. Then, the SOx concentration in the flue gas achieves to the target value.

Figure 5-1 DeSOx Tower

The desulfurizing agent is a mixture of calcium hydroxide (Ca(OH)2), coal ash, and calcium

sulfate (CaSO4). The chemical reaction is represented by the following equation:

2Ca(OH)2 + 2SO2 + O2 → 2CaSO4 + 2H2O ‐(1)

The desulfurizing agent is pelletized, as shown in Figure 5-2. The desulfurizing agent is

produced by the process scheme shown in Figure 5-3.


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During the hydrothermal treatment, calcium silicate is produced and it contributes to

absorption of sulfur dioxide (SO2). Part of the spent desulfurizing agent is recycled as raw

material to replace of calcium sulfate (CaSO4), since spent the desulfurizing agent consists

mainly of calcium sulfate (CaSO4). Typical schematic drawing of production of desulfurizing

agent is shown in Figure 5-4.

Figure 5-4 Schematic Drawing of Desulfurizing Agent Production

Figure 5-2 Desulfurizing Agent

Figure 5-3 Process Scheme for Production of Desulfurizing Agent


0-7745 0

SHEET 8 OF 81

FORM 1005-2 3




5.2 DeNOx Process

DeNOx process uses selective catalytic reduction (SCR) for nitrification. As a gaseous reductant,

air-diluted ammonia (NH3) vapor is injected upstream of the catalyst. The chemical reaction is

indicated by the Equations (2), (3) and (4). Nitric oxide (NO) and nitrogen oxide (NO2) are

converted to nitrogen (N2) and water (H2O).

4NO + 4NH3+O2 → 4N2 + 6H2O ‐(2)

NO + NO2 + 2NH3 → 2N2 + 3H2O ‐(3)

NO2 + 8NH3 → 7N2 + 12H2O ‐(4)

In general, plate type or honeycomb structured catalyst is used. Honeycomb structured catalyst

provides higher performance, as the required volume of catalyst is smaller than that of the

plate type. Honeycomb structured catalyst can be used for clean flue gas (dust free or low

concentration of dust) as plugging from a high concentration of dust is not anticipated.

Figure 5-5 Honeycomb Structured Catalyst


0-7745 0

SHEET 9 OF 81

FORM 1005-2 3




6. Technical and Economic Study for Commercial Plant

6.1 Study Case

The technical and economic study was conducted by assuming that the dry-DeSOx process and

DeNOx process are introduced into a new or existing TPP, which is equivalent to 1 unit (525

MW, flue gas flow rate 2,300,000 Nm3/h) of the Maithon power plant in the Jharkhand state in

India. The study was made for the following three cases and the details of each case are

described hereafter:

Case 1: Retrofit of dry-DeSOx system and low NOx burner into the existing plant

Case 2: Retrofit of dry-DeSOx system and DeNOx system into the existing plant

Case 3: Installation of dry-DeSOx system and DeNOx system into the new plant

The configuration of existing plant was assumed as shown in Figure 6-1. The configuration is

the same as that of the Maithon power plant.

Figure 6-1 Configuration of Existing Plant

In Case 1, the exiting plant will be retrofit with the dry-DeSOx system and low NOx burner.

NOx concentration is decreased to the Norms’ level (refer to Table 9-1) or lower by installing the

low NOx burner into the existing boiler. SOx concentration is decreased to the Norms’ level or

lower by installing the dry-DeSOx system downstream of ESP. The configuration and process

conditions of Case 1 are shown in Figure 6-2.


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Figure 6-2 Configuration and Process Conditions of Case 1

In Case 2, the existing plant will be retrofit with the dry-DeSOx system and DeNOx system.

SOx concentration is decreased to the Norms’ level by installing dry-DeSOx system downstream

of ESP. NOx concentration is decreased to the Norms’ level by installing DeNOx system

downstream of dry-DeSOx system. The configuration and process conditions of Case 2 are

shown in Figure 6-3.


In Case 3, the dry-DeSOx system and DeNOx system will be installed in a new plant. SOx

concentration is decreased to the Norms’ level by installing dry-DeSOx system downstream of

the dust collection system. NOx concentration is decreased to the Norms’ level by installing

DeNOx system downstream of the dry DeSOx system. The configuration and process conditions

of Case 3 are shown in Figure 6-4.


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6.2 Basic Design Information for Case 1

6.2.1 PFD

PFD for Case1 is shown in Attachment-4. Flue gas from the existing ESP is introduced to

DeSOx Tower (C-101A~F) and SOx is absorbed by the desulfurizing agent by contacting with

the desulfurizing agent in the DeSOx Tower (C-101A~F). The treated flue gas is discharged

from the existing stack to atmosphere. The desulfurizing agent is stocked in Fresh Agent

Hopper (V-101A/B), weight-measured by Fresh Agent Weigh Scale (Z-102A/B) and then fed to

the DeSOx Tower (C-101A~F) by Fresh Agent Conveyer (Z-103A/B). The spent desulfurizing

agent is used at a rate of 7.45 ton/hr and discharged from the bottom of DeSOx Tower (C-

101A~F) and transferred to Spent Agent Hopper (V-102A/B) by Spent Agent Conveyer (Z-

104A/B). In addition to this DeSOx system, desulfurizing agent production facility (refer to

Figure 5-4) is installed separately.

6.2.2 Major Equipment

Conceptual drawing of one unit of DeSOx Tower is shown in Figure 6-5 and Figure 6-6. DeSOx

Tower (C-101A~F) comprises 4 beds/tower × 3 towers/unit ×2 units. The dimensions are 19.6

m long ×14.0 m wide × 32.0 m high per unit.


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Figure 6-5 DeSOx Tower for Case 1(plan view of one unit)

Figure 6-6 DeSOx Tower for Case 1 (side view of one unit)

6.2.3 Required Area

Required area for installation of the dry-DeSOx system and desulfurizing agent production

facility was estimated approximately as follows:

Dry DeSOx System 1,010

Desulfurizing Agent Production Facility 1,600

Total 2,610 m2

Tower

Bed

Uni


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6.2.4 Effluent

Major effluent from the installed facilities is the spent desulfurizing agent discharged from the

bottom of DeSOx Tower (C-101A~F) by total 7.45 ton/h. Part of spent agent (approx. 30%) is

recycled as raw material of fresh agent, and the rest of spent agent (approx. 70%) will be

disposed of in a landfill or reused as deodorant and solidification material for sludge, etc.

However, waste water is not discharged, and thus, waste water treatment is not required for

the dry-DeSOx process. This is a significant advantage over the competing wet-DeSOx process

(i.e., Limestone process).

6.3 Basic Design Information for Case 2

Case 2 considers retrofitting DeNOx system downstream of the DeSOx system, in addition to

Case 1. However, it was particularly noted for Case 2 that the flue gas temperature to the

DeNOx system is as low as 145 oC and a large quantity of DeNOx catalyst seemed to be

required for the following reasons:

Activity of DeNOx catalyst significantly decreases at low reaction temperature.

Degradation of performance occurs due to deposition of ammonium sulfate on the surface of

DeNOx catalyst in the presence of sulfur compounds (SO3) and ammonia at low reaction

temperatures, especially under 200 oC.

In detail, the quantity of DeNOx catalyst required was studied for several flue gas temperature

conditions and it was confirmed to be impractically large in Case 2, as shown in Figure 6-7.

Accordingly, further study of Case 2 was cancelled.

Figure 6-7 Relation between Flue Gas Temperature and DeNOx Catalyst Quantity


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6.4 Basic Design Information for Case3

6.4.1 PFD

PFD for Case3 is shown in Attachments 5 and 6. This Case 3 assumes that the dust removal

systems, dry-DeSOx system and DeNOx system are installed in new TPP. Flue gas from the

economizer is introduced to Inertia Dust Collector (S-101A~H) and Multicyclone (S-102A~H)

to remove most of the dust. Removed dust is transferred to Dust Hopper (S-103) equipped with

Dust Filter (V-103) by pneumatic conveyer system and finally transferred to ash pond by Dust

Conveyor (Z-105) for landfill.

The flue gas, including minimal dust, is sent to DeSOx Tower (C-101A~H), and SOx is

absorbed by desulfurizing agent by contacting with the desulfurizing agent in DeSOx Tower

(C-101A~H). The minimal dust is trapped by the desulfurizing agent.

The desulfurizing agent is stocked in Fresh Agent Hopper (V-101A/B), weight-measured by

Fresh Agent Weigh Scale (Z-102A/B) and then fed to DeSOx Tower (C-101A~H) by Fresh

Agent Conveyer (Z-103A/B). The spent desulfurizing agent is used at a rate of 7.45 ton/hr,

discharged from the bottom of DeSOx Tower (C-101A~H) and transferred to Spent Agent

Hopper (V-102A/B) by Spent Agent Conveyer (Z-104A/B). In addition to this DeSOx system,

desulfurizing agent production facility (refer to Figure 5-4) is installed separately.

The flue gas from DeSOx tower (C-101A~H) is sent to SCR reactor (R-301) after mixing with

air-diluted ammonia vapor in Flue Gas / NH3 Mixer (M-301). The air-diluted ammonia vapor

is supplied by Ammonia Injection Package (Z-301). Treated flue gas is sent to air heater and

discharged from the stack to atmosphere.


In Case 3, the major items of equipment are Inertia Dust Collector / Multicyclone (S-101A~H /

S-102A~H), DeSOx Tower (C-101A~H) and SCR Reactor (R-301).

Inertia Dust Collector (S-101A~H) and Multicyclone (S-101A~H) are combined, and 8 units

are required. Conceptual drawing of one unit of Inertia Dust Collector and Multicyclone is

shown in Figure 6-8. The unit dimensions are 11.0 m long ×8.0 m wide × 15.0 m high, and 81

cyclones are installed per unit.


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Figure 6-8 Inertia Dust Collector/Multicyclone for Case 3(side and plan view of one unit)

Conceptual drawing of one unit of DeSOx Tower is shown in Figure 6-9 and Figure 6-10.

DeSOx Tower (C-101A~H) comprises of 4 beds/tower × 4 towers/unit × 2 units. The unit

dimensions are 26.0 m long × 14.0 m wide × 32.0 m.

Figure 6-9 DeSOx Tower for Case 3 (plan view of one unit)

Tower

Bed Uni


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Figure 6-10 DeSOx Tower for Case 3 (side view of one unit)

Conceptual drawing of SCR Reactor (R-301) is shown in Figure 6-11. SCR Reactor (R-301) has

3 catalyst layers (2 layers in operation and 1 layer in standby). The dimensions are 15.33 m

long × 12.27 m wide × 20.5 m high.

Figure 6-11 SCR Reactor for Case 3 (side and plan view)

6.4.3 Required Area

Required area for installation of the dust removal system, dry-DeSOx system and

desulfurizing agent production facility and DeNOx system was estimated approximately as

follows:


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Dust Removal System 2,320

Dry DeSOx System 1,340

DeNOx System 640

Desulfurizing Agent Production Facility 1,600

Total 5,900 m2

6.4.4 Effluent

Major effluents from the installed facilities are the spent desulfurizing agent and DeNOx

catalyst.

The spent desulfurizing agent is discharged from the bottom of DeSOx Tower (C-101A~H) at a

rate of 7.45 ton/h. Part of spent agent (approx. 30%) is recycled as raw material of fresh agent,

and the rest of spent agent (approx. 70%) will be disposed of in a landfill or reused as

deodorant and solidification material for sludge, etc. The same as in Case 1, described in

Section 6.2.4, waste water is not discharged, and thus, waste water treatment is not required

for the dry-DeSOx process.

The DeNOx catalyst has 5 years of design life, since blockage and erosion of catalyst will be

less likely due to the installation of a dust removal system and Dry DeSOx system upstream of

the DeNOx system. The spent DeNOx catalyst will be sent to a waste disposal firm in India in

compliance with the Indian law.

6.4.5 Comparison of Dust Removal System

6.4.5.1 Comparison

A comparison was made between multicyclone separator and electrostatic precipitator for the

Case 3 study (refer to Section 6.1) to confirm the feasibility of applying large-scale multicyclone

separators in a commercial plant. The comparison is summarized in Table 6-1, based on technical

discussions with several vendors and on their quotations. Figures that would make it infeasible

and technical concerns are highlighted in blue.


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Table 6-1 Comparison of Multicyclone Separator and Electrostatic Precipitator

Item Multicyclone Separator Electrostatic Precipitator Vendor A Vendor B/C/D Vendor B Vendor C Vendor D

No. of Unit 10

Decline

6 8 3 Delivery [Month] 54 30 12 12 Required Area [m2] 2,320 3,760 4,620 2,821 CAPEX [-] (Note 1) 1.15 1.00 0.66 2.21 Dust Removal Efficiency [%] (Note 2)

82.0 99.0 99.0 99.0

Friction Loss [mmAq] 72 25 30 25

Concern

Maldistribution

Potential maldistribution within one unit caused by increasing the equipment size to commercial scale

No concern

Turndown

Decrease of dust removal efficiency

No concern Needs control to equalize flow to the units

Others

Low availability of vendors with sufficient experience manufacturing large-scale multicyclone separators

No concern

Note 1: CAPEX is shown as the ratio to the CAPEX of electrostatic precipitator quoted by the Vendor B. Note 2: Dust removal efficiency is based on Vendor guaranteed figures.

As shown in Table 6-1, multicyclone separators are superior to electrostatic precipitators in

terms of the area required. However, the guaranteed figures and performance (i.e., dust

removal efficiency) of multicyclone separators are quite inferior to those of electrostatic

precipitator. In addition, when increasing the equipment size to the commercial plant scale,

the following technical concerns were found with multicyclone separators.

Maldistribution:

JGC conducted CFD analysis for one multicyclone separator units to review flow distribution

inside the unit. The result is shown in Figure 6-12. Lower velocity was observed just behind

the inlet screen, while higher velocity was observed in the rear of the unit. Although the

maldistribution could be mitigated by developing the design of the inlet screen, large

multicyclone separators may inherently be difficult to design in such a way as to prevent

maldistribution in all operation cases.


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Figure 6-12 Flow Distribution inside Multicyclone Separator

Turndown:

During turndown operation, flue gas flow rate will decrease, and this will lower the dust

removal efficiency. In order to maintain high dust removal efficiency (which is achieved by

high velocity), some multicyclone separators may be shut down, and the flow redistributed to

the working multicyclone separators. To do this, a large automated damper (or guide vane)

and a flow meter will be required at the inlet of each multicyclone separator (refer to Figure

6-13 for an example of the duct arrangement). This will cause problems, both technically and

commercially.

Figure 6-13 Duct Arrangement for Multicyclone Separators


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Others:

Prospective vendors are limited due lack of experience manufacturing large multicyclone

separators. This will lead to commercial problems during detailed engineering.

6.4.5.2 Short Summary

Multicyclone separator is inferior to electrostatic precipitator in dust removal efficiency. In

addition, multicyclone separator may have several concerns (maldistribution, turndown,

marketability) when increasing equipment size to a commercial plant scale.

6.5 Economic Study

6.5.1 Conditions

General

An economic study was conducted for Cases 1 and 3 to evaluate the cost competitiveness of the

dry-DeSOx process compared to the conventional wet-DeSOx process. The study was

conducted by comparing the sum of the CAPEX and the OPEX for 20 years of operation.

CAPEX and OPEX were calculated based on vendor quotations and on in-house data of the

consortium partners, on a Japanese price basis. OPEX was calculated based on a plant load

factor (PLF) 100 % and a Capacity Factor (CF) 85 %.

Conventional System

The configuration and process conditions of the conventional system assumed in this economic

study for Cases 1 and 3 are shown in Figure 6-14 and Figure 6-15, respectively.

Figure 6-14 Configuration and Process Condition of Conventional System for Case 1


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Figure 6-15 Configuration and Process Condition of Conventional System for Case 3

Dry-DeSOx System

Slake lime (Ca(OH)2) is currently used as the raw material of the desulfurizing agent in the

existing plants.However, quick lime (CaO) can be used as the raw material, as a cost reduction

option, because both, its price by weight and the price by weight of the calcium contained, are

lower than that of slake lime. Although the use of quick lime is still up to a bench scale test,

the use of quick lime was considered as a cost reduction option. In this study, the unit prices of

the raw material were assumed as follows:

Slake lime Ca(OH)2 : 0.20 USD/kg (equivalent to 0.37 USD/kg-Ca)

Quick lime CaO : 0.18 USD/kg (equivalent to 0.25 USD/kg-Ca)

In addition, the larger the desulfurizing agent production facility, the lower CAPEX per unit

weight of the desulfurizing agent produced. Hence, using one desulfurizing agent production

facility to supply all three neighboring power plants (i.e., Maithon, Jojobera and IEL) was

considered as another cost reduction option. When a common desulfurizing agent production

facility was applied, the CAPEX of the desulfurizing agent production facility was divided by

the ratio of the plant capacity (Maithon : Jojobera & IEL = 1050 MW : 668 MW).

Wet-DeSOx System

The limestone process, as the most common conventional process in inland areas and the main

competitor to the dry-DeSOx process, was taken as Case W-1. In addition, the Mg(OH)2

process was taken as Case W-2 (Note: The Mg(OH)2 process is generally cheaper than the

limestone process. However, since it may not be allowed to dispose of its by-product

(magnesium sulfate MgSO4) in rivers or in inland areas and as it has been applied in small

plants only, the Mg(OH)2 process was considered for reference only).

DeNOx System

When dry-DeSOx system is applied, honeycomb type DeNOx catalyst is used because the


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DeNOx system is located downstream of the dust collection system, and the DeNOx catalyst

will be almost free of plugging from dust. Catalyst life is assumed to be 5 years because

erosion by dust is not expected.

However, when a wet-DeSOx system is applied, a plate type DeNOx catalyst is used because

DeNOx system is located upstream of the dust removal system and a honeycomb type catalyst

cannot be used due to plugging from dust. Catalyst life is assumed to be 2 years (i.e., shorter

than that of the honeycomb type) because heavy erosion by the high concentration of dust is

anticipated.

6.5.2 Economic Study for Case 1

Based on the conditions above, an economic study was conducted for the 6 study cases. The

details of each study case, CAPEX and OPEX/yr, are listed in Table 6-2. CAPEX of Case W-1

was used as a benchmark. CAPEX and OPEX/yr are shown as the ratio to the CAPEX of Case

W-1. The breakdown of CAPEX and OPEX/yr are shown in Figure 6-16 and Figure 6-17,

respectively. The cumulative cost (sum of CAPEX and OPEX/yr) for 20 years of operation is

shown in Figure 6-18.

Table 6-2 Economic Study Case

Case

DeSOx System

CAPEX OPEX/yr Dry or Wet Process Raw

material

DeSOx agent production

(Note)

D-1 Dry Silica-enhanced lime process Ca(OH)2 Dedicated 1.14 0.087

D-1a Dry Silica-enhanced lime process Ca(OH)2 Common 0.81 0.082

D-2 Dry Silica-enhanced lime process CaO Dedicated 1.14 0.066

D-2a Dry Silica-enhanced lime process CaO Common 0.81 0.062

W-1 Wet Limestone Process CaCO3 n/a 1.00 0.076

W-2 Wet Mg(OH)2 Process Mg(OH)2 n/a 0.61 0.079

Note: “Common” means that the desulfurizing agent production facility is used in common by Maithon, Jojobera and IEL power plants. However, “Dedicated” means that the facility is dedicated to Maithon power plant only.


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Figure 6-16 CAPEX Breakdown for Case 1

Figure 6-17 OPEX Breakdown for Case 1


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Figure 6-18 Cumulative Cost for Case 1

The following are the results of the study:

CAPEX of 1.14 in Cases D-1 and D-2 is higher than the 1.00 of Case W-1. However, the

CAPEX of desulfurizing agent production facility accounts for substantial fraction in the dry-

DeSOx system (refer to Figure 6-16). By having the neighboring power plants share the

desulfurizing agent production facility, the CAPEX of Cases D-1 and D-2 will decrease to 0.81

(as Case D-1a and D-2a) and be lower than the 1.00 of Case W-1.

OPEX of the dry-DeSOx system is dominated by the desulfurizing agent (refer to Figure

6-17), and thus, use of a less expensive raw material is a cost reduction option. By using quick

lime, CaO, as the raw material of the desulfurizing agent, instead of slake lime, Ca(OH)2, the

OPEX of 0.087 in Case D-1 will decrease to 0.066 (as Case D-2) and become lower than the

0.076 of Case W-1. In addition, by having the neighboring power plants share the

desulfurizing agent production facility, the OPEX will decrease to 0.062 (as Case D-2a).

Based on the considerations above, Case D-2a is recommended, as both, CAPEX and OPEX,

are lower, compared with Case W-1. In Case D-2, it is also probable that the total cost (CAPEX

+ OPEX) will be lower than that in Case W-1, for an operation period of 14 years or longer.

6.5.3 Economic Study for Case 3

Economic studies were conducted separately for the DeSOx system (including dust collection

system), DeNOx system and overall system (combination of DeSOx system + DeNOx system).

6.5.3.1 DeSOx System including Dust Removal System

The economic study had been planned for the 6 study cases, as the same as studied in Case 1.


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Meanwhile, variation of the dust collection system (i.e., Multicyclone Separator or

Electrostatic Precipitator) can provide double study cases. However, since Multicyclone

Separator seemed not to be feasible for large commercial plants (refer to Section 6.4.5),

Electrostatic Precipitator was considered for the 6 study cases.

The details of each study case, CAPEX and OPEX/yr, are listed in Table 6-3. CAPEX of Case

W-1E was used as a benchmark. Thus, CAPEX and OPEX/year are shown as a ratio to the

CAPEX of Case W-1E, overall system (Dust Removal + DeSOx + DeNOx). The cumulative cost

(sum of CAPEX and OPEX/yr) for 20 years of operation is shown in Figure 6-19.

Table 6-3 Economic Study Case for DeSOx System

Case Dust

Collection

DeSOx System

CAPEX OPEX/yr Dry or

Wet Process Raw

material

DeSOx agent

production (Note)

D-1E ESP Dry Silica-enhanced lime process Ca(OH)2 Dedicated 1.15 0.064

D-1Ea ESP Dry Silica-enhanced lime process Ca(OH)2 Common 0.92 0.062

D-2E ESP Dry Silica-enhanced lime process CaO Dedicated 1.15 0.050

D-2Ea ESP Dry Silica-enhanced lime process CaO Common 0.92 0.048

W-1E ESP Wet Limestone Process CaCO3 n/a 0.91 0.055

W-2E ESP Wet Mg(OH)2 Process Mg(OH)2 n/a 0.65 0.057

Note: “Common” means that the desulfurizing agent production facility is shared by Maithon, Jojobera and IEL power plants. However, “Dedicated” means that the facility is dedicated to Maithon power plant.

Figure 6-19 Cumulative Cost for Case 3 DeSOx System


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The results of the economic study are as follows:

Because flue gas temperature is higher and the number of dry-DeSOx towers is larger

than in Case 1, by increasing of flue gas volume flow, the CAPEX of the dry-DeSOx

system is higher than that of the wet-DeSOx system. However, by sharing the

desulfurizing agent production facility, CAPEX of 1.15 of dry-DeSOx process in Case D-1E

and Case D-2E decreases to 0.92 (as Case D-1Ea and D-2Ea), which is close to the 0.91 of

the wet-DeSOx system in Case W-1E.

OPEX of 0.064 of dry-DeSOx system in Case D-1E will decrease to 0.050 (as Case D-2E)

which is lower than the 0.055 of the wet-DeSOx system in Case W-1E, by using quick

lime, CaO, as the raw material of the desulfurizing agent, instead of slake lime, Ca(OH)2.

In addition, by sharing the desulfurizing agent production facility, the OPEX will decrease

to 0.048 (as Case D-2Ea).

6.5.3.2 DeNOx System

Economic study was conducted for the 6 cases (the same as those studied for the DeSOx

system in Section 6.5.3.1) with the same conditions. Honeycomb type catalyst was used for the

dry DeSOx system cases because DeNOx system is downstream of the dust collection system.

However, plate type catalyst was used for the wet-DeSOx system cases, as the DeNOx system

is upstream of the dust collection system.

The details of each study case, CAPEX and OPEX/yr are listed in Table 6-4. CAPEX of Case

W-1E was used as a benchmark. Thus, CAPEX and OPEX/year are shown as the ratio to the

CAPEX of Case W-1E, overall system (DeSOx + DeNOx). The cumulative cost (sum of CAPEX

and OPEX/yr) for 20 years of plant life is shown in Figure 6-20.

Table 6-4 Economic Study Case for DeNOx System

Case DeNOx System

CAPEX OPEX/yr Catalyst

D-1E Honeycomb type 0.09 0.074

D-1Ea Honeycomb type 0.09 0.074

D-2E Honeycomb type 0.09 0.074

D-2Ea Honeycomb type 0.09 0.074

W-1E Plate type 0.09 0.100

W-2E Plate type 0.09 0.100


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Figure 6-20 Cumulative Cost for Case 3 DeNOx System

The results of the economic study are as follows:

Because the honeycomb type of DeNOx catalyst is cheaper than the plate type of DeNOx

catalyst in terms of total cost (i.e., total quantity of catalyst multiplied by unit price of

catalyst) and catalyst life (refer to Section 6.5.1), OPEX of 0.074 of the dry-DeSOx system

cases (Case D-1E, D-1Ea, D-2E, D-2Ea) will be lower than the OPEX of 0.100 of the wet-

DeSOx system cases (Case W-1, W-2).

6.5.3.3 Overall system (DeSOx system + DeNOx system)

An economic study was conducted for the 6 cases (the same as studied for the DeSOx system

in Section 6.5.3.1 and the DeNOx system in Section 6.5.3.2). The details of each study case,

CAPEX and OPEX/yr, are listed in Table 6-5. The CAPEX and OPEX/year are shown as the

ratio to the CAPEX of Case W-1E, overall system (DeSOx + DeNOx). The breakdowns of

CAPEX and OPEX/yr are shown in Figure 6-21 and Figure 6-22, respectively. . The

cumulative cost (sum of CAPEX and OPEX/yr) for 20 years of operation is shown in Figure

6-23 (for clarity, numerical data up to 10 years of operation period is shown in Table 6-6).

Table 6-5 Economic Study for Overall System

Case Dust

Collection (Note 1)

DeSOx System DeNOx System

CAPEX OPEX/yr Dry or

Wet Process Raw

material

DeSOx agent production

(Note 2) Catalyst

D-1E ESP Dry Silica-enhanced lime process Ca(OH)2 Dedicated Honeycomb 1.23 0.137

D-1Ea ESP Dry Silica-enhanced lime process Ca(OH)2 Common Honeycomb 1.01 0.134

D-2E ESP Dry Silica-enhanced lime process CaO Dedicated Honeycomb 1.23 0.124

D-2Ea ESP Dry Silica-enhanced lime process CaO Common Honeycomb 1.01 0.120


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W-1E ESP Wet Limestone Process CaCO3 n/a Plate 1.00 0.155

W-2E ESP Wet Mg(OH)2 Process Mg(OH)2 n/a Plate 0.73 0.157

Note1: “ESP” = Electrostatic Precipitator Note2: “Common” means that the desulfurizing agent production facility is shared by Maithon, Jojobera and IEL power plants. However, “Dedicated” means that the facility is dedicated to Maithon power plant.

Figure 6-21 CAPEX Breakdown for Case 3

Figure 6-22 OPEX Breakdown for Case 3


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Figure 6-23 Cumulative Cost for Case 3 Overall System

Table 6-6 Cumulative Cost for Case 3 Overall System (numerical data)

Case Operation Period [years]

Note 0 1 2 3 4 5 6 7 8 9 10

D-1E 1.23 1.37 1.51 1.64 1.78 1.92 2.06 2.20 2.33 2.47 2.61

D-1Ea 1.01 1.14 1.28 1.41 1.55 1.68 1.82 1.95 2.08 2.22 2.35

D-2E 1.23 1.36 1.48 1.60 1.73 1.85 1.97 2.10 2.22 2.35 2.47

D-2Ea 1.01 1.13 1.25 1.37 1.49 1.61 1.73 1.85 1.97 2.09 2.21

W-1E 1.00 1.16 1.31 1.47 1.62 1.78 1.93 2.09 2.24 2.40 2.55 Benchmark

W-2E 0.73 0.89 1.05 1.20 1.36 1.52 1.67 1.83 1.99 2.14 2.30

As a result of the economic study of the overall system, it was found that the CAPEX of the

dry-DeSOx system cases (D-1E, D-1Ea, D-2E, D-2Ea) will be higher than that of the wet-

DeSOx system case, W-1E. However, the same as observed in Case 1, the CAPEX of the

desulfurizing agent production facility still accounts for a substantial fraction in the dry-

DeSOx system (refer to Figure 6-21), and thus, sharing the desulfurizing agent production

facility among the neighboring power plants is also still a cost reduction option in Case 3.

However, it was observed that the OPEX of the dry-DeSOx system cases will be lower than in

the wet-DeSOx system cases due to the low cost of the honeycomb type catalyst in the DeNOx

system. In addition, the OPEX of the DeSOx agent dominates some fraction in the dry-DeSOx

system (refer to Figure 6-22). Hence, the use of a less expensive raw material for the

desulfurizing agent will also lower the OPEX of the dry-DeSOx system cases much more in

Case 3.

By applying the cost reduction options above, the total cost of cases D-1Ea and D-2Ea will be


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lower than that of case W-1E in 1 year of operation or longer (refer to Table 6-6, cases D-1Ea

and D-2Ea, highlighted in yellow). Hence, the following is recommended:

The dry-DeSOx system Cases D-1Ea and D-2Ea are recommended, as their total cost will

be lower than that of the wet-DeSOx system, Case W-1, early in the operation period.

6.5.4 Short Summary

The results of the economic study for Cases 1 and 3 are as follows:

Dry-DeSOx system is competitive at lower flue gas temperatures, as the number of dry

DeSOx towers decreases by decreasing of flue gas volume flow.

Use of less expensive raw material (i.e., use of quick lime, CaO, instead of slake lime,

Ca(OH)2), is a cost reduction option in the dry-DeSOx system. Accordingly,

industrialization of desulfurizing agent production using quick lime, CaO, should be

accelerated to introduce the dry-DeSOx system into commercial plants widely.

A commonly used desulfurizing agent production facility is a cost reduction option in the

dry-DeSOx system.


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7. Technical and Cost Information for Demonstration Plant

7.1 Basic Design Information

7.1.1 BFD

The demonstration plant is designed to confirm performance of the dust removal system,

DeSOx system and DeNOx system for the study Case 3, prior to development for the

commercial scale.

The BFD of demonstration plant, including process conditions, is shown in Figure 7-1. Flue

gas is taken from the downstream of the existing economizer in the Jojobera Power Plant Unit

5. The flue gas is treated through the demonstration plant and returned to the downstream of

the existing air heater in the Unit 5. The tie-in conditions are summarized in Table 7-1.

Figure 7-1 BFD of Demonstration Plant

Table 7-1 Tie-in Conditions

Tie-in A

(Flue gas take-off) Tie-in B

(Flue gas return) Flow rate [Nm3/h] 5,000 5,156 *1) Temperature [oC] 310 277 Pressure [kPag] -0.15 -1.5 SOx [mg/Nm3] 800 < 100 NOx [mg/Nm3] 600 < 100 Dust [g/Nm3] 100 < 30

*1) Flue gas is increased by injection of ammonia vapor in the DeNOx system.


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7.1.2 Tie-ins to / from the Existing Plant

The exact tie-in locations were confirmed with Client as shown in Figure 7-2. The details and

scope of supply of tie-in connections were confirmed with Client as shown in Figure 7-3. The

tie-in connections were planned to be installed by Client during the shutdown in December

2017.

Figure 7-2 Tie-in Locations to/from the Existing Plant

Figure 7-3 Detail of Tie-in Connection (applicable to both Tie-in A and B)

7.1.3 PDP

Basic design information of demonstration plant was compiled as PDP (process design

package). Table 7-2 shows document list included in the PDP.


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Table 7-2 Document List of PDP for Demonstration Plant

Document No. Title

S-1223-051 Process Description for Demonstration Plant S-1224-001 Equipment List S-1224-351 Process Data Sheet for SCR Reactor (R-351) S-1224-352 Process Data Sheet for Flue Gas/NH3 Mixer (M-351) S-1228-151 Process Data Sheet for Multi-Cyclone Separator (S-151/S-152) S-1228-351 Duty Specification for Ammonia Injection Package (Z-351) S-1228-003 Catalyst and Chemical Summary S-1228-004 Utility Summary D-1223-151 PFD for DeSOx Unit D-1223-351 PFD for DeNOx Unit D-1225-051 Plot plan for Jojobera Power Plant D-1225-052 Plot plan for demonstration plant D-1225-101 P&ID for Symbology D-1225-151 P&ID for DeSOx Unit Tie-in from Existing Plant D-1225-152 P&ID for DeSOx Unit Dust Removal and DeSOx Tower D-1225-351 P&ID for DeNOx Unit SCR Reactor D-1225-352 P&ID for DeNOx Unit Dust Blaster and PA Distribution

D-1350-151 Mechanical Drawing for DeSOx Tower (C-151) / Multi-cyclone Separator (S-151/152) / Fresh Agent Hopper (V-151)

D-1350-152 Mechanical Drawing for Ash Feeder (Z-153) D-1350-351 Mechanical Drawing for Dust Blaster (Z-352)


Major equipment of the demonstration plant are Inertia Dust Collector / Multicyclone (S-151 /

152), DeSOx Tower (C-151) and SCR Reactor (R-351).

Inertia Dust Collector / Multicyclone (S-151 / 152):

One inertia dust collector / multicyclone is installed with the dimensions, 3.7 m long ×1.2 m

wide × 5.455 m high, having 2 cyclones in the multicyclone.

DeSOx Tower (C-151):

One tower is installed with the dimension, 4.62 m long × 3.85 m wide × 13 m high, comprising

two stages of moving beds of desulfurizing agent.

SCR Reactor (R-351):

One reactor is installed with the dimensions, 0.9 m long × 0.9 m wide × 7.1 m high, having 2

catalyst layers in operation.

7.1.5 Required Area

The required area of demonstration plant is approximately 170 m2 (21.0 m long × 8.0 m wide)


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as shown in Figure 7-4.

Figure 7-4 Plot plan of Demonstration Plant

7.1.6 Consumption of Utility, Catalyst and Chemical

The following utilities, catalysts and chemicals are used for operating the demonstration

plant.

Utility:

Electric power Nor. 49.7 kW, Max. 50.1 kW

Instrument air Nor. 1.4 Nm3/h, Max. 11.4 Nm3/h

Plant air Nor. 0.0 Nm3/h, Max. 100 Nm3/h (intermittent use only)

Industrial water Nor. 0.0 ton/h, Max. 3.0 ton/h (intermittent use only)

Catalyst and Chemical:

Desulfurizing agent 16.2 kg/h

DeNOx catalyst 0.63 m3

Anhydrous ammonia 1.48 kg/h (supplied by liquid cylinders (50 kg/cylinder) )


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7.1.7 Effluents

Effluents from the demonstration plant are fly ash, spent desulfurizing agent and spent

DeNOx catalyst.

Fly ash:

Fly ash is discharged from the bottom of Inertia Dust Collector (S-151) and Multicyclone (S-

152) at a rate of 475 kg/h. The fly ash is transferred to Dust Hopper (V-152) by Dust Transfer

Fan (K-151A/B), and then the fly ash is transferred to the existing ash pond by truck once a

day.

Spent Desulfurizing Agent:

The spent desulfurizing agent is discharged from the bottom of DeSOx Tower (C-151) to drum

at a rate of 16.2 kg/h. The spent desulfurizing agent is transferred to the existing ash pond for

land fill, the same as the fly ash.

Spent DeNOx Catalyst:

Total 0.63 m3 of DeNOx catalyst will be installed in SCR Reactor (R-351) for 6 months of

demonstration operation. After the completion of 6 months of operation, the spent DeNOx

catalyst will be sent to a waste disposal firm in India in compliance with the Indian law.

7.1.8 Detailed Engineering

CFD analysis was conducted to assure homogeneous mixing and distribution of ammonia

vapor into the flue gas before reaching the DeNOx catalyst in SCR Reactor (R-351). As a result

of the analysis, it was observed that homogeneous ammonia vapor can be supplied to the

DeNOx catalyst within +/- 7.0 % of tolerance by a combination of the following measures:

Ammonia vapor is diluted 80 times with air

Flue Gas / NH3 Mixer (M-351) comprises 4 distribution pipes, with 28 holes (10 mm dia.)

placed on the pipes at intervals of 70 mm (refer to Figure 7-5).

Flue Gas / NH3 Mixer (M-351) is at least 6 m upstream of the inlet of the SCR Reactor (R-

351). At least one elbow is provided between Flue Gas / NH3 Mixer (M-351) and SCR

Reactor (R-351). In addition, a minimum of 3 m of straight run is provided at the inlet of

SCR Reactor (R-351).

These measures were incorporated in the PDP. The result of the CFD analysis is shown in

Figure 7-6.


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Figure 7-5 Detail of Flue Gas / NH3 Mixer (M-351)

Figure 7-6 Distribution of Air-diluted NH3 Vapor to SCR Reactor

7.2 Schedule

The EPC schedule of the demonstration plant is provided in Figure 7-7. Detailed design is

planned from the middle of the 1st quarter up to end of the 2nd quarter in 2018. Construction is

planned from the 3rd to the 4th quarter in 2018. Operation is planned from the 1st to the 2nd

quarter in 2019, and demolition is planned in the 3rd quarter in 2019.


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Figure 7-7 EPC Schedule of Demonstration Plant


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8. Detail Information of DeNOx Catalyst

For the design of DeNOx catalyst (determination of cell number, chemical composition, volume

etc.), it is necessary to clarify influence of dust contained in flue gas on catalyst performance.

The coal ash samples, which were obtained from the coal-fired TPPs owned by TATA Power Co.,

Ltd., were analyzed and the study was conducted for the influence of dust on DeNOx catalyst.

8.1 Analysis of Indian coal ash

The coal ash samples were obtained from Jojobera and MPL (Maithon Power Limited) coal-fired

TPPs owned by TATA Power Co., Ltd. and its chemical composition and physical properties

were analyzed. Coal ash sample was taken from coal ash storage silo, in which coal ash from

both, hopper under the GGH downstream of the boiler flue gas and ESP further downstream, is

stored. Chemical composition was determined by using the Philips x-ray fluorescence

spectrophotometer MagiX PRO. Particle size distribution was measured by using the HORIBA

Laser particle size analyzer LA-950. SEM observation was performed by using JEOL scanning

electron microscope JSM-6010LA.

The results of particle size distribution (PSD) measurement of the coal ash samples are shown

in Table 8-1 and Figure 8-1. The median particle sizes of the coal ash samples from Jojobera

and MPL power plants are 28.9 μm and 23.3 μm, respectively, and the average particle sizes

are 45.0 μm and 45.2 μm, respectively. There is a tendency that particle size of Indian coal ash

is larger than that of general coal ash available in Japan. In addition, the PSD of Indian coal

ash indicates two peaks of distribution, a first peak at ca. 10 to 20 μm and a second peak at ca.

60 to 100 μm. It is different from the PSD of Japanese coal ash, with one peak at ca.11 μm.

Table 8-1 Particle Size of Coal Ashes

Jojobera MPL Japanese

（For reference）

Median particle size

μm 28.9 23.3 11.7

Average particle size

μm 45.0 45.2 16.8


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Figure 8-1 Particle Size Distribution of the Coal Ashes

SEM images of these coal ashes are shown in Figure 8-2. Japanese coal ash contains a lot of 10

μm class particles and contains almost no large particles (refer to Figure 8-2 c)). However,

Indian coal ash contains a lot of large, amorphous particles over 50 µm in size (100 μm class)

together with fine particles (refer to Figure 8-2 a) and b)). The result of SEM observation

supports the result of PSD measurement.


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a) Jojobera

b) MPL

c) Japanese (for reference)

Figure 8-2 SEM Images of the Coal Ashes


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The results of chemical composition analysis for the coal ashes are shown in Table 8-2. For the

Indian coal ash, the sum of SiO2 and Al2O3 account for over 80 % of the composition. The Fe2O3,

TiO2 and K2O components are contained at much lower ratios. The content of alkali metal (K2O)

included in the Indian coal ash, which is a catalyst poisoning material, is approximately twice

than that in Japanese coal ash. Meanwhile, the content of CaO contained in the Indian coal ash,

which is a catalyst poisoning material, as well, is approximately one third of that in Japanese

coal ash. Besides that, trace amounts of components such as P2O5, MgO, BaO, SO3 and Na2O

are contained in the coal ash.

Table 8-2 Result of Chemical Composition Analysis for the Coal Ashes

8.2 Influence of Catalyst Poisoning Components on Performance of DeNOx Catalyst

Catalyst poisoning components included in flue gas may be, for example, alkali metals (Na, K),

alkaline earth metals (Mg, Ca), and As, Pb, P, and so on. Compared with Japanese coal ash, it is

supposed that influence of K2O on degradation of catalyst performance might be greater in

Indian coal ash since the content of K2O included in the Indian coal ash is about twice that in

Japanese coal ash. However, it is speculated that the influence of CaO on catalyst performance

might be less in Indian coal ash, since the content of CaO in the Indian coal ash is one third

that in Japanese coal ash. Also, the levels of the other catalyst poisoning components are very

low and there is no significant difference between both Indian and Japanese ashes. Based on

these considerations, the influence of Indian coal ash on degradation of DeNOx catalyst

performance could be nearly the same level as that of Japanese coal ash. Therefore, it is

concluded that a degradation rate of DeNOx catalyst performance by poisoning should be

considered the same as in Japan when designing DeNOx catalyst for coal-fired TPPs in India.

Jojobera MPL Japanese

（For reference）

SiO2 53.9 56.1 59.1

Al2O3 30.2 30.0 21.9

Fe2O3 6.8 6.0 6.5

TiO2 2.7 2.6 1.8

K2O 2.2 1.8 1.1

CaO 1.8 1.3 6.1

P2O5 1.3 0.8 0.6

MgO 0.4 0.5 1.1

BaO 0.2 0.2 0.2

SO3 0.2 0.2 0.7

Na2O <0.1 0.1 0.4


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8.3 Influence of Dust on Erosion of DeNOx Catalyst

In order to investigate the influence of dust on erosion of DeNOx catalyst, a simulation was

conducted for measurement of wear rate of honeycomb type DeNOx catalyst using silica sand as

the wear material under several conditions. Assuming a low dust concentration after removing

dust, the high activity honeycomb type catalyst was used for the examination sample. Wear

rate was calculated by the following method: DeNOx catalyst sample cut into a predetermined

shape was installed in the wear testing apparatus (refer to Figure 8-3), air containing the wear

material was blown on the side end of the catalyst sample for 30 minutes, and the sample was

weighed before and after testing. Median diameter 80 μm, 52 μm and 20 μm of the silica sand

were used as the wear material, and the wear test was conducted at several dust

concentrations, and gas velocity was as shown in Table 8-3.

Figure 8-3 Wear Testing Apparatus

Table 8-3 Conditions of Wear Test for DeNOx Catalyst

Test No. Dust concentration

(g/Nm3)

Dust particle size

(μm)

Gas velocity

(Nm/s)

1 70 52 40

2 30 52 40

3 5 52 40

4 70 80 40

5 70 20 40

6 70 52 30

7 70 52 20

The result of the wear test indicates the relationship between dust concentration and wear rate,


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the relationship between dust particle diameter and wear rate and the relationship between gas

velocity and wear rate, as shown in Figure 8-4, Figure 8-5 and Figure 8-6, respectively.

Figure 8-4 Relationship between Dust Concentration and Wear Rate

Figure 8-5 Relationship between Dust Particle Size and Wear Rate

Figure 8-6 Relationship between Gas Velocity and Wear Rate


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Figure 8-4 and Figure 8-5 indicate that the wear rate increases linearly with the dust

concentration and the dust particle size increasing in the range of the test conditions. Figure

8-5 suggests that erosion also occurs under high dust concentration, even if dust particle size is

very small. Figure 8-6 shows that the wear rate is in proportion to the 3.8th power of gas

velocity. Therefore, it is to be desirable that the gas condition reaching catalyst have a low dust

concentration, small dust particle size and low gas velocity in order to prevent catalyst erosion,

when designing DeNOx system.

The following can be concluded based on the results of analysis of coal ash and wear test

described above, and also JGC C&C's commercial experience:

1) The influence of Indian coal ash on erosion of DeNOx catalyst could be significant, since the

particle size of Indian coal ash is larger than that of Japanese coal ash, and contains a lot of

large particles of over 50 μm.

2) If dust is be removed by MC and dry FGD combined system or ESP, since dust concentration

would be 10 mg/Nm3 and only fine particle would remain after removing large particles,

influence of dust on catalyst erosion can be considered slight.

3) Actually, in the commercial experience of JGC C&C, catalyst erosion by dust is negligible if

the dust concentration is the same level as above and in the range of SCR design gas

velocity (2-3 Nm/s).

4) For a high dust concentration of 100 g/Nm3 without dust removal, wear rate is assumed as

several times that in the case of 20 mg/Nm3 by extrapolation. However estimation of

erosion is difficult, since erosion and plugging will occur partially and simultaneously.

5) Normally flue gas dust concentration in coal-fired TPPs in Japan is approximately 20 g/Nm3.

DeNOx catalyst manufactured by JGC C&C for coal-fired TPP is adjusted for less than 14%

of wear rate in the standard wear test conditions, and its mechanical life is 4-6 years.

The catalyst sample used for this wear test is the grade for low dust concentration conditions,

and its wear rate is about twice that of the grade for coal-fired TPP. However, erosion by dust

could be assumed negligible because dust concentration of commercial and demonstration

plants is 3 orders of magnitude lower than that in Japan. Therefore, 4-6 years of mechanical life

is expected.

8.4 Design information of DeNOx catalyst

The specification of DeNOx catalyst designed based on the design conditions for commercial and

demonstration plants is shown in Table 8-4.


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Table 8-4 Design Condition and Specification of DeNOx Catalyst

1) Inlet Gas Condition Commercial

Plant Demonstration

Plant

Flow Rate Nm3/h 2,300,000 5,000

Temperature ℃ 270

Gas Composition

O2 vol% 3.3 - 4.5

CO2 vol% 15 – 16

H2O vol% 10

N2 vol% Balance

NOx mg/Nm3 600

SOx mg/Nm3 100

Dust mg/Nm3 30

2) Requirement Commercial

Plant Demonstration

Plant

Outlet NOx mg/Nm3 100

Leak NH3 ppm ≦ 5

Life time year 2 1

3) Specification Commercial

Plant Demonstration

Plant

Catalyst Type - Honeycomb

Catalyst model - NRU-5

Cell Number - 35

Catalyst Section Size mm x mm 150 x 150

Number of Catalyst - 100 25

Number of Module - 80 1

Number of Layer - 2 2

Catalyst Length mm 905 560

Catalyst Volume m3 325.8 0.63


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9. Outline of New Environmental Norms and Status

The related information of power generation industry in India, such as the actual state of

energy consumption, the new environmental norms issued by MoEF&CC in December 2015 is

described in this chapter. In addition, the status and challenges of complying with the new

environmental norms are also described.

9.1 Background of Energy Sector in India

Build-up of installed generating capacity as of March 2017 in India is shown in Figure 9-1.

60% of the installed capacity was coal based as well as 86% of the generation was thermal.

This indicates that India’s energy sector is highly dependent on this fossil fuel both as a source

of heat as well as electricity. The contribution of renewable energy to total electricity

generation will remain lower than the generation from coal based power plants. The coal

based power plant will continue to serve the base load as well as a large portion of the total

load.

Figure 9-1 Build-up of Installed Capacity

(Source: CEA, Installed Capacity and Executive Summary Reports)

Figure 9-2 shows growth of annual energy requirement in India. Annual energy requirement

was increased in the past 10 years at a CAGR of 5.2 % and that of 2016-2017 was 1,143 Billion

kWh.

Figure 9-3 shows growth of annual coal consumption in power sector in India. Annual coal

consumption was increased in around 10 year (from 2004-2005 to 2015-2016) at a CAGR of

6.33% and that of 2015-2016 was 546 million tons. This fact assumes that the capacity of coal-

fired TPP was increased with the energy requirement.


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Figure 9-2 Growth in Annual Energy Requirement

(Source: CEA, Power Supply Position Reports)

Figure 9-3 Growth in Annual Coal Consumption in Power Sector

(Source: Coal Directory of India, Coal Controller’s Organization, Govt. of India)

As can be seen in Figure 9-4, total installed capacity has increased at a CAGR of 7.62%

between 2007 and 2017 with maximum growth in renewable energy installation at a CAGR of

22.4%, followed by thermal capacity at a CAGR of 9.26%. Despite high growth, the total

installed capacity of renewable energy is very small (only 18 % of total capacity) as compared

to thermal capacity (67 % of total capacity).


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Figure 9-4 Installed Generating Capacity in India

(Source: CEA, Installed Capacity and Executive Summary Reports)

9.2 Outline of New Environmental Norms

Through “Draft National Electricity Plan” issued by Ministry of Power (MoP) and the “19th

Electric Power Survey Report” issued by CEA, the current situation and issues related to new

environmental norms were observed as follows:

Capacity addition during the period of 2017-2022 will be limited to 56,400 MW of coal power

and 38,040 MW of gas and hydro power.

As for the requirements by new environmental norms, complying with norms with the

currently set time frame might be difficult for due to technical/financial/regulatory

constraints.

PLF is forecast to vary between 50% and 60% depending on electric requirement and new

capacity addition from fossil or non-fossil fuel.

Coal demand is forecast to be 730~800 million tons in 2021~2022.

Target share of renewable energy is set to be 20% by 2021~2022.

47% out of the entire added capacity up to March 2022 is to be non-fossil based.

Coal fired power stations shall be required to play a role in addressing the requirement of

flexible operation in response to the system fluctuations that are to be caused by massive

introduction of renewable energy. However, basically gas and hydro should undertake the

major role of flexibilization, to the extent possible.

New technology with as high-efficiency and low environmental impact will be installed for

TPP.


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To further reduce other harmful emissions from TPPs, MoEF&CC has also issued the Norms,

new and more stringent environmental norms in December 2015, regarding emission of SPM,

SOx, NOx and Mercury (refer to Table 9-1). Norms for specific water consumption by TPPs have

also been notified to conserve water (refer to Table 9-2).

Table 9-1 New Emissions Norms Notified on 7 December 2015

Installed before 31st Dec 2003 Installed in Jan 2004-Dec 2016 Installed from Jan 2017 onward

capacity MW Less than 500 500 and above Less than 500 500 and above

SPM mg/Nm3 100 50 30

SO2 mg/Nm3 600 200 600 200 100

NOx mg/Nm3 600 300 100

Hg mg/Nm3 Not regulated 0.03 0.03 0.03

(Source of Reference data: CEA)

Table 9-2 New Water Norms Notified on 7 December 2015

MoEF&CC Water Norms for TPPs

1. All plants with Once Through Cooling (OTC) shall install Cooling Tower (CT) and

achiever specific water consumption up-to maximum of 3.5 m3/MWh within a period of 2

years from the date of publication of this notification.

2. All existing CT based plants shall reduce specific water consumption up to maximum of

3.5 m3/MWh within a period of 2 years from the date of publication of the notification.

3. New plants to be installed after 1st January 2017 shall have to meet specific water

consumption of 2.5 m3/MWh and achieve zero waste water discharged.

(Source of Reference data: CEA)

9.3 Present Status of TPPs and Corresponding Status to New Environmental Norms

JCOAL conducted an interview at TATA power and two other utilities to analyze coal and flue

gas properties for understanding their environmental measures and corresponding status. In

this chapter, the results are described.

9.3.1 Coal Properties Survey

Coal properties from two TPPs owned by TATA Power, one state utility and one private utility

are listed in Table 9-3. Properties of Grade standards (Grade-C, -D and –E) are also listed to

compare with the data obtained from power plants.


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Table 9-3 Coal Properties

Max. Min. Ave.


G6‐8 G8‐11 G11‐14

Gross air dried Kcal/ kg 4474 3283 4671 5707 3750 4561 3731 3500 3655 3646 5880 5640 4943

Total Moisture % ar 4.05 12.50 7.11 16.72 4.1 5.95 10.8 12 11.65 12 6.1 6.6 5

Moisture % ad 1.06 5.43 5.63 0.97 1.44 4.9 4.3 3.4

Ash Content % ad 41.72 45.15 36.19 49.72 29.52 40.71 33.76 41.2 36.66 33.52 10.6 16.4 25.5

Volatile Matter % ad 19.03 22.87 15.92 23.71 13.56 16.51 26.61 21.56 24.4 21.4 32.2 29.3 28.1

Fixed Carbon % ad 38.19 26.55 40.78 52.51 31.05 41.34 28.83 25.5 27.25 52.2 50 43

Total Carbon Content % daf 47.84 61.4 40.8 48.58 40.34 35.87 40.58 38.3 77.06 78 76.17

Total Hydrogen Content % daf 2.89 3.58 2.81 3.15 2.61 2.66 2.46 3.7 4.6 4.71 4.87

Total Nitrogen Content % daf 1 1.07 0.25 0.61 0.97 0.72 0.85 0.96 1.76 1.68 1.63

Total Sulphur Content % daf 0.39 0.93 0.3 0.52 0.63 0.59 0.31 0.46 0.3 0.38 0.51

Oxygen Content (diff.) % daf 4.58 13.414 3.909 6.07 10.8 12 6.98 16.38 15.3 16.89


Mercury in coal mg/kg 0.045 0.013 0.049

SiO2 % db 64.45 50.46 59.43 57.2‐63.8 59.7 56.26 44.3 52.6 69.04

Al2O3 % db 33.32 22.08 27.13 26.7‐31.8 28.35 27.71 26.72 27.31 22.54

Fe2O3 % db 15.44 3.49 6.63 2.0‐7.2 4.1 7.14 16.3 13.5 3.11

CaO % db 2.32 0.08 0.82 1.1‐1.6 2.05 0.66 5.1 1.56 0.8

MgO % db 1.44 0.32 0.59 0.4‐1.0 1.5 0.66 0.81 0.37 0.53

Na2O % db 5.41 0.062 0.79 NA 2.37 0.02 0.03 0.04

K2O % db 2.05 0.946 1.41 NA 1.22 0.46 0.49 1.04

TiO2 % db 2.102 1.46 1.72 1.0‐1.5 0.02 2.14 1.8 1.49

Mn3O4 % db

P2O5 % db 0.951 0.241 0.56 0.2‐0.8 0.9 0.04 1.89 0.98 0.1

SO3 % db 1.28 0.09 0.27 Traces 0.35 0.2 1.93 0.8 0.49

MnO % db 0.23 0.037 0.08 0.15

V2O5 % db 0.04 0.03 0.03

Li2O % db

Grade Standard

Grade‐C Grade‐D Grade‐E

State Private

CCL

Design Actual Design Actual

ASH ANALYSIS

Source CCL, BCCL

Actual DesignActual

CALORIFIC VALUE

CHEMICAL ANALYSIS

ULTIMATE ANALYSIS


Items＿＿_____＿＿＿＿＿＿＿＿＿

＿


MCL: Mahanadi Coalfield Ltd, CCL: Central Coalfield Ltd, BCCL: Bharat Coking Coal Ltd, SECL: South

Eastern Coalfield Ltd、WCL: Western Coalfield Ltd、Middling: Washed coal

While analytical items were different by TPP, their Gross Calorific Value (GCV), ash content

and sulphur content were in range of 3,000~4,500 kcal/kg, 30~50% and 0.3~1.0%, respectively.

Typically, G12 to G14 grade coal is used for a TPP in India, these data show typical thermal

coal grade except two points from Jojobera middling coal and max. quality of MPL (Maithon

Power Limited). Relationship between GCV and ash content and sulphur content are indicated

in Figure 9-5 and Figure 9-6, respectively. JCOAL’s in-house data is also plotted in the same

figures to show the quality of coal used at TATA power. The maximum quality of MPL showed a

G6 grade in terms of GCV, but ash and sulfur levels are greater than those of grade standard

(Grade D) plotted as green circles.


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0

10

20

30

40

50

60

2000 2500 3000 3500 4000 4500 5000 5500 6000

Ash

(%)

GCV (kcal//kg)

AshContent

ReferencesG12G13G14

Figure 9-5 Relation between GCV and Ash Content

(Source of Reference data: JCOAL)

0

0.2

0.4

0.6

0.8

1

1.2

2000 2500 3000 3500 4000 4500 5000 5500 6000

Sulp

hur

(%)

GCV (kcal//kg)

SulphurContentReferences

G12G13G14

Figure 9-6 Relation between GCV and Sulphur Content

(Source of Reference data: JCOAL)

Because the ranges of volatile matter and fixed carbon show characteristics of bituminous coal,

GCV is inversely proportional to ash content. A wide range of GCV is presumed to be influenced

a fluctuation of received coal quality.

Regarding ash properties, levels of SiO2 and Al2O3 are relatively high. Its abrasive behavior

might cause erosion of boiler inner parts and flue gas section. Slagging Index (SI) calculated

form ash analyses were 0.02-0.07 (standard samples 0.03-0.08) and Fouling Index (FI) were 0-

0.34 (standard samples 0-0.01). These values show quite good aspects regarding less fouling and


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higher heat transfer on the boiler surface. Mercury levels in coal have not been provided from

TPP, standard samples were analyzed and found that mercury levels were around 0.03 mg/kg.

This value is almost equal to the Norms’ level (refer to Table 9-1) and considered to be

sufficiently low, since mercury is normally trapped through ESP.

9.3.2 Flue Gas Properties Survey

Table 9-4 and Figure 9-7 show flue gas properties which calculated by coal properties shown in

Table 9-3 with based on 6% of excess O2. PM concentration was calculated as conditions at the

upstream of ESP. NOx concentration was not estimated since NOx concentration is mainly

influenced by combustion condition of a boiler. The calculated SOx concentrations were higher

than the Norms’ level. This result presumes that TPPs shown in Table 9-4 required FGD

technology to comply with the Norms. The calculated PM at inlet of ESP is in the range of

20~24 g/Nm3 for Maithon Power Limited, and that of outlet is decreased to less than 50

mg/Nm3. Thus, ESP shows good performance.

Table 9-4 Calculated Date of Flue Gas based on Coal Properties

Max. Min. Ave.


Gross air dried Kcal/ kg 4474 3283 4671 5707 3750 4561 3731 3500 3655 3646

Total Moisture % ar 4.05 12.50 7.11 16.72 4.1 5.95 10.8 12 11.65 12

Moisture % ad 1.06 5.43 5.63 0.97 1.44

Ash Content % ad 41.72 45.15 36.19 49.72 29.52 40.71 33.76 41.2 36.66 33.52

Volatile Matter % ad 19.03 22.87 15.92 23.71 13.56 16.51 26.61 21.56 24.4 21.4

Fixed Carbon % ad 38.19 26.55 40.78 52.51 31.05 41.34 28.83 25.5 27.25

Total Carbon Content % daf 47.84 61.4 40.8 48.58 40.34 35.87 40.58 38.3

Total Hydrogen Content % daf 2.89 3.58 2.81 3.15 2.61 2.66 2.46 3.7

Total Nitrogen Content % daf 1 1.07 0.25 0.61 0.97 0.72 0.85 0.96

Total Sulphur Content % daf 0.39 0.93 0.3 0.52 0.63 0.59 0.31 0.46

Oxygen Content (diff.) % daf 4.58 13.41 3.91 6.07 10.8 12 6.98


Mercury in coal % dbCalculated dataFlue gas (Excess O2 = 6%) Nm3/kg‐fuel 0 0 17 21 15 17 14 12 14 15SOx mg/Nm3 460 890 406 602 917 963 441 604PM g/Nm3 21 24 20 24 25 34 26 22

ULTIMATE ANALYSIS

Design Actual

Source CCL, BCCL

CALORIFIC VALUE

CHEMICAL ANALYSIS


Items＿＿_____＿＿＿＿＿＿＿＿＿＿

TATA PowerJojobera Maithon Power Limited Sate Private

Actual DesignActual

Design Actual

CCL


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0

200

400

600

800

1000

1200

0 5 10 15 20 25 30 35 40 45

SO2

(cal

c.)

(mg/

Nm

3)

PM (calc.) (g/Nm3)

Coal data

References

grade_standard

MPL(Calculated)

MPL(Actual)

Jojobera(Actual)

Figure 9-7 Relation between Calculated Value of PM and SO2 Concentration

Table 9-5 shows actual flue gas data of TATA Power Jojobera and MPL, and other private

power plant as reference. The criteria of each unit are also shown in the same table. A green

column means sufficiently lower than the Norms’ level, yellow means close to the Norms’ level

(>90%), red requires countermeasures for reducing NOx and SOx to satisfy the Norms’ level.

Actual SO2 concentration agreed with calculated value.

Table 9-5 Data of Actual Flue Gas

Private

Unit‐1 Unit‐2 Unit‐3 Unit‐4 Unit‐5 Unit‐1 Unit‐2

Gas Temperature deg C 127 133 138 127 133 136 137 110‐135

O2 Concentration % dry 7.2 7.4 7.2 6.8 7 8.8 7.7 5.5‐6.5

Exces Air Ratio ‐ 35

H2O Concentration % wet 6.86 7.63

CO2 Concentration % dry 11.4 11.8 11.6 11.8 11.8 10.6 11.6 13 ‐ 15

NOx Concentration mg/Nm3 322.8 334.7 326.2 297.3 290.3 405 446 250‐400

SOx Concentration mg/Nm3 563.6 577.2 572.3 524 534.9 827 793 550‐800

Dust Concentration mg/Nm3 74.5 74.7 74.6 49.5 49.6 48.9 25.8 40‐70

Hg Concentration mg/Nm3 <0.1 <0.1 <0.1 <0.1 <0.1 <0.01 <0.01

Load MW 54 120.31 107.46 119.8 119.59

NOx mg/Nm3 600 600 600 600 300 300 300 300SO2 mg/Nm3 600 600 600 600 600 200 200 600SPM mg/Nm3 100 100 100 100 50 50 50 50Hg mg/Nm3 0.03 0.03 0.03 0.03


Items＿＿_____＿＿＿＿＿＿＿＿＿

TATA Power Jojobera Maithon Power Limited

Criteria

9.3.3 Corresponding Status for New Environmental Norms

Corresponding status for the Norms was investigated by interviewing TPPs, Indian government

and CEA. The results are summarized in this chapter.


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9.3.3.1 Corresponding Status for New Environmental Norms

CEA has conducted various meetings with Regional Power Committees (RPCs) and power

utilities to implement the Norms in the earliest possible time. Per directions of MoP CEA has

prepared a phasing plan for implementation of the Norms for 2018-2022 as shown in Table 9-6.

From this phasing plan, approx. 66 GW (222 units) capacity has been agreed for enhancement

of ESPs, while approx. 161 GW (414 units) capacity has been agreed for installation of FGD

system to correspond to new SOx norms. Though DeNOx technology has not demonstrated in

India, NTPC has been initiating pilot projects to establish suitability of SCR/SNCR systems for

Indian coal with high ash content.

Table 9-6 Phasing Plan by CEA

Year NOx SOx SPM

Capacity (MW) Units Capacity (MW) Units Capacity (MW) Units

2018

Pilot project by NTPC is underway. Phasing Plan for DeNOx will be finalized in 2018

500 1 500 1

2019 4,940 8 1,300 2

2020 27,230 55 10,705 28

2021 64,027.5 172 23,495 97

2022 64,704.5 178 28,525 94

total 161,552 414 65,925 222

(Source: CEA)

Though a huge demand for FGD installations were created, the Norms provide a limited

timeframe as well. Most of the existing and incoming capacity have to be ready for complying

with the Norms’ level. Manufacture capacity is also concerned since an annual requirement of

FGD is more than 170 units in the period of 2021 and 2022. The foregoing gives so much

financial constraints to utilities. Naturally, there are concerns that required huge capital

investment may incur impact on electricity tariff.

9.3.3.2 Corresponding Status with Respective Items

Suspended Particulate Matter (SPM)

As shown in Table 9-7, 273 units of 72,659 MW is deemed to require ESP enhancement. In

2018-2022, utilities are required to implement ESP enhancement at 231 units (85% out of 273

units) of 65,925 MW (90% out of 72,659 MW).

As countermeasures for retro-fitting of ESP, replacement of ESP or introduction of bug filters,

etc. are required. In some cases layout change may be also required at existing units.


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Table 9-7 Units require ESP Enhancement

Number of Units Installed Capacity (MW)

Grand total required for ESP modification 273 72,659

Grand total required for ESP modification in 2018-2022 231 65,925

Sulphur Oxide (SOx)

For all categories of existing/incoming TPPs, FGD system is required to satisfy the Norms’ level

of SOx. Major issues and barriers for FGD installation are as follows:

Issue of space constraints

Availability of good quality limestone and disposal of gypsum

Availability of adequate number of qualified vendors to cater such large capacity in the

limited time frame.

Increased Auxiliary Power Consumption due to installation of FGD system.

As shown in Table 9-8, 482 units of 170,931 MW is deemed to require FGD installation. In

2018-2022, utilities are required to implement FGD installation at 415 units (86 % out of 482

units) of 925 MW (95 % out of 170,931 MW).

Table 9-8 Units require FGD installation

Number of Units Installed Capacity (MW)

Grand total required for FGD installation 482 170,931

Grand total required for FGD installation in 2018-2022 415 161,552

TPPs having capacity of 500 MW and higher are considered space provisions for FGD

installation, supply and transport of limestone. The requirement for limestone is estimated to

be 30 million tons/year for the Indian total electrical capacity of 250 GW. In addition, gypsum

will be generated as a byproduct from FGD unit, and total generation is estimated to be around

42 million tons/year for a capacity of 250 GW. Increased auxiliary power consumption by

installation of FGD was estimated as 1.0-1.5 % as unit efficiency.

Nitrogen Oxide (NOx)

The proposed standards of 600 mg/Nm3 would require combustion optimization, use of low NOx

burners and over-fire air (OFA) systems in the boilers.

In the meantime, to comply with the regulated value of 300 mg/Nm3 or 100 mg/Nm3,

introduction of equipment such as SCR, SNCR, etc., for appropriate DeNOx process will be

required. However, it is to be noted that the globally available SCR systems are yet to be proven

on Indian coal with high ash levels. Also, there are concerns about increased auxiliary power


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consumption due to installation of DeNOx system.

Mercury

Globally, no established technology is available for mercury removal from flue gas. However, it

is worth noting that other environmental equipment, such as ESP, FGD, SCR, etc., currently

provides a co-benefit by mitigating mercury emissions.

9.4 Challenges in Complying with New Environmental Norms

9.4.1 Challenges in Complying with SOx norms

Before the Norms were issued, India had no national norms for SO2 emissions. Although SO2

monitoring is a fairly standard practice in private and centrally owned TPPs, most of these

units do not have any SO2 removal technology. As a result, the Indian power sector’s

experience in FGD technologies is limited. The SO2 emission norms of 600/200 mg/Nm3 for

existing power plants are more relaxed than those of other countries (China: 100 mg/Nm3, US:

100 mg/Nm3), particularly in view of the fact that Indian coal has much lower sulfur content

than imported coal. Nonetheless, there are two main barriers, space and financial constraints,

for FGD installation.

Space Constraints

FGD is the most popular and acceptable technology to remove SO2 and will be required to

comply with the Norms. Space is required for FGD equipment, and storage for limestone (used

in scrubbing) and gypsum (a byproduct). The CEA report described that TPP with a capacity

of 500 x 2 MW requires 28,500 m2 of land for limestone-based Wet-FGD. The power plants

where seawater is available, the space requirements for FGD are reduced by about 30 %.

Indian TPPs with a capacity of less than 500 MW installed before 2003 will find it difficult to

acquire the land required for FGD. Even if these units are able to find funding to install FGD,

they may not be able to take any action due to space constraints. However, Indian TPPs with

a capacity of larger than 500 MW may not face space constraints, as provisions (generally

such spaces are provided between the ID fan and stack) were already made as part of their

standard design practice.

Financial Constraints

The cost estimation for Wet-FGD installation in India is provided in Table 9-9. For reference,

comparison of FGD technologies by NTPC is indicated in Table 9-10. If full pass through of

the cost is not permitted in the tariff or the MoP does not provide a subsidy, plant owner will

find it difficult to manage finance because they are already suffering from the financial crisis

due to delays in plant commissioning on account of land and power evacuation issues, etc.

This will reopen their Power Purchase Agreement (PPA) and other contracts. Per CEA


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assessment, there are 27 units that are more than 30 years old, with a total capacity of 5,301

MW that might get impacted due to this factor.

Table 9-9 Cost Estimation of Wet-FGD in India

Wet FGD system Seawater FGD system

Capital cost, US$/MW 90,910 70,300

Fixed operating costs, cents/MWh 37.9 28.8

Variable operating costs, cents/MWh 0 0

Auxiliary consumption, % 1.5 1.25

FGD efficiency, % 90 90

(Source: Disease Control Priorities Third Edition, Injury Prevention and Environmental Health [2016])


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Table 9-10 Comparison of FGD Technologies Wet FGD Dry FGD

Commerciallyavailable range

~ 1,100 MW 300~400 MW single absorberFor novel integrated desulphurization(NID) each module of 75MW

Types 1) Seawater2) Freshwater

1) Spray dry absorber (SDA)2) Circulating dry absorber3) NID.

SO2 removalefficiency

Upto 99 per cent Upto 99 per cent (90~95 per cent forSDA)

Capital cost 1) Seawater FGD: ~40 lakhs/MW2) Freshwater FGD: ~50 lakhs/MW

~35 lakhs/MW

Sorbent 1) Seawater FGD: No sorbent2) Freshwater FGD: CaCO3

CaO/Ca(OH)2

Sorbent use Approximately 1.5~2 tonne limestoneconsumed per tonne SO2 removal

Approximately 0.75~1.5 tonne limeconsumed per tonne SO2 removal

Sorbent cost(Rs/tonne)

~2000 ~6000

Water consumption

in m3/MWh0.2~0.25 m3/MWh for power plantsbetween 200~500MW;

0.25~0.3 m3/MWh for power plantsbetween 50~200MW;

0.3~0.45 m3/MWh for power plantsbetween 50~70MW

0.1~0.2 m3/MWh for power plants up to200MW.The semi dry system is not recommendedfor power plant > 200MW

Auxiliary powerconsumption

1) Seawater FGD: 0.7~1.5 per cent2) Freshwater FGD: 0.7 per cent

1~2 per cent

Condition ofexixting stack

Existing stacks to be modified in allcases

Existing stackes can be used withoutmodification

FGD by-product 1) Seawater FGD: No by-product2) Freshwater FGD: gypsum

CaSO3/CaSO4: Has to be landfilled

Waste water Generates Doesn't generate

Erection period Up to 50MW: 12~14months50~200MW: 14~18months200~500MW: 18~24months>500MW: 24~30months

Up to 50MW: 12~14months50~200MW: 14~18months

Downtime Up to 50MW: 2~3weeks50~200MW: 3~4weeks200MW and above: 4~6weeks

4~6 months (due torenovation/modification in existing PMcontrol equipment such as bag filter/ESP)

Source: NTPC

*Assuming sulphur content of 0.5 percent in coal and stoichiometric consumption of sorbents.

9.4.2 Challenges in Complying with NOx norms

Prior to December 2015, there were no national emission norms for NOx. Most of the existing

units monitor their NOx emissions, but almost none of them have DeNOx technologies (SCR

or SNCR). Prior to the Norms, NOx was removed either under Environmental Clearances

(EC) or Consent to Establish (CTEs) issued by State Pollution Control Board (SPCBs), or by

the TPPs themselves. NOx can be decreased or removed, either by process and equipment

modifications (such as air staging, fuel staging or flue gas re-circulation) or by using end-of-

pipe technologies (such as SCR or SNCR). NTPC, Central Electricity Regulatory Authority


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(CERC), CEA and other key stakeholders have the view that the Indian TPPs will have

difficulties to comply with the Norms without major investments in either installing DeNOx

technologies or making major changes in the firing system (burner houses or low-NOx

burners).

The barriers to install DeNOx technologies are space, financial constraints and technological

availability

Space Constraints

Compared to FGD, DeNOx technologies do not require a huge area, but the installation of

DeNOx system in existing TPPs will generally require modifications in the plant’s technical

makeup as well as other site-related changes. Thus, for NOx, space is not a major challenge,

but changes in plant layout (such as pipelines for fuel and air) in existing TPPs will be

difficult. Though DeNOx system is generally installed between economizer and GGH due to

the high operating temperature of DeNOx system, installation of DeNOx system is difficult by

space constraint. Some of the TPPs under construction may also require changes in layout

and some re-engineering of the pipeline design, however there may not be more difficult than

that of existing TPPs.

Financial Constraints

NTPC, CEA, CERC and other key stakeholders estimate that the indicative capital costs for

installing DeNOx technologies will mean capital costs in the range of $0.02 million per MW

and an operating cost of $3.7~$4.4 million per year for a 500 MW unit. This will impact the

finances of plants and plant owners will request for amendments to existing contracts (PPA,

financing, etc.). Moreover, it will be very difficult for units that are near the end of their lives

to make this investment.

Technological Challenges

SCR and low-NOx burner technologies are the most popular technology worldwide to remove

NOx, however these technologies are fairly un-tested for Indian coal and under Indian TPP

conditions in general. If for some reason, imported DeNOx technology does not yield

satisfactory results in India, this will become a serious technology issue and will considerably

delay complying with the Norms.

9.4.3 Challenge Level in Complying the New Environmental Norms

The Norms have put the Indian power sector, which already has stressed cash flows, lack of

space, short plant life (especially TPPs owned by State), in a difficult position.


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Table 9-11 shows the analysis of the severity of key challenges in meeting the SOx emission

norm. A green column means sufficiently low to meet the Norms’ level, yellow means close to

the Norms' level, red requires measures for DeSOx technologies to meet the Norms’ level.

Most of the units with capacities greater than 500 MW have either already made space

provisions for FGD, or have FGD planned in the coming years. Hence, space is not a major

challenge for these units. However, all the units with capacity less than 500 MW face severe

space constraints. Though FGD is a fairly common technology outside of India, it is untested

for Indian coal and Indian conditions. In addition, a shortage of equipment suppliers in India

and consequently capacity building and financial constrain are also major challenges.

Table 9-12 shows the analysis of severity of key challenges in meeting the NOx emission

norm. A green cell means sufficiently low to meet the Norms’ level, yellow means close to the

Norms’ level, red requires measures for DeNOx technologies to satisfy the Norms’ level.

Constraints of space and finance are challenges for existing TPPs as well as the case of SOx.

In addition, there is a technical challenge that major DeSOx technologies have not been

demonstrated in India.

Table 9-11 Overall Severity Matrix for SOx Emissions

Capacity(MW)

Installedbefore2003


Underconstruction


< 500

≥ 500

< 500

≥ 500

< 500

≥ 500

< 500

≥ 500

< 500

≥ 500

Space

Financial

Technology


Capacity Building

Green: sufficiently low, yellow: close, red: requires countermeasures to meet the Norms’ level


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Table 9-12 Overall Severity Matrix for NOx Emissions

Installedbefore2003


Underconstruction


Space

Financial

Technology


Capacity Building

Green: sufficiently low, yellow: close, red: requires countermeasures to meet the Norms’ level

9.5 Latest Situation of Interactions about New Environmental Norms

The latest situation of interactions on the Norms between policy makers involving utilities

and power companies is summarized in this chapter. The situation was researched by

interviewing the following relevant stakeholders on February 13-14, 2018:

Political side: Central Electricity Authority (CEA)

Industry side: NTPC

Electrical Consulting: STEAG Energy Service India Ltd.,

Think tank of environment: Centre for Science and Environment

9.5.1 Present situation for New Environmental Norms

Timeframe to comply with the Norms

Under the Norms, the timeframe given for power plants that had commercial operation date

after 2003 was two years (i.e., by the end of 2017). In the meantime, even before the Norms

were issued, there were concerns about the difficulties to comply with the foregoing timeframe

in terms of not only the required time period for the basic study and tender processes but also

other administrative procedures as well as limited supply capacity of vendors with appropriate

technology. Thus, the power sector stakeholders have been firmly committed to make their

utmost efforts to comply with the Norms.

Interactions between the relevant government institutions and observed interim outcomes

The major actions and interactions between the government institutions between mid-2016 and

late 2017 are summarized in below.

- MoP organized a committee under the Chairmanship of Chairman, CEA to prepare an action

plan for implementation of the Norms.

- MoEF&CC convened a meeting that was participated by CEA, NTPC and CPCB (Central


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Pollution Control Board).

- MoP informed MoEF&CC, in writing, of the concerns of various power sector stakeholders

concerning the requirements by the Norms on PM, SO2 and NOx emissions. The concerns

expressed by MoP were roughly as follows:

Out of presently installed capacity, approx. 60 % meets the new PM norms with

existing facilities. For the remaining 40 % to comply with the Norms, complete

shutdown of 4-6 months for each unit is required, which may affect the sustainability of

power supply.

As for compliance with the requirement of SO2, besides the time constraint, there are

technical challenges about design and engineering, approvals as well as funds

arrangements, tender and commissioning process. Required plant shutdown and

availability of technologies/suppliers may also cause another concern.

In order to comply with NOx, utilities may be required to install at their units

regulated by the Norms SNCR or SCR, while either technology is yet to be proven on

Indian coals.

In consideration of the all foregoing, it may be advisable for the regulator to extend the

timeframe up to 2014 for 146 GW units to install SCR/SNCR to comply with the

Norms.

It is to be requested that the plants installed before December 31, 2003 to be allowed to

have another three years to achieve specified standards of 600 mg/Nm3. Relaxation of

600 mg/Nm3 instead of 300 mg/Nm3 and 300 mg/Nm3 in place of 100 mg/Nm3 is also

requested for rest of the plants.

The compliance period of SPM for the plants to install FGD is suggested to be kept per

the phasing plan prepared by CEA.

- MoEF&CC deemed that the proposed time period of seven years for FGD installation plan

suggested by MoP is too long and that measures for all pollutants to comply with the

Norms shall be taken between 2018 and 2022.

- MoP provided the revised plan with compliance period up to 2022. Number of units with

planned ESP installation in the plan was 231 units (64.5 GW) out of 273 units, while that of

units with planned FGD installation was 415 units (161.4 GW) out of 482 units.

- CEA reported to MoP on the matters of concern with regard to the required compliance with

the Norms within the given time period and at the same time provided the complete list of

all-India power plants that indicates whether ESP/FGD installation is planned/not viable

at each unit.

- The matters of concern mentioned were as follows:

Chimney Height

The lining of existing stacks, which is required for FGD installation generally, will

require very long shut down of units that may impact adversely the power supply as


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well as revenues of the power plants. If MoEF&CC allows shorter stacks for those

environmentally compliant units, the same could be constructed in parallel to FGD

installation without shutdown of the unit for such longer duration.

Seawater based FGD

The revised standards in the Norms regarding water consumption do not make any

distinction between seawater based power plant and sweet water based power plant.

While seawater plant by itself may not meet the Norms, it is clear that seawater based

FGD is the best possible solution for SOx removal in such plants. There should be

amendments exempting power plants with seawater based FGDs from the Norms.

Regulatory issues

Many utilities have filed petitions with their respective Regulatory Commissions for

tariff revision on account of cost incurred for FGD installation, etc. The same are

pending with the regulators so far and may take significant time if without any special

policy measures are taken. In this regard, regulators are requested to give in-principal

approval to the foregoing requests by utilities. Actions by MoP are urgently required in

this regard.

Financing

State and other utilities may not be able to invest the huge capital required for meeting

the Norms considering their poor financial health. They are continuously requesting

funds from the National Clean Energy Fund (NCEF) and Power Sector Development

Fund (PSDF).

Vendors

A huge demand for installation of FGDs shall be created simultaneously in a short

period as most of the existing capacity and capacity under construction have been

provided with a limited timeframe to meet the Norms. There may be bottlenecks in

timely supply of equipment and installation.

- CPCB informed to MoEF&CC that any and all power plants shall have to comply with the

Norms by 2022, after which any plant that is not compliant must be shut down.

9.5.2 Short Summary

From the objective view, the period limitation, which is by 2022, is a strict target to comply with

the Norms. However, there are possibilities to drive forward this commitment.


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10. Market Information

Market survey and market analysis for the DeSOx and DeNOx system in India based on the

latest local information are described in this chapter. In addition, the related information, such

as technology suppliers for DeSOx and DeNOx system and their experience, are also described.

Availability of raw material for producing the desulfurizing agent for dry FGD system is also

included.

10.1 Market Survey of DeSOx and DeNOx system

Results of market survey for DeSOx and DeNOx system in India is summarized as following.

As reported in Chapter 9, MoEF&CC notified fairly stringent new emission norms for TPPs in

December 2015 (refer to Table 9-1 and Table 9-2). The Norms have been made retroactive (e.g.,

they cover all power plants in operation irrespective of their date of installation).

The potential market of FGD and SCR can be divided in three categories from the perspective of

challenges in compliance with the norms:

(a) New TPPs about 64 GW capacity

TPPs under planning, designing and construction will have comparatively the fewest

difficulties in meeting the Norms

(b) Existing TPPs (environmental facility can be installed) about 122 GW capacity

Existing TPPs which can implement environmental facility may have finance and other

technical issues

(c) Existing TPPs (environmental facility cannot be installed) about 72 GW capacity

Existing TPPs which cannot comply with the Norms due to non-availability of space or

finance, or short residual plant life

The potential market of FGD and SCR in India appears to be 186 GW of electrical capacity

which is total capacity of category (a) and (b), excluding category (c). 186 GW of FGD market is

about 13 % of the total world market. Out of 186 GW of total Indian market, 122 GW (capacity

of category (b)) is ready market and 64 GW (capacity of category (a)) will come in the next 10

years. It is estimated that more than 10 years are required to comply with the Norms by

installation of FGD and SCR for the total potential market due to the limitation of manufacture

capacity of equipment supplier.

From the recent National Electricity Plan issued by CEA in 2016, installation of new TPP is not

planned after 2027. Per the generation planning of India, renewable energy and nuclear energy

are going to substitute the coal based capacity in India. However, it will be difficult to have no

new coal capacity in spite of having large coal reserve. Therefore, the coal based power plant

will continue to serve base load as well as a large portion of the total load. However, it will be


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difficult to phase out 72 GW (category (c)) soon. Thus some form acceptance of phasing plan of

72 GW capacity and more relaxation in time in adherence to the Norms are expected from

MoEF&CC.

10.1.1 Category (a): Installation of DeSOx and DeNOx system to New TPPs

As the potential market of DeSOx and DeNOx system, the list of new TPPs under planning or

under construction which will be operated by 2021 is indicated in Table 10-1 with the status of

FGD installation. As described above, the total capacity is about 64 GW. Most of the listed TPPs

have indicated the Wet-DeSOx process (limestone process or seawater process), which has

extensive commercial experience, as their bid specification.

Table 10-1 Status of Thermal Power Plants and Their FGD Installation Plans S. No.

Name of the Plant Location Sector Owner Number of

units Capacity (MW)

FGD Status

1 Barh STPP St-I Dist: Patna, Bihar

Central NTPC 3x660 1980 Order not yet placed

2 Nabinagar TPP Aurangabad, Bihar


3 Lara STPP Raigarh, Chhattisgarh


4 North Karanpura STPP

Chatra, Jharkhand


5 Kudgi STPP St-I Bijapur, Karnataka


6 Solapur STPP Solapur,Maharashtra


7 Gadarwara STPP, St–I

Narsinghpur Madhya Pradesh


8 Khargone STPP Khargone,Madhya Pradesh


9 Darlipalli STPPSt-I Sundergarh,

Central NTPC 2x800 1600 Order not yet placed Odisha

10 Telangana TPP (Ph-I) Karim Nagar Telangana


11 Meja STPP Allahabad, U.P. Central

NTPC & UPRVUNL

2x660 1320 Plant not yet commissioned

12 Tanda-II STPP, Ambedkar Nagar, U.P.


13 Barsingsar TPP ext Bikaner, Rajasthan

Central NLC 1x250 250 Plant under construction

14 Bithnok TPP Bikaner, Rajasthan

Central NLC 1x250 250 Plant under construction

15 Chhabra SCTPP Baran, Rajasthan

State RRVUNL

2x660 1320 No data


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16 Suratgarh Super Critical TPP

Ganga Nagar, Rajasthan

State RRVUNL

2x660 1320 No data

17 Obra-C TPP Sonebhadra, U.P.

State UPRVUNL

2x660 1320

Plant construction started. No data on FGD

18 Jawaharpur STPP Etah, U.P. State JVUNL 2x660 1320

Commissioning of units I & II are scheduled for 12.2020

19 Rayalaseema TPP St-IV

Cuddapah, Andhra Pradesh

State M/s. APGENCO

1x600 600


20 Sri Damodaram Sanjeevaiah TPP St-II

Nellore, Andhra Pradesh

State APPDCL

1x800 800 Boiler erection yet to start

21 Dr. Narla Tata Rao TPP

Vijayawada, Andhra Pradesh

State APGENCO

1x800 800 Construction under way. No data on FGD

22 Kothagudem TPS –VII

Kammam, Telagana

State TSGENCO

1x800 800


23 Bhadradri TPP Kammam, Telagana

State TSGENCO

4x270 1080


24 Yelahanka Combined Cycle Power plant

Karnataka State 1x370 370


25 Ennore SEZ SCTPP Thiruvallur, TN State TANGEDCO

2x660 1320


26 Uppur SCTPP Ramnad, Tamil Nadu

State TANGEDCO

2x800 1600 Under construction. No data on FGD

27 Ennore SCTPP Thiruvallur, TN State TANGEDCO

1x660 660


28 TuiticorinTPP St-IV Tuticorin, Tamil Nadu

State

SEPC Power Pvt. Ltd

1x525 525


29 Malibrahmani TPP Angul, Odisha State

M/s Monnet Ispat

2x525 1050 Construction under way. No data on FGD

30 KVK Nilachal TPP, Ph‐I Kandarei

Dhenkanal, Odisha State

M/s KVK Nilanc

3x350 1050 Unit 1 commissioned. No work is


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DeSOx & NOx System for Coal-fired Power Plant hal Ltd.

under progress presently. No data on FGD

31 Namrup Replacement Power Project

Dibrugarh, Assam

State APGCL 1x98.40 98.4

To be commissioned. No data on FGD

32 PRAYAGRAJ TPP Bara, Allahabad Private

M/s Prayagraj Power Generation Co. Ltd.

3x660 1980 No data

33 Kashipur Gas Based CCPP, Ph-II


Private

M/s Sravanthi Energy Private Limited

3x75 225

To be commissioned in 12/17. No data on FGD

34 BETA CCPP, Module-I


Private

M/s BETA INFRATECH PRIVATE LTD.

3x75 225

To be commissioned in 12/17. No data on FGD

35 Uchpinda TPP Unit-1(Ph-I) Unit-2,3&4(Ph-II)

Janjgir Champa District, Chhattisgarh

Private R.K.M Power

4x360 1440

2 units commissioned, 2 units to be commissioned in 2017 and 2018. No data on FGD

36 Lanco Amarkantak Mega TPS, Phase-II

Korba, Chhattisgarh

Private

M/s LAP Pvt. Ltd.

2x660 1320 No data

37 Salora TPP Korba, Chhattisgarh

Private

M/s Vandana Vidyut Ltd

2x135 270

First unit commissioned. 2nd unit uncertain. No data on FGD

38 Singhitarai TPP Janjgir Champa District, Chhattisgarh

Private

M/s Athena Chhattisgarh Power Ltd

2x600 1200



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39 Binjkote TPP Raigarh, Chhattisgarh

Private

SKS power Gen. Ltd.

4x300 1200

2 units to be commissioned in 2017. 2 uncertain. No data on FGD

40 Nawapara TPP Raigarh, Chhattisgarh

Private

M/s TRN Energy Pvt Ltd

2x300 600 No data on FGD

41 Mahan TPP Singrauli, MP Private

Essar Power MP Ltd.,

2x600 1200 No data on FGD

42 Gorgi TPP Singrauli, MP Private

DB Power (MP) Ltd.,

1x660 660 Construction started. No data on FGD

43 Niwari TPP Narsinghpur, MP Private BLA Power Ltd.

1x45 45

Commissioning date uncertain. Work at site on hold. No data on FGD

44 Amravati TPP , Ph-II, Amravati, Maharashtra

Private

M/s RattanIndia Power Ltd

5x270 1350

Commissioning date uncertain. Work on hold. No data on FGD

45 Nasik TPP, Ph-I Nasik, Maharashtra

Private


5x270 1350

Unit 1 commissioned. Other units to be commissioned in 2017. No data on FGD

46 Nasik TPP , Ph-II Nasik, Maharashtra

Private


5x270 1350 Work on hold. No data on FGD

47 Lanco Vidarbha TPP Wardha, Maharashtra

Private

M/s Lanco vidarbha Thermal Power Ltd.

2x660 1320


48 Bijora Ghanmukh TPP

Yavatmal, Maharashtra

Private

M/s Jinbhuvish Power Generations

2x300 600 UNCERTAIN. Work put on hold


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DeSOx & NOx System for Coal-fired Power Plant Pvt. Ltd. (JPGPL)

49 Shirpur Power Dhule, Maharashtra

Private

Shirpur Power Private Ltd.

2x150 300


50 Thamminapatnam TPP Ph-II

Nellore, Andhra Pradesh

Private

M/s Meenakshi Energy Pvt.Ltd.

2X350 700


51 Bhavanapadu TPP Ph-I

Srikakulam, Andhra Pradesh

Private

M/s East Coast Energy Pvt. Ltd.

2x660 1320

To be commissioned in 2018-19. No data on FGD. Currently work on hold

52 Tuticorin TPP Tuticorin, Tamil Nadu

Private

Ind. Barath Power Limited

1x660 660


53 Barauni Extn TPS Begusarai, Bihar Private BSPGCL

2x250 500


54 Siriya TPP Banka, Bihar Private JAS INFRA 4x660 2640

Presently no work is in progress at site

55 Matri Shri UshaTPP Latehar, Jharkhand

Private

M/s Corporate Power Ltd.

4x270 1080

Construction under way. Date of commissioning uncertain. No data on FGD

56 Tori TPP Latehar, Jharkhand

Private

Essar Power (Jharkhand) Ltd.

3x660 1980

Presently no work is in progress due to financial constraints

57 Ib Valley TPP Jharsaguda, Odisha

Private OPGC 2x660 1320

To be commissioned in 2018. FGD Plant: Management


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DeSOx & NOx System for Coal-fired Power Plant approval for award of consultant for tender specification in progress

58 Ind Barath TPP Jharsaguda, Odisha

Private

M/s Ind‐Barath Energy (Utkal) Ltd.

2x350 700

Unit 1 commissioned. Unit 2 to be commissioned in 2017. No data on FGD

59 Lanco Babandh TPP Dhenkanal, Odisha

Private

M/s Lanco Babandh Power Ltd.

2x660 1320


60 India Power (Haldia) TPP

East Medinipur, West Bengal

Private

India Power Corporation (Haldia) Ltd

3x150 450

Unit 1 commissioned. Other 2 units to be commissioned in 2018. No data on FGD.

10.1.2 Category (b) and (c): Retrofit of Existing TPPs

Out of the existing TPPs, capacity of category (b) was analyzed by region and sector. The

analysis result indicated in Table 10-2 shows that 48 % market exists in western India

followed by 22 % in northern region. The sector analysis shows 21%, 35% and 44% market will

be contributed by central, state and private sectors respectively. This suggests that demand of

state and private sectors are larger than that of central.

Table 10-2 Potential Market of FGD and SCR in India Region

No Capacity No Capacity No Capacity No Capacity Northern 10 4,690 40 11,775 20 10,940 70 27,405

Western 15 7,640 63 19,055 67 31,662 145 58,357

Southern 8 4,000 20 10,250 13 5,990 41 20,240

Eastern 20 9,660 4 1,220 15 5,790 39 16,670

Total 53 25,990 127 42,300 115 54,382 295 122,672

PrivateTotalSector (Capacity is in MW)

Central State

(Based on CEA analysis, the views expressed by TPP owners in public and in private)

The percentages of the existing market (category (b)) in total capacity of existing TPPs


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(category (b) and (c)) derived from Table 10-2 are indicated in Table 10-3. For example, 37 %

(4,690 MW) out of the total capacity 12,630 MW is the market potential for FGD for the

central sector in Northern region.

Table 10-3 Percentages of Market in Total Capacity of category (b) and (c) Region

Total Capacity


Total Capacity


Total Capacity

Market Potential in %

of Total CapacityTotal Capacity

Market Potential in %

of Total CapacityNorthern 12,630 37 17,098 69 22,760 48 52,488 52

Western 14,317 53 22,280 86 33,385 95 69,982 83

Southern 13,425 30 17,832 57 12,124 49 43,381 47

Eastern 14,256 68 6,570 19 6,225 93 27,051 62

Total 54,628 48 63,780 66 74,494 73 192,902 64

Sector (Capacity is in MW) TotalCentral State Private

36 GW out of 72 GW (category (c)) are the TPPs which have space constraints. However, their

operating periods are less than 20 years (i.e., relatively new plant). If new technologies are

developed to solve space constraint of these power plants, they would help not to waste big

infrastructure and huge investment for India.

As shown in Table 9-6, CEA announced the phasing plan for FGD installation for existing

TPPs. In this report, this market is analyzed by region and sector. The following are the

assumptions:

TPPs that had been operated within the last 2 year have sufficient space for FGD

installation in their plant. Then, these TPPs can comply with the Norms by 2019.

TPPs that had been operated in the period between 2010 and 2015 will be able to

install environmental facility within the next 3 years and be able to comply by 2020.

TPPs that had been operated before 2010 will face difficulty in complying with the

Norms due to space and financial constraints. Thus, they will require more time to

install these technologies and come under compliance. For these plants we have given

a compliance period untill 2023.

Analytical results indicated in Figure 10-1 and Table 10-4 show that the potential market for

FGD and SCR system will gain and grow untill about 2021 and then decline towards 2023

when most of the plants are expected to come under compliance. Therefore, it will be prudent

to plan to enter this market within the next 2 years and take advantage of the growing

demand of FGD systems fulfilled by 2021~23.


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Figure 10-1 Potential Market Trend

Table 10-4 Timeline Analysis for Potential Market of FGD and SCR

Compliance Timeline

Sector

Northern Region

Western Region

Southern Region

Eastern Region

# Capacity

(MW) #

Capacity (MW)

# Capacity

(MW) #

Capacity (MW)

2019

Central 0 0 1 660 2 1,000 6 2,400 State 3 1,600 8 3,570 6 4,100 1 500

Private 9 5,160 16 8,180 7 4,280 3 1,200 TOTAL 12 6,760 25 12,410 15 9,380 10 4,100

2020

Central 7 3,480 8 4,480 5 2,500 9 4,760 State 10 3,550 12 5,610 8 4,310 0 0

Private 11 5,780 42 21,490 1 600 9 3,840 TOTAL 28 12,810 62 31,580 14 7,410 18 8,600

2023

Central 3 1,210 6 2,500 1 500 5 2,500 State 27 6,625 43 9,875 6 1,840 3 720

Private 0 0 9 1,992 5 1,110 3 750 TOTAL 30 7,835 58 14,367 12 3,450 11 3,970

10.2 Requirement for DeSOx and DeNOx system

Federally owned companies like NTPC and BHEL release tender notifications to invite bids for

installation of specific technologies at their TPPs or other plants being planned. Gathered

information from these bid invitations show the specifications of FGD and SCR systems

required by the power generation companies. These are discussed in this chapter.

10.2.1 Requirement for DeSOx system

NTPC has been measuring the level of SOx emissions from their power plants for last 3-4

years. However, they have neither published the data nor shared it. Per their analysis, Indian

coal has 0.3~0.5 % sulphur. NTPC estimates it will be between 600~1,000 mg/Nm3 based on

200 mg-SOx/Nm3 per 0.1% of sulphur in coal.


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NTPC has released tenders for FGD installation at some of its coal power plants. The

specifications for FGD system for Telangana Super Thermal Power Project Phase-I of 2 x 800

MW capacity are as follows:

1) Qualified wet limestone based FGD System Manufacturer (QFGDM)

- Flue gas treatment capacity should not be less than 2,300,000 Nm3/hr

- Desulphurization efficiency of a wet FGD system should not be less than 90 %

2) Wet Limestone based Flue Gas Desulphurization System Manufacturer with

Collaboration and Technology Transfer Agreement with QFGDM

- Flue gas treatment capacity should not be less than 600,000 Nm3/hr

- Desulphurization efficiency of a wet FGD system should not be less than 85%

The Telangana Super Thermal Power plant is currently under construction. The boiler is

being built by BHEL, while the turbine is being provided by Alstom Bharat Forge Ltd.

NTPC released another invitation for bids in July 2017 for FGD system package for Khargone

Super Thermal Power Plant in Madhya Pradesh with its capacity of 1,320 MW (660 MW x 2).

The scope of work includes a complete package of work, including “design, engineering,

manufacture, shop fabrication, preassembly, shop testing/type testing at the manufacturer’s

shop, packing, transportation, unloading, handling and conservation of equipment at site,

complete services of construction including erection, supervision, pre-commissioning,

commissioning and performance testing of equipment under bidder’s scope of work of FGD

system, limestone handling, storage, crushing and Gypsum handling & storage, low height

wet chimney and its associated auxiliaries, including all associated Electrical, Control &

Instrumentation, Civil, Structural and Architecture works.” The requirements for the bidders

are the following:

1) Qualified wet limestone based FGD System Manufacturer (QFGDM)

- Flue gas treatment capacity should be at least 2,000,000 Nm3/hr

- Desulphurization efficiency should be at least 90%

2) Other company except QFGDM

- Flue gas treatment capacity should be at least 600,000 Nm3/hr

- Desulphurization efficiency should be at least 85%

NTPC has invited similar bids for the upcoming North Karanpura Thermal Power Station of 3

x 660 MW capacity at Chatra, Jharkhand. A common invitation for bids has been released by

NTPC recently for the following plants. The specifications for these are similar to the FGD

specifications for Telangana Super Thermal Power Project Phase-I of 2 x 800 MW capacity

plant:

Mouda STPP, Stage-II (2 x 660 MW)

Kudgi STPP, Stage-I (3 x 800 MW)


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Solapur STPP (2 x 660 MW)

Lara STPP, Stage-I (2 x 800 MW)

Nabinagar Thermal Power Project (4 x 250 MW), BRBCL

Meja Thermal Power Project (2 x 660 MW)

Barh STPP, Stage-I (3 x 660 MW)

Gadarwara STPP, Stage-I (2 x 800 MW)

Darlipalli STPP, Stage-I (2 x 800 MW)

Tanda STPP, Stage-II (2 x 660 MW)

Nabinagar STPP (3 x 660 MW), NPGCPL

Muzaffarpur Thermal Power Project, Stage-II (2 x 195 MW), KBUNL

Feroze Gandhi Unchahar Thermal Power Project, Stage-IV (1 x 500 MW)

Mauda STPP, Stage-I (2 x 500 MW)

Barh STPP, Stage-II (2 x 660 MW)

Rihand STPP, Stage-II (2 x 500 MW) & Stage-III (2 x 500 MW)

Vindhyachal STPP, Stage-III (2 x 500 MW) & Stage-IV (2 x 500 MW)

10.2.2 Requirement for DeNOx system

Per a bid document recently released by BHEL for various projects, the requirements for a

bidder for SCR system are the followings:

It should have designed and installed a system of NOX reduction efficiency at least

75 % at a plant of at 250 MW or having a steaming capacity of at least 810 tons/hr.

It should also have designed and installed an anhydrous ammonia handling and

storage system for a similar type of plant

It should have manufactured or supplied catalyst for such a plant and such a catalyst

the SCR system should have been in operation for at least 16,000 hours without any

replacement.

Design life of 25 years

Minimization of conversion of SO2 to SO3

Prevention of formation of ammonium bisulfate

Modular construction to enable catalyst management plan and periodic maintenance

The specifications for SCR system provided in BHEL’s tender for 3 x 800 MW Patratu Power

Plant are the following:

1) Qualified SCR System Manufacturer/Supplier

- Experience in design and installation of DeNOx system with efficiency of at least 75%

in power plant of at least 500 MW capacity or 1,500 tons/hr steaming capacity

2) Proneness’ criteria for critical equipment and bought out items for SCR systems

- Ammonia handling and storage system: the bidder should have experience in designing


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and installation of such a system in a plant of at least 500 MW capacity or at 1,500

tons/hr. steaming capacity and the system should have been in operation for at least

one year

- Catalyst for SCR system: catalyst should be supplied by a manufacturer that has

experience of supplying such catalyst to a plant of at least 500 MW capacity or at least

1,500 tons/hr. steaming capacity. That catalyst should have been in use for at least

16,000 hours without replacement.

- SNCR system: the bidder should have experience in designing and installing such a

system in a plant of at least 500 MW capacity or at 1,500 tons/hr. steaming capacity,

and the system should have been in operation for at least 1 year

10.3 DeSOx and DeNOx Suppliers in India and Their Activities

Technology suppliers, such as manufactures, who participated in the tenders of DeSOx or

DeNOx technologies are listed in Table 10-5. Table 10-5 is based on the open information

about tenders by BHEL and NTPC. In addition, following catalysis suppliers show their

interest to Indian potential market:

NANO, Korea

IBIDEN Co. Ltd., Japan

Yara International, Norway

Johnson Matthey, USA

Mitsubishi Hitachi Power Systems, Japan

Cormetech Inc.

DRPley, Germany

Haldor Topsoe, Denmark

JGC Catalyst & Chemical, Japan


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Table 10-5 FGD and SCR Manufacturers and Suppliers

S. No.Name of theCompany

FirmLocation/Headquarters

Manufacturing in India orimported and supplied inIndia

Firm Turnover(2016)

Past Clients in(Already runningsystems)

TechnologyUsed such asSCR/SNCR

TechnologyEfficiency (%Removal)

-Riikinvoima Oy,Finland-Energoinstal S.A. /SEJ S.A., Poland- MSE MjölbySvartadalen EnergiAB, Sweden

2 ERC EmissionReduction Concepte

Germany Exclusively in Germany NA (Privatecompany)

NA SCR, SNCRand ERC-plusprocess

- Jingfeng Power Plant,Beijing- Yixing Power Plant,Jiangsu, China- Dairen Chemical,Jiangsu, China

4 Wuhan KaidiElectric PowerEnvironmental Co.,Ltd

China

- Most of the pastprojects in China. Noproject in India- eg. Datang BinchangPower Plant 2x600MW denitrificationproject EPC

FGD (Limestone /Seawater} 90%;FGD (Dry/ Semi Dry)60%-85%;SCR System 90%

7 Ducon Technologies India Amalgamation with DuconInfratechnologies Limited

INR 4082.49 lacs WienerbergerKarnataka

FGD 99%

8 Alstom India (HQ: France) EUR 6.9 Bn National ThermalPower Corporation

FGD and SCR FGD 98%;

SCR 95%

9 Chanderpur WorksPvt. Ltd

India USD 30 Million JSW Cement, HyundaiHeavy Industry, NCC

FGD

10 Thermax India Manufacturing in India Rs. 4287 Cr. WetScrubbers,FGD, SNCR

FGD <15ppm

11 Ljungström AdvX™Technology/ARVOSGroup

India Wet FGD,SCR

99.80%

12 Siemens India INR 7,948 Cr. FGD and SCR

>=80% (<90mg/Nm3)

6 Indure India Alliance with RAFAKO S.A,Poland

INR 1650 Cr FGD and SCR

5 CHINA DATANGTECHNOLOGY &ENGINEERING CO.,LTD.

China Manufacturing of catalystusing foreign technologies

Registered CapitalUSD 2.9 Billion

<= 100 mg/Nm3

3 LP Amina USA and China Manufacturing in USA andChina only

NA SCR andSNCR andLow-NOxburners

>80%

1 Andritz Energy andEnvironment

Austria No manufacturing in Indiaof air quality managementsystems. However, Andritzitself will provide the main(SCR) equipment

MEUR 6,039.0(sales of the Andritzgroup)

FGD and SCR


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NTPC had floated an enquiry for setting up a demonstration project for DeNOx technologies,

such as SCR and SNCR. Ten companies were shortlisted for this demonstration, and they

have or will set up nine projects. NTPC has provided, or will provide, about 2 % of flue gas

from existing TPPs for these demonstration projects, which have been set up by companies by

their own cost. List of these projects and the companies shortlisted by NTPC are indicated in

Table 10-6. Direct supplier, EPC contractors and main equipment suppliers are included in

this list.

Table 10-6 Bidders for NTPC SCR Tender S.N.

Name of Company SCR/SNCR Test Allocated NTPC Plant

1. BHEL 2 Nos. SCR Test Simhadri Unit No. 1 2. GE-Alstom India Limited 1 No. SCR and 1 No SNCR Vindhyachal unit No 13 3. L&T-MHPS Boiler Private

Limited (LMB) & MHPS 1 No SCR Sipat Unit No 4

4. Termokimik Itlay with Indure 1 No SCR Singrauli Unit no 6/7 5 Shanghai 1 No SCR Talcher Unit No 6 6 Andritz 1 No SCR Korba Unit No 7 7. ERC 1 No SNCR Korba Unit No. 7 8. Yara Norway 1 No. SCR and 1 No SNCR Rihand Unit No 4 9. Thermax Ltd 1 No SCR Ramagundam Unit No 7 10. Doosan 1 Nos. SCR Kahalgon Unit no 6.

10.4 Properties and Market of Raw Materials for Dry Desulfurizing Agent

Market and quality of quick lime (CaO) and slaked lime (Ca(OH)2) which are used as raw

materials of dry desulfurizing agent was investigated. The location of limestone mines are

indicated in Figure 10-2. The figure shows that major lime mines are around Jodhpur

(Rajasthan State in North West India) or the area between southward to eastward of India.

The calcium content in limestone is about 45-52%. The quality of limestone is sufficient for

cement production, glass, ceramics and construction, limestone. There is a huge import of

quick lime with calcium content above 55% from Oman, Ras al Khaimah (UAE), etc., into

India to the extent of about 6 million tons per year, it is quite good quality and it is mainly

used for steel industry.


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Mahendragarh

Pali

Sirohi ChittaurgarhBanaskantha

RajkotBhavnagarJamnagar

Amreli

SatnaRewa

Katni

Palamau

SinghbhumSundargarh

Sambalpur

KoraputBalaghat

Adilabad

KarimnagarWarangalGulbarga

BagalkotBelgaum

Simoga

ChitradurgaTumkur

Guntur

Cuddapah

Palghat

SalemPeramblur

TiruchirapalliVirdhunagar

Tirunelveli

Rajasthan is the main source of lime stone.

Limestone Mines

Figure 10-2 Limestone Mines in India

Suppliers around Rajasthan and their manufacture capacity are indicated in Table 10-7. In

Jodhpur major player is Sigma Minerals who have vertical automatic Kilns. Tara Minerals is

another big supplier in Jodphur, have pot kilns and supply high-quality quick lime. It is

reported there are 600 small manufactures of quick lime around Jodhpur, Gotan, Khimsar. All

of them use pot kilns fueled by petcoke, wood, coal, charcoal, etc., for calcination.

The industrial specifications of quick lime and slake lime in Japan (Japanese Industrial

Standard, JIS) are listed in Table 10-8. The properties of quick lime and slaked lime produced

in India seems to be equivalent with JIS specification in terms of calcium levels.


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Table 10-7 Suppliers of CaO and Ca(OH)2 around Rajasthan area

State SiteCompany

nameWebsite

Capacity ofCalcium

Oxide(CaO)Spec

Capacity ofCalcium

HydroxideCa(OH)2

Spec

NagourMayur

InorganicsLtd.

http://www.mayurinorganics.com/about.htm

27,000MT/Y 10,000MT/Y

JodhpurSigma

Minerals Ltd.http://www.sigmamineral

s.com/Ca(OH)2 > 96%

JodhpurTara Minerals& Chemicals

Pvt. Ltd.

http://www.taraminerals.co.in/home/

CaO > 96% Ca(OH)2 > 96%

KimsarGaurikaMinerals

http://www.essemmetachem.com/limestone-

rajasthan.html24,000MT/Y CaO > 87% 24,000MT/Y Ca(OH)2 > 90%

Jaisalmer

RajasthanState Mines& Minerals

Ltd.

http://www.rsmm.com/profile.htm

CaO > 95%

Rajasthan

Table 10-8 JIS specification of CaO and Ca(OH)2

Material Quality CaO content %

Quick Lime (CaO) Special ≧ 93.0 %

Slake Lime (Ca(OH)2) Special ≧ 72.5 %


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11. Conclusions and Recommendations

As a result of this feasibility study, it has been confirmed that India has a huge market for

DeSOx and DeNOx systems, which is equivalent to 186 GW (13% of world demand). It was

assumed that the potential demand for FGD and SCR technologies will gain and grow until about

2021 by the consideration of manufacture capacity of technologies suppliers. From this analysis,

it is ideal to meet the market demand growing up to the time limit and introduce the proposed

Dry-DeSOx and DeNOx systems.

With regard to the proposed systems, it has been confirmed that electrostatic precipitators are

feasible for the dust removal equipment, since multicyclone separators needs to overcome several

technical challenges before they can be scaled up to a commercial size. Also, it has been

confirmed that the proposed DeNOx system (using honeycomb type catalyst with low dust

concentration downstream of dust removal equipment and dry-DeSOx system) is much more

competitive than the conventional DeNOx system (using plate type catalyst with high dust

concentration at the outlet of the boiler).

However, it has been confirmed that the proposed Dry-DeSOx is competitive by applying a lower

flue gas temperature (i.e., lower flue gas volume and fewer Dry-DeSOx towers). In addition, it

has been confirmed that the proposed Dry-DeSOx system can be made more competitive than the

conventional Wet-DeSOx system (limestone process) by having a common DeSOx agent

production facility shared by the neighboring TPPs and by industrializing and introducing the

DeSOx agent production process using quick lime (CaO), instead of slake lime (Ca(OH)2), as the

raw material.

As a way to introduce the proposed Dry-DeSOx system into India earlier, the industrialization of

DeSOx agent production process using quick lime should be accelerated. In addition, it is

recommended to target projects where the competitiveness and advantages (e.g., lower water

consumption and no waste water treatment) of the proposed Dry-DeSOx system can be fully

realized.


0-7745 0

SHEET 81 OF 81

FORM 1005-2 3




Attachment List Attachment-1 Basic Engineering Design Information (S-1222-001) Attachment-2 Design Basis for Maithon Power Plant (S-1222-101) Attachment-3 Design Basis for Jojobera Power Plant (S-1222-102) Attachment-4 PFD for DeSOx unit - Case 1 (D-1223-101) Attachment-5 PFD for DeSOx unit -Case 3 (D-1223-102) Attachment-6 PFD for DeNOx unit -Case 3 (D-1223-301)

FORM 1005-1


0-7745 S-1222-001 1

DATE 2017 11 02 SHEET 1 OF 16


CHK’D H.Isobe

APP’D T. Kayukawa



2017-08-15 All First issue MH HI TK


DIST’N CLIENT

H.OFFICE

FIELD

JGC

CP

Instrument

Electrical

Civil

Piping

Equipment

Process

T&I

PJ

FIELD

TATA Power Co., Ltd. Project specification

4


A

0

BASIC ENGINEERING DESIGN INFORMATION

JOB No. DOC. No. REV. 0-7745 S-1222-001 1

SHEET 2 OF 16

FORM 1005-2 3



Contents 1. SCOPE ....................................................................................................................................................... 3 2. GENERAL ................................................................................................................................................. 3 3. COMMUNICATION CHANNEL LIST OF CONTACT .......................................................................... 3 4. UNITS OF MEASURE .............................................................................................................................. 4 5. CLIMATIC DATA .................................................................................................................................... 5 6. UTILITY CONDITIONS AT B/L ............................................................................................................. 6

6.1 Steam and Condensate .......................................................................................................................... 6 6.2 Water ..................................................................................................................................................... 6 6.3 Chemicals .............................................................................................................................................. 8 6.4 Air and Nitrogen ................................................................................................................................... 8 6.5 Electrical Power .................................................................................................................................... 9

7. NUMBERING SYSTEM ......................................................................................................................... 10 7.1 Unit numbering ................................................................................................................................... 10 7.2 Equipment Numbering ........................................................................................................................ 10 7.3 Instrument Numbering ........................................................................................................................ 11 7.4 Line Numbering .................................................................................................................................. 12

8. PROCESS DESIGN PHILOSOPHY & INFORMATION ...................................................................... 13 8.1 Design Margin ..................................................................................................................................... 13 8.2 Design Pressure ................................................................................................................................... 13 8.3 Design Temperature ............................................................................................................................ 13 8.4 Standard Corrosion allowance ............................................................................................................ 14 8.5 Critical Service Rotary Machinery ...................................................................................................... 14

9. EQUIPMENT DESIGN PHILOSOPHY & INFORMATION ................................................................ 15 9.1 Vessels ................................................................................................................................................ 15 9.2 Pumps .................................................................................................................................................. 16 9.3 Induced Draft Fan ............................................................................................................................... 16

JOB No. DOC. No. REV. 0-7745 S-1222-001 1

SHEET 3 OF 16

FORM 1005-2 3



1. SCOPE

This document firstly covers general information of the project such as client, plant location, communication channel, and secondly covers design basis information such as units of measure, utility conditions, numbering system. JGC basically proceeds with the basic design work based on information listed by this document.

2. GENERAL

Client: TATA Power Company Ltd. Project name: DeSOx & NOx System for Coal-fired Power Plant Plant location: Jojobera Power Plant Unit 5, Jharkhand, India Type and capacity of the plant: Flue Gas DeSOx & NOx

(457,999 Nm3/hr of flow rate for commercial unit) (5,000 Nm3/hr of flow rate for demonstration plant)

3. COMMUNICATION CHANNEL LIST OF CONTACT

(1) Client: TATA Power Company Ltd. (2) Consortium Leads: JGC Corporation

Attention: Mr. Tomoki Kayukawa, Project Manager, Technology Innovation Center ([email protected])

Address: 2-3-1, Minato Mirai, Nishiku, Yokohama City 220-6001, Japan Phone: +81-45-682-8371

(3) Consortium Member: JGC C&C

Attention: Mr. Jin Abe, Assistant Manager, Business Planning Group, Sales Division ([email protected])

Address: Solid Square East Tower 16F, 580 Horikawa-cho, Saiwai-ku, Kawasaki city, Kanagawa Pref. 212-0013, Japan

Phone: +81-44-556-9158 Consortium Member: Sojitz Attention: Mr. Kentaro Hiiragi, Manager Section 3, Advanced Materials Dept.

Chemicals Division ([email protected])

Address: 1-1, Uchisaiwaicho 2-chome, Chiyoda-ku, Tokyo 100-8691, Japan Phone: +81-3-6871-2775 Consortium Member: JCOAL Attention: Mr. Masahiro Ozawa, Deputy Director, Power Generation & Infrastructure

Development Group, Business Development Department ([email protected])

Address: 3F Daiwa Nishi-shimbashi Building, 3-2-1 Nishi-shimbashi, Minato-ku, Tokyo 105-0003 Japan

Phone: +81-3-6402-6104

JOB No. DOC. No. REV. 0-7745 S-1222-001 1

SHEET 4 OF 16

FORM 1005-2 3



4. UNITS OF MEASURE

SI is used on this project. Specific units of measure are listed below.

The normalized conditions for gas measurement are:

Normal : 101.3 kPa, 0 °C (Nm3/h)

SI (New Metric) Temperature °C Pressure MPa, kPa Vacuum kPa Weight kg, ton Volume m3 Flow of Process fluid Liquid - Mass flow kg/h, ton/h - Volume flow m3/h Gas - Mass flow kg/h - Volume flow m3/h, Nm3/h - Mole flow kmol/h Flow of steam kg/h Enthalpy kJ/kg Heat duty kW, kcal/h Power kW, MW Transfer rate W/(m2.°C) Fouling resistance m2.°C/W Viscosity mPa.s, cP Equipment size mm Pipe length m Pipe diameter mm Vessel nozzle sizes mm

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FORM 1005-2 3



5. CLIMATIC DATA

These data may not be required for BDP preparation. They may be indicated if needed.

● Maximum temperature:

● Design maximum ambient temperature:

● Minimum temperature:

● Winterizing temperature:

● Design minimum temperature:

● Relative humidity - Average:

- Maximum:

● Dry bulb temperature:

● Barometric pressure - Minimum:

- Maximum:

- Average:

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SHEET 6 OF 16

FORM 1005-2 3



6. UTILITY CONDITIONS AT B/L

Except otherwise specified, all the following conditions are at the battery of the owner plant.

The pressure of the B/L is on the basis of ground elevation at the owner’s B/L.

6.1 Steam and Condensate

Low pressure steam Pressure(MPa) Temperature(°C)

Normal: 0.35 150

Mechanical design: 0.7/FV 180


Steam condensate

Condensate from Low pressure steam system will discharge to Demineralized water system for recovering.

6.2 Water

Industrial water Pressure(MPa) Temperature(°C)

Normal: 0.4 Ambient


pH(25°C): 6.5-8.5

Industrial water quality

pH(25°C): 6.5-7.5

Conductivity(H conductivity at 25℃): ≤0.3(μS/cm)

Hardness: ~0(μmol/L)

SiO2: ≤20(μg/L)

Fe: ≤30(μg/L)

Cu: ≤5(μg/L)

Cooling water - Supply Pressure(MPa) Temperature(℃)

Normal: 0.4 30

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FORM 1005-2 3





Cooling water - Return Pressure(MPa) Temperature(℃)

Normal: 0.25 40


Cooling water quality

Turbidity: ≤ 20(NTU)

pH: 6.8-9.5

Alkalinity methyl orange as CaCO3: ≤ 1100(mg/L)

(Calcium carbonate saturation index): LSI ≥ 3.3

Ca2+ Hardness: ≤ 200(mg/L)

(Temperature of water side of heat transfer surface):

≥ 70°C

Total Fe: ≤ 1.0(mg/L)

Cu2+: ≤ 0.1(mg/L)

Cl-: ≤ 700(mg/L)

SO42- +Cl-: ≤ 2500(mg/L)

Silica as SiO2: ≤ 175(mg/L)

Mg2+×SiO2 as CaCO3: ≤ 50000(mg/L) pH≤ 8.5

Free chlorine: ≤ 0.2～1.0 In CW return header

NH3-N: ≤ 10(mg/L)

Oil: ≤ 5(mg/L)

CODcr: ≤ 100(mg/L)

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FORM 1005-2 3



6.3 Chemicals

Ammonia Anhydrous ammonia liquid is supplied by cylinder at the local site.

6.4 Air and Nitrogen

Instrument air Pressure(MPa) Temperature(℃)

Normal: 0.6 Ambient


Instrument air specification



Dust content: ≤ 1(mg/m3)


Plant air Pressure(MPa) Temperature(℃)

Normal: 0.6 Ambient


Plant air specification



Nitrogen Pressure(MPa) Temperature(℃)

Normal: 0.7 Ambient


Nitrogen specification

Purity: ≥ 99.99

O2 content: ≤ 100(vppm)


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FORM 1005-2 3



6.5 Electrical Power

Motor

Motor power range Voltage(V) Phase Frequency(Hz)

≥ 180 kW 10000 3 50

< 180 kW 380 3 50

Control Voltage(V) Phase Frequency(Hz)

220 1 50

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SHEET 10 OF 16

FORM 1005-2 3



7. NUMBERING SYSTEM

7.1 Unit numbering

Unit numbering is defined as following;

Unit name Unit number

Dust Collection 1

DeSOx 2

DeNOx 3

7.2 Equipment Numbering

Equipment shall be identified by a tag number as the following format: D-EFFA/B/C Where, D: Equipment code (see the equipment codes given below) EFFA/B/C: E is the unit No. of plant deficed as Chapter 7.1. FF is the sequence numbers for equipment, A/B/C is the code to denote identical equipment used for the same purpose.

Equipment codes

NO EQUIP. CODE

First letters for

1 C Columns: tray columns, packed columns etc.

2 E Unfired heat transfer equipment, heat exchangers, condensers, air cooled heat exchangers, reboilers, electric heaters

3 K Compressors, blowers, fans 4 M Mixers, stirrers, mixing nozzles, blenders, steam desuperheaters 5 P Pumps 6 R Reactors

7 S Gravity and mechanical separators, e. g. thickeners, cyclones, expellers, centrifuges, filters, dust collectors, sieves, helical separators

8 V Vessels including pressure storage vessels, silos and hoppers 9 Z Miscellaneous equipment, e.g. conveyor, blasters

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FORM 1005-2 3



7.3 Instrument Numbering

Instruments shall be identified by a tag number as the following format: ABB-CCC Where, ABB: A is the first letter of instrument function code, BB is the succeeding letters with 2 (or 1) chatacters of instrument function code (see the functional identification letters given below)

CCC: Sequence numbers for instruments.

Functional identification letters

First letters Succeeding letters

Measured or initiating variable

Modifier Measured or initiating variable

Output function Modifier

A Analysis Alarm B Burner, Combustion C Control D Differential

E Voltage Sensor

(Primary element)

F Flow rate Ratio (Fraction)

G Gas Gauge,

Viewing device

H Hand High I Current (Electrical) Indicate J Power Scan

K Time, Time schedule Time rate of change

Control station

L Level Light Low

M Momentary Middle,

Intermediate N O Orifice, Restriction P Pressure, Vacuum Point (test) connection

Q Quantity Integrate, Totalize

Quantity

R Radiation Record S Speed, Frequency Safety Switch,Sequence T Temperature Transmit U Multivariable Logic Multifunction Multifunction Multifunction

V Vibration, Mechanical analysis

Valve, Damper, Louver

W Weight, Force Well X Event state or pressure X axis Unclassified Unclassified Unclassified

Y Compute in DCS Y axis Relay,Compute,

Convert

Z Position, Dimension Z axis Driver, Acutuater,

Unclassfide final control element

Functional identification letters are also referred to the legend sheets of P&ID

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FORM 1005-2 3



7.4 Line Numbering

Lines shall be identified by a tag number as the following format: AA-BBB-CCC-DD-E-F

Where,

AA: Nominal pipe size in mm

BBB: Fluid code (see the fluid codes given below)

CCC: Sequence numbers for lines

DD: Piping material class

E: Insulation type F: Trace type.

Fluid codes (Process)


FG Flue Gas

DS DeSOx Adsorbent

AW Ammonia Water

Fluid codes (Utility and common)


CWS Cooling water (supply)

CWR Cooling water (return)

IA Instrument air

IW Industrial water

LPS Low pressure steam

N2 Nitrogen

PA Plant air

SC Steam condensate Fluid codes are also referred to the legend sheets of P&ID.

Notes:

Numbering starts from 001.

The number changes after control valves and main equipment.

The number is different for the lines connected to equipment in parallel.

Each type of fluid has a separate numbering sequence.

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SHEET 13 OF 16

FORM 1005-2 3



8. PROCESS DESIGN PHILOSOPHY & INFORMATION Design Electric equipment such as heater, pump and compressor is on the basis of the following regulation/code/standard.

8.1 Design Margin

Design margins of each equipment item are as follows :

(1) Pumps

Charge pumps Flow rate 10% %


Product pumps Flow rate 10% %


Reflux pumps Flow rate 20% %


(2) Electric heater : Duty 10% %

8.2 Design Pressure

Positive Design Pressure shall be no less than the expected maximum operating pressure. If the

maximum pressure cannot be expected, it shall be

1.1 times the normal operating pressure (gauge pressure) or the normal operating pressure +

1.8 kg/cm2, whichever is bigger.

Electric part such as control panel and its components has the certificate of XXX Marking (India Certification) or the equivalent as CE Marking (Conformity European).

8.3 Design Temperature

Hot Design Temperature above 0C shall be no less than the expected maximum operating

temperature. If the maximum temp. cannot be expected, it shall be

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SHEET 14 OF 16

FORM 1005-2 3



the normal operating temperature + 25C rounded to nearest 5C as standard.

Cold Design Temperature below 0C shall be no less than the expected minimum cold operating

temperature. If the minimum temperature cannot be expected, JGC will recommend and specify it.

8.4 Standard Corrosion allowance

(1) Standard corrosion allowance for internal surface of pressure vessel are :





(2) Standard corrosion allowance for each side of vessel/reactor internal, such as coil, are :





8.5 Critical Service Rotary Machinery

JGC will specify critical service steam or power driven rotary machinery which must be maintained in

the event of power failure in order to protect personnel, equipment, or catalyst, and design them

accordingly.

JGC will consider the following equipment as critical service rotary machinery according to

Owner’s requirement, etc. : Later

JOB No. DOC. No. REV. 0-7745 S-1222-001 1

SHEET 15 OF 16

FORM 1005-2 3



9. EQUIPMENT DESIGN PHILOSOPHY & INFORMATION

9.1 Vessels

(1) Dimension indication

inside diameter & tangential lines’ distance

The equipment (columns, vessels & tubular heat exchangers*, etc.) nominal diameter (ID) should meet

Indian standard listed below as far as possible.

(2) Head shape

ASME 2:1 elliptical heads normally & hemispherical heads for high pressure vessels

by Licensor

(3) Size limitation for transportation of shop fabricated vessels N/A

Diameter limitation m

Length limitation m

(4) Connection on equipment

flanged

by Licensor

(5) Small nozzle installed directly on equipment

(a) Minimum connection size : 25 mm 20 mm

(b) Flange rating

same as the rating of the connecting part of equipment even for 25 mm or smaller

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SHEET 16 OF 16

FORM 1005-2 3



- Application of the above criteria a) & b) for tanks Yes No

for shell & tube exchangers Yes No

(6) Separate steam-out connection on vessel

is not required. Utilize drain connection etc. on associated piping of vessel.

be provided. Size : inch

(7) Manhole

(a) Minimum manhole size : 450 mm nominal diameter

9.2 Pumps



● Driver output will be specified minimum 110% to pump break horse power.

9.3 Induced Draft Fan



● Installation of induced draft fan will be unsheltered, outdoor.

FORM 1005-1


0-7745 S-1222-101 0

DATE Jul 21 2017 SHEET 1 OF 7


CHK’D T. Kayukawa

APP’D M. Morita


2017/7/21 All For Discussion (DRAFT) MH TK MM

2017/8/15 All Data provided by TATA Power MH HI TK

DIST’N CLIENT

H.OFFICE

FIELD

JGC

CP

Instrument

Electrical

Civil

Piping

Equipment

Process

T&I

PJ

FIELD



A

0

4

Design Basis for Feasibility Study of

DeSOx & DeNOx System at Maithon Power Plant

JOB No. DOC. No. REV. 0-7745 S-1222-101 0

SHEET 2 OF 7

FORM 1005-2 3



Contents

1. Introduction .......................................................................................................................................... 3

2. Plant Capacity for Commercial Plant ................................................................................................. 3



Attachment-1 ............................................................................................................................................... 4

Attachment-2 ............................................................................................................................................... 7

JOB No. DOC. No. REV. 0-7745 S-1222-101 0

SHEET 3 OF 7

FORM 1005-2 3



1. Introduction








the DeSOx & DeNOx System in a commercial plant.

2. Plant Capacity for Commercial Plant

Capacity 525 MW subcritical,

Coal Consumption 293.48 T/hr, Indian Coal

Air Consumption 1,824.73 T/hr

Gas Flow Rate 2,342,569 Nm3/hr (at stack inlet)

Plant location Maithon, Dombhuin Village

Turn Down 60% (55% as per new regulation)~100%







JOB No. DOC. No. REV. 0-7745 S-1222-101 0

SHEET 4 OF 7

FORM 1005-2 3





A-1. Fuel (Coal)




1.0 PROXIMATE ANALYSIS By Weight


1.2 Ash % 36.19



1.5 Total % 100

1.6 Gross Calorific Value kcal/kg 4671


2.1 Carbon % 47.85

2.2 Hydrogen % 2.89

2.3 Sulphur % 0.39

2.4 Nitrogen % 1.00

2.5 Moisture % 7.11

2.6 Ash % 36.19


2.8 Total % 100



4.1 Initial Deformation Temp. °C

4.2. Hemispherical Temp. °C

4.3 Fusion Temp. °C To be confirmed

A-2. Ash

The following information is based on the analytical results of an ash sample, named as “MPL

(Maithon Power Limited)”. “MPL” ash was selected as design case.


(MPL)

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SHEET 5 OF 7

FORM 1005-2 3




5.1 Silica (SiO2) % 56.11

5.2 Alumina (Al2O3) % 29.96

5.3 Iron oxides (Fe2O3) % 6.00

5.4 Titania (TiO2) % 2.62

5.5 Potassium oxide (K2O) % 1.83

5.6 Lime (CaO) % 1.31

5.7 Phosphoric Anhydride (P2O5) 0.84

5.8 Magnesia (MgO) % 0.48

5.9 Sulphuric Anhydride (SO3) % 0.23

5.10 Sodium oxide (Na2O) % 0.11

5.11 Balance Alkalis (by difference) % 0.50


6.1 D10 μm 7.74

6.2 D50 μm 23.33

6.3 D90 μm 111.02

6.4 Detail distribution (Attach-1B)

7.0 Density



A-3. Flue Gas (Maithon Power Plant)


8.0 Gas Condition


Economizer

Outlet of ESP

8.2 Total Gas Flow Rate

(wet)(TMCR)

kg/hr 2,050,000 2,200,000

8.3 T/h 2,050 2,200

8.4 Gas Temp. (TMCR) °C 322 114

8.5 Gas Pressure (TMCR) mmH2OG -60 -276

8.6 Gas viscosity cP Not available Not available

8.7 Gas density kg/Nm3 0.875 0.939


9.1 Oxygen vol %-wet

9.2 vol %-dry 3.56 8.7

9.3 H2O vol %-wet

9.4 CO2 vol %-dry 15.43 10.7

9.5 NOx kg/hr 2,062 1,119

JOB No. DOC. No. REV. 0-7745 S-1222-101 0

SHEET 6 OF 7

FORM 1005-2 3



9.6 mg/Nm3-

dry

@6%O2

880 (100%TGMCR) 477.5

(100%TGMCR)

9.7 NO2 kg/hr 300 163

9.8 mg/Nm3-

dry

@6%O2

128 (assumed as

NO2 mol/NO mol =

1/9)

70 (assumed as NO2

mol/NO mol = 1/9)

9.9 SOX kg/hr 1,931 1,687

9.10 mg/Nm3-

dry

@6%O2

824 (Design Coal

TGMCR)

720 (Design Coal

TGMCR)

9.11 Dust kg/hr 117,129 84

9.12 mg/Nm3-

dry

@6%O2

50,000

(100%SGMCR)

35.85

(100%SGMCR)



Permissive level: SO2 200 mg/Nm3 (for > 500MW), NOx 300 mg/Nm3, SPM 50 mg/Nm3

B-2. Treated Gas (Commercial Plant)




12.0 Gas Condition

12.1 Location Outlet of SCR

12.2 Gas Pressure mmH2OG By Contractor

13.0 Treated Gas Composition

13.1 NOx mg/Nm3-dry

@ 6%O2

< 100

13.2 SOx mg/Nm3-dry

@ 6%O2

< 100

13.3 Dust mg/Nm3-dry

@ 6%O2

< 30


JOB No. DOC. No. REV. 0-7745 S-1222-101 0

SHEET 7 OF 7

FORM 1005-2 3













FORM 1005-1


0-7745 S-1222-102 1

DATE 2017 11 02 SHEET 1 OF 8


CHK’D H.Isobe

APP’D T.Kayukawa



2017-08-15 All Data provided by TATA Power MH HI TK


DIST’N CLIENT

H.OFFICE

FIELD

JGC

CP

Instrument

Electrical

Civil

Piping

Equipment

Process

T&I

PJ

FIELD



A

0

4

Design Basis for Basic Design of Demonstration Plant of

DeSOx & DeNOx System at Jojobera Power Plant

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 2 OF 8

FORM 1005-2 3



Contents

1. Introduction .......................................................................................................................................... 3

2. Plant Capacity for Commercial Plant (for Reference) ........................................................................ 3

3. Plant Capacity and Inlet Condition for Demonstration Unit ............................................................ 3



Attachment-1 ............................................................................................................................................... 4

Attachment-2 ............................................................................................................................................... 8

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 3 OF 8

FORM 1005-2 3



1. Introduction








the DeSOx & DeNOx System in a commercial plant and a demonstration unit.

2. Plant Capacity for Commercial Plant (for Reference)

Capacity 120 MW subcritical

Coal Consumption 70 T/hr, Indian Coal

Air Consumption 442 T/hr


Plant location Tata Power Co. Ltd, Jojobera Power Plant Unit 5, Jamshedpur.

Turn Down 100%


3. Plant Capacity and Inlet Condition for Demonstration Unit

Plant location Jojobera Power Plant Unit 5, Jharkhand, India


Gas composition SOx 800 mg/Nm3-dry@ 6%O2

NOx 600 mg/Nm3-dry@ 6%O2

Dust 100 g/Nm3-dry@ 6%O2

DeNOx Catalyst Life 1 year






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SHEET 4 OF 8

FORM 1005-2 3





A-1. Fuel (Coal)




1.0 PROXIMATE ANALYSIS By Weight C7 July 2017


1.2 Ash % 39.40



1.5 Total % 100.0

1.6 Gross Calorific Value kcal/kg 4,281.77


2.1 Carbon % 49.30

2.2 Hydrogen % 3.32

2.3 Sulphur % 0.43

2.4 Nitrogen % 1.03

2.5 Moisture % 0.00

2.6 Ash % 41.37


2.8 Total % 100.0



4.1 Initial Deformation Temp. °C >1,332

4.2. Hemispherical Temp. °C >1,332

4.3 Fusion Temp. °C >1,332

A-2. Ash

The following information is based on the analytical results of 2 kinds of ash samples, named

as “Jojobera” and “MPL (Maithon Power Limited)”. “MPL” ash was selected as design case

since the particle size of “MPL” ash is smaller than that of “Jojobera”, and it should be safer to

design dust removal unit.

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SHEET 5 OF 8

FORM 1005-2 3



No. Particulars Units Reference

(Jojobera)

Design

(MPL)


5.1 Silica (SiO2) % 57.60 56.11

5.2 Alumina (Al2O3) % 28.80 29.96

5.3 Iron oxides (Fe2O3) % 5.87 6.00

5.4 Titania (TiO2) % 1.59 2.62

5.5 Potassium oxide (K2O) % 1.67 1.83

5.6 Lime (CaO) % 1.14 1.31

5.7 Phosphoric Anhydride (P2O5) 0.74 0.84

5.8 Magnesia (MgO) % 0.61 0.48

5.9 Sulphuric Anhydride (SO3) % 0.15 0.23

5.10 Sodium oxide (Na2O) % 1.30 0.11

5.11 Balance Alkalies (by difference) % 0.53 0.50


6.1 D10 μm 8.92 7.74

6.2 D50 μm 28.94 23.33

6.3 D90 μm 102.43 111.02

6.4 Detail distribution (Attach-1A) (Attach-1B)

7.0 Density



A-3. Flue Gas (Jojobera Power Plant Unit 5)


8.0 Gas Condition


Economizer

Outlet of

Air Heater

Outlet of

ESP

8.2 Total Gas Flow

Rate (wet)

kg/hr Not available Not available 600,610

8.3 Nm3/h Not available Not available 457,999

8.4 Gas Temp. °C 314/310 145/140 129/124

8.5 Gas Pressure mmwc -15.37 Not available -220/ -217

8.6 Gas viscosity cP Not available Not available Not available

8.7 Gas density kg/Nm3 Not available Not available 1.31


9.1 Oxygen vol %-

wet

4.1/4.5 6.47/6.6 4.61

9.2 vol %-dry 5.09

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SHEET 6 OF 8

FORM 1005-2 3



9.3 H2O vol %-

wet

9.32

9.4 CO2 vol %-

wet

14.5/14.6 11.5/12.6 13.06

9.5 NOx kg/hr 290

9.6 mg/Nm3-

dry

@6%O2

655

9.7 NO2 kg/hr 30

9.8 mg/Nm3-

dry

@6%O2

65

9.9 SOx kg/hr 540

9.10 mg/Nm3-

dry

@6%O2

1225

9.11 Dust kg/hr 45.8

9.12 g/Nm3-

dry

@6%O2

0.1



Permissive level: SO2 600 mg/Nm3, NOx 300 mg/Nm3, SPM 50 mg/Nm3

B-2. Treated Gas (Demonstration Unit)




14.0 Gas Condition

14.1 Location Outlet of Demonstration Unit

14.2 Gas Pressure mmH2OG -150

15.0 Treated Gas Composition (Note 1)

15.1 NOx mg/Nm3-dry

@ 6%O2

< 100

15.2 SOx mg/Nm3-dry

@ 6%O2

< 100

15.3 Dust mg/Nm3-dry < 30

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 7 OF 8

FORM 1005-2 3



@ 6%O2


Note1 : The treated gas composition shall be achieved for the inlet gas composition defined in

the Section 3.

JOB No. DOC. No. REV. 0-7745 S-1222-102 1

SHEET 8 OF 8

FORM 1005-2 3













F

E

D

C

B

A

8 7 6 5 4 3 2 1

F

E

D

C

B

A

8 7 6 5 4 3 2 1

S. Kameda

JOB CODE


REVISIONS


DWG. NO.B

DATE： SCALE None

SIZE REV.



T. Kayukawa

0 7 7 4 5

H. Isobe

0

2017-10-XX


02

D-1223-101

0 0 0 0

DRAFT

(NOTE1)

NOTE:

FROM ELECTROSTATIC PRECIPITATOR(EXISTING)


C-101A~FDeSOx TOWER

V-102A/BSPENT AGENT

HOPPERZ-103A/BFRESH AGENT CONVEYER

WC INV

B/LFLUE GAS


WC INV

V-101B

Z-102A

Z-103A

Z-102B

Z-103B


Z-104A

Z-104B

V-102A

NOTE2

101

102A

102B

103B

103A104

NOTE2


M

M

M



C-101B

LSL

LSM

INV

MMMM

MMMM

C-101C

NO

TE 3C-101A

MM

M M

C-101D

LSL

LSM

INV

MMMM

MMMM

C-101F

NO

TE 3C-101E

MM

M M

V-102B

M

V-101A

TO STACK (EXISTING)

B/LTREATED FLUE GAS


DeSOx unitinlet gas




KPaG -2.3 -2.3 -3.8 -3.8Nm3/h 230,000,000 115,000,000 115,000,000 230,000,000

SOx mg/Nm3 800 800 100 100NOx mg/Nm3 300 300 300 300

mg/Nm3 50 50 50 50

Stream No.

Fluid

Phase

Concentration

Dust

TemperaturePressureFlow rate

F

E

D

C

B

A

8 7 6 5 4 3 2 1

F

E

D

C

B

A

8 7 6 5 4 3 2 1

S. Kameda

JOB CODE


REVISIONS


DWG. NO.B

DATE： SCALE None

SIZE REV.



T. Kayukawa

0 7 7 4 5

H. Isobe

0

2017-10-XX


02

D-1223-102

0 0 0 0

DRAFT

(NOTE1)

NOTE:

TO DeNOx UNIT

FROM ECONOMIZER (EXISTING)

S-102A HMULTICYCLONE

FLUE GASD-1223-301

S-101A HINERTIA DUST

COLLECTOR


C-101A~HDeSOx TOWER

V-102A/BSPENT AGENT

HOPPER Z-103A/BFRESH AGENT CONVEYER

WC INV

B/LFLUE GAS


WC INV

V-102B

V-103DUST HOPPER

C-101B

V-101B

V-101A

Z-102A

Z-103A

Z-102B

Z-103B


Z-104A

Z-104B

Z-105DUST CONVEYOR

V-102A

NOTE2

M

S-101A HS-102A H

101

102A

102B

103B

103A 104

LSL

LSM

INV

LSL

LSM

INV

LAND FILL

V-103

Z-105

TO ATM AT SAFETY

LOCATION

M M M M M M M M

M MM MM MM M

NOTE2


MMMMMM

M MMMMM

MMMMMM

M MMMMM

M

M

M


C-101C C-101D

C-101F C-101G C-101H

M

NO

TE 3


NO

TE 3


DeSOx unitinlet gas




KPaG -0.2 -2.2 -3.7 -3.7Flow rate Nm3/h 230,000,000 115,000,000 115,000,000 230,000,000

SOx mg/Nm3 800 800 100 100NOx mg/Nm3 600 600 600 600

mg/Nm3 100,000 1,000 30 30

Stream No.

Fluid

Phase

Concentration

Dust

TemperaturePressure

S-103

S-103DUST FILTER

C-101A

MM

M M

MM

MM

C-101E

F

E

D

C

B

A

8 7 6 5 4 3 2 1

F

E

D

C

B

A

8 7 6 5 4 3 2 1

S. Kameda/M. Hatayama

JOB CODE


REVISIONS


DWG. NO.B

DATE： SCALE None

SIZE REV.

TATA Power Co., Ltd.Process Flow Diagram for DeNOx unit

(Commercial Plant Case-3)

T. Kayukawa

0 7 7 4 5

H. Isobe

0

2017-10-XX

2017-10-XX0 For preliminary study S.K/M.H H.I T.K

02

D-1223-301

0 0 0 0

DRAFT

FROM DeSOx UNIT

FLUE GAS

R-301

M

301

303

304

M-301

M-301FLUE GAS/NH3 MIXER

R-301SCR REACTOR

Z-302DUST BLASTER

D-1223-102

B/LTREATEDFLUE GAS

TO AIR HEATER

Z-301AMMONIA INJECTION PACKAGE

NOTE:

DUSTCOLLECTION

1. THE CONFIGURATION IS PRELIMINARY ANDSHALL BE UPDATED BASED ON VENDORINFORMATION DURING DETAIL ENGINEERING.

302

Z-301

PA

IW

ｖ v v v

FC

TO GRADE

NH3（VAPOR）

NH3（LIQUID）

BY VENDOR

BY CONTRACTOR

NOxSOxO2

AI

Z-302

NOTE1

E

TS

LS

301 302 303 304

Flue Gas_Main NH3 + Air SCR inlet gas SCR outlet gas


KPaG -3.7 15 -4.1 -6kmol/hr 102,679 3,197 105,876 105,887Nm3/h 2,300,000 71,612 2,371,612 2,371,876

SOx mg/Nm3 100 0 97 97NOx mg/Nm3 600 0 582 97

mg/Nm3 30 0 30 30

Concentration

Dust

Flow rate

Stream No.

Fluid

PhaseTemperature

Pressure

NOxSOxO2NH3

AI

tata power 石炭火力発電所向け 乾式脱硫脱硝システムの ...3.2 事業目的...

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tata power 石炭火力発電所向け乾式脱硫脱硝システムの ...3.2 事業目的...