System for metering electricity by integrating in-phase current
Abstract
This record has no abstract on file.
Term
Projected expiry 11 July 2028.
- Priority
- Filed
- Granted
- Today
- Projected expiry
29 claims: 28 independent, 1 dependent
- 1配電変圧器における電圧および電流を測定するメータであって、 ボディ部とレバー部を有し、上記レバー部は上記ボディ部に可動的に搭載され、上記レバー部が上記ボディ部に接する閉位置と、上記レバー部が上記ボディ部から離れる開位置との間で上記レバー部が可動である、ハウジングと、 第1電流センサおよび第2電流センサと、 上記配電変圧器の各ターミナルX1、3に装荷可能な第1電圧リードおよび第2電圧リードと、 上記第1電流センサ、上記第2電流センサ、上記第1電圧リードおよび上記第2電圧リードに接続され、上記第1電流センサ、上記第2電流センサ、上記第1電圧リードおよび上記第2電圧リードからの電圧と電流の各測定値を記録するようになっている、計器モジュールと、 上記計器モジュールに接続され、上記電圧と上記電流の各測定値を離れた使用者に通信するための通信モジュールとを備え、 上記第1電流センサおよび上記第2電流センサは、それぞれ、2つの対応する各センサ分画部に分割され、 上記第1電流センサおよび上記第2電流センサの一方のセンサ分画部は、上記ハウジングのボディ部に形成され、上記第1電流センサおよび上記第2電流センサの他方の対応するセンサ分画部は、上記ハウジングのレバー部に形成され、 上記第1電流センサおよび上記第2電流センサの各センサ分画部は、上記第1電流センサおよび上記第2電流センサのそれぞれが、上記ハウジングのレバー部が閉位置にあるとき、上記配電変圧器のターミナルを受け入れる大きさの開口部の中心を有するように構成され、 上記第1電流センサおよび上記第2電流センサは、上記ハウジング上にて、上記メータが上記配電変圧器の各ターミナルに装荷でき、上記第1電流センサが上記配電変圧器の1つのターミナルを受け入れ、上記第2電流センサが上記配電変圧器の他のターミナルを受け入れるように配置され 、 上記第1電圧リードおよび上記第2電圧リードは、それぞれ、上記第1電流センサおよび上記第2電流センサに隣り合う上記ハウジング上に装荷される導電性クリップであり 、 上記各クリップは、上記第1電流センサおよび上記第2電流センサの対応する開口部に受け入れられるターミナルと電気的に接続するような大きさに構成されている 、メータ。
- 2上記第1電流センサおよび上記第2電流センサのそれぞれは、上記開口部の中心から放射状に延びる複数の各平面型コイルを含み、 上記各平面型コイルは、上記開口部の中心の中心軸に対して略放射対称に配置され、 上記第1電流センサおよび上記第2電流センサの各平面型コイルの一部は、上記ハウジングの上記ボディ部に含まれ、上記第1電流センサおよび上記第2電流センサの各平面型コイルの他の一部は、上記ハウジングの上記レバー部に含まれ、 上記各平面型コイルは、上記第1電流センサおよび上記第2電流センサのそれぞれにて電気的に相互接続されて、上記各平面型コイルの各出力電圧を、組み合わせ、上記第1電流センサおよび上記第2電流センサの各出力ターミナルに印加するようになっている、請求項1に記載のメータ。
- 3配電変圧器における電圧および電流を測定するメータであって、 ボディ部とレバー部を有し、上記レバー部は上記ボディ部に可動的に搭載され、上記レバー部が上記ボディ部に接する閉位置と、上記レバー部が上記ボディ部から離れる開位置との間で上記レバー部が可動である、ハウジングと、 第1電流センサおよび第2電流センサと、 上記配電変圧器の各ターミナルX1、3に装荷可能な第1電圧リードおよび第2電圧リードと、 上記第1電流センサ、上記第2電流センサ、上記第1電圧リードおよび上記第2電圧リードに接続され、上記第1電流センサ、上記第2電流センサ、上記第1電圧リードおよび上記第2電圧リードからの電圧と電流の各測定値を記録するようになっている、計器モジュールと、 上記計器モジュールに接続され、上記電圧と上記電流の各測定値を離れた使用者に通信するための通信モジュールとを備え、 上記第1電流センサおよび上記第2電流センサは、それぞれ、2つの対応する各センサ分画部に分割され、 上記第1電流センサおよび上記第2電流センサの一方のセンサ分画部は、上記ハウジングのボディ部に形成され、上記第1電流センサおよび上記第2電流センサの他方の対応するセンサ分画部は、上記ハウジングのレバー部に形成され、 上記第1電流センサおよび上記第2電流センサの各センサ分画部は、上記第1電流センサおよび上記第2電流センサのそれぞれが、上記ハウジングのレバー部が閉位置にあるとき、上記配電変圧器のターミナルを受け入れる大きさの開口部の中心を有するように構成され、 上記第1電流センサおよび上記第2電流センサは、上記ハウジング上にて、上記メータが上記配電変圧器の各ターミナルに装荷でき、上記第1電流センサが上記配電変圧器の1つのターミナルを受け入れ、上記第2電流センサが上記配電変圧器の他のターミナルを受け入れるように配置され、 上記第1電流センサおよび上記第2電流センサのそれぞれは、上記開口部の中心から放射状に延びる複数の各平面型コイルを含み、 上記各平面型コイルは、上記開口部の中心の中心軸に対して略放射対称に配置され、 上記第1電流センサおよび上記第2電流センサの各平面型コイルの一部は、上記ハウジングの上記ボディ部に含まれ、上記第1電流センサおよび上記第2電流センサの各平面型コイルの他の一部は、上記ハウジングの上記レバー部に含まれ、 上記各平面型コイルは、上記第1電流センサおよび上記第2電流センサのそれぞれにて電気的に相互接続されて、上記各平面型コイルの各出力電圧を、組み合わせ、上記第1電流センサおよび上記第2電流センサの各出力ターミナルに印加するようになっており、 上記各平面型コイルは、第1回路および第2回路にて電気的に相互接続される第1セットおよび第2セットを有し、 上記第1セットの各平面型コイルと、上記第2セットの各平面型コイルとは、インターリーブされ、 上記第1回路は、差動増幅器におけるプラス入力に接続され、上記第2回路は、上記差動増幅器におけるマイナス入力に接続されている、メータ。
- 4上記ハウジングの上記レバー部は、上記ハウジングの上記ボディ部に対して回動するように結合され、 さらに、上記レバー部を上記閉位置において保持可能とするためのラッチを備えている、請求項1に記載のメータ。
- 5上記ハウジングの上記レバー部は、上記ハウジングの上記ボディ部に対して回動するように結合され、 さらに、上記レバー部を上記閉位置において保持可能とするためのラッチを備えている、請求項 3 に記載のメータ。
- 6上記通信モジュールは、電圧および電流の各測定値を、離れた使用者に、上記配電変圧器に接続された電線を通して通信するための電力線通信モジュールを備えている、請求項 5 に記載のメータ。
- 7上記計器モジュールは、一定の時間間隔で電圧および電流の各測定値を定期的に測定し、メモリに上記各測定値を記憶するように構成され、 上記通信モジュールは、上記記憶された各測定値を、離れた使用者へ送信するように構成されている、請求項 5 に記載のメータ。
- 8上記計器モジュールは、一定の時間間隔で電圧および電流の各測定値を定期的に測定し、メモリに上記各測定値を記憶するように構成され、 上記通信モジュールは、上記記憶された各測定値を、離れた使用者へ送信するように構成されている、請求項 6 に記載のメータ。
- 9少なくとも2つの各ターミナルを有するタイプの変圧器における電圧および電流を測定するためのメータであって、 ハウジングと、 上記各ターミナルに装荷可能な、クランプオン式の第1電流センサおよびクランプオン式の第2電流センサと、 上記各ターミナルに装荷可能な第1電圧リードおよび第2電圧リードと、 上記第1電流センサ、上記第2電流センサ、上記第1電圧リードおよび上記第2電圧リードに接続され、上記第1電流センサ、上記第2電流センサ、上記第1電圧リードおよび上記第2電圧リードからの電圧および電流の各測定値を記録するようになっている計器モジュールと、 上記電圧および上記電流の各測定値を、離れた使用者に通信するための、上記計器モジュールに接続された通信モジュールとを備え、 上記第1電流センサおよび上記第2電流センサのそれぞれは、開口部の中心から放射状に配置された、各平面型コイルの第1セットおよび第2セットを含み、 上記各平面型コイルは、中心軸に対して略放射対称に位置され、 上記第1電流センサの各平面型コイルは、互いに接続されて、上記各平面型コイルの出力電圧が組み合わされ、上記第1電流センサの出力ターミナルに印加されるようになっており、 上記第2電流センサの各平面型コイルは、互いに接続されて、上記各平面型コイルの出力電圧が組み合わされ、上記第2電流センサの出力ターミナルに印加されるようになっており、 上記第1セットの上記各平面型コイルと、上記第2セットの上記各平面型コイルは、それぞれ、第1回路および第2回路にて、電気的に相互接続され、 上記第1回路および第2回路は、インターリーブされ、上記第1回路は、差動増幅器におけるプラス入力に接続され、上記第2回路は、上記差動増幅器におけるマイナス入力に接続されている、メータ。
- 10上記通信モジュールは、電圧および電流の各測定値を、離れた使用者に、上記変圧器に接続された電線を通して通信するための電力線通信モジュールを備えている、請求項 9 に記載のメータ。
- 11上記計器モジュールは、一定の時間間隔で電圧および電流の各測定値を定期的に測定し、メモリに上記各測定値を記憶するように構成され、 上記通信モジュールは、上記記憶された各測定値を、離れた使用者へ送信するように構成されている、請求項 10 に記載のメータ。
- 12上記計器モジュールは、一定の時間間隔で電圧および電流の各測定値を定期的に測定し、メモリに上記各測定値を記憶するように構成され、 上記通信モジュールは、上記記憶された各測定値を、離れた使用者へ送信するように構成されている、請求項 11 に記載のメータ。
- 13上記ハウジングは、ボディ部とレバー部とを有し、上記レバー部は、上記ボディ部に可動的に搭載され、上記レバー部が上記ボディ部に接する閉位置と、上記レバー部が上記ボディ部から離れる開位置との間で上記レバー部が可動であり、 上記第1電流センサおよび上記第2電流センサのそれぞれは、2つの対応する各センサ分画部に分割され、 上記第1電流センサおよび上記第2電流センサの一方の各センサ分画部は、上記ハウジングの上記ボディ部に形成され、上記第1電流センサおよび上記第2電流センサの他方の対応する各センサ分画部は、上記ハウジングの上記レバー部に形成され、 上記第1電流センサおよび上記第2電流センサの各センサ分画部は、上記第1電流センサおよび上記第2電流センサのそれぞれが上記ハウジングの上記レバー部の上記閉位置にあるとき、上記変圧器のターミナルを受け入れられる大きさの開口部の中心を有するように構成され、 上記第1電流センサおよび上記第2電流センサは、上記ハウジング上にて、上記メータが上記変圧器の各ターミナルに装荷でき、上記第1電流センサが上記変圧器の1つのターミナルを受け入れ、上記第2電流センサが上記変圧器の他のターミナルを受け入れるように、位置合わせされている、請求項 12 に記載のメータ。
- 14上記第1電圧リードおよび上記第2電圧リードは、それぞれ、上記第1電流センサおよび上記第2電流センサに隣り合う位置の上記ハウジングに装荷される導電性のクリップを含み、 上記各クリップは、対応する電流センサの開口部に受け入れられるターミナルと電気的に接続する大きさに構成されている、請求項 13 に記載のメータ。
- 15上記ハウジングの上記レバー部は、上記ハウジングのボディ部に回動するように結合され、 さらに、上記レバー部を上記閉位置において保持するためのラッチを備えている、請求項 14 に記載のメータ。
- 16上記通信モジュールは、電圧および電流の各測定値を、離れた使用者に、上記変圧器に接続された電線を通して通信するための電力線通信モジュールを備えている、請求項 15 に記載のメータ。
- 17少なくとも2つの各ターミナルを有するタイプの変圧器における電圧および電流を測定するためのメータであって、 ハウジングと、 上記各ターミナルに装荷可能な、クランプオン式の第1電流センサおよびクランプオン式の第2電流センサと、 上記各ターミナルに装荷可能な第1電圧リードおよび第2電圧リードと、 上記第1電流センサ、上記第2電流センサ、上記第1電圧リードおよび上記第2電圧リードに接続される計器モジュールと、 上記計器モジュールに接続され、電圧の測定値、電流の測定値、および積算同相電流の測定値を離れた使用者に通信するための通信モジュールを備え、 上記計器モジュールは、一定の期間にて、上記第1電流センサ、上記第2電流センサ、上記第1電圧リードおよび上記第2電圧リードからの電圧、電流、および平均電流の各測定値を記録するようになっており、 上記計器モジュールは、測定時間の長さにより乗算された平均同相電流と等しい、積算同相電流の測定値を、上記期間中において記録するように構成されている、メータ。
- 18上記通信モジュールは、電圧および電流の各測定値を、離れた使用者に、上記変圧器に接続された電線を通して通信するための電力線通信モジュールを備えている、請求項 17 に記載のメータ。
- 19上記第1電流センサおよび上記第2電流センサは、それぞれ、開口部の中心から放射状に配置された複数の各平面型コイルを含み、 上記各平面型コイルは、略放射対称にお互い間隔を有し、 上記各平面型コイルは、上記開口部に対して略軸方向かつ各放射方向を含む、角度を伴って間隔を有する各平面に沿って配置され、または、上記各平面に対して同じ傾きで傾けられ、 上記第1電流センサおよび上記第2電流センサの各平面型コイルの一部は、上記ハウジングのボディ部に含まれ、上記第1電流センサおよび上記第2電流センサの各平面型コイルの他の一部は、上記ハウジングのレバー部に含まれ、 上記第1電流センサおよび上記第2電流センサのそれぞれにおいて、上記各平面型コイルは、電気的に相互接続され、上記各平面型コイルの各出力電圧が組み合わされ、上記センサの各出力ターミナルに印加されるようになっている、請求項 17 に記載のメータ。
- 20上記各平面型コイルは、第1回路において電気的に相互接続された、第1セットの各平面型コイル、および、第2回路において電気的に相互接続された、第2セットの各平面型コイルを有し、 上記第1セットの平面型コイルおよび上記第2セットの各平面型コイルは、インターリーブされ、 上記第1回路は、差動増幅器におけるプラス入力に接続され、上記第2回路は、上記差動増幅器におけるマイナス入力に接続されている、請求項 19 に記載のメータ。
- 21上記ハウジングは、ボディ部とレバー部とを有し、 上記レバー部は 、上 記ボディ部に搭載され、上記レバー部が上記ボディ部に接する閉位置と上記レバー部が上記ボディ部から離れる開位置との間で可動であり、 上記第1電流センサ、上記第2電流センサは、それぞれ、2つの対応する各センサ分画部に分割され、 上記第1電流センサおよび上記第2電流センサの一方の各センサ分画部は、上記ハウジングの上記ボディ部に形成され、上記第1電流センサおよび上記第2電流センサの他の一方の各センサ分画部は、上記ハウジングの上記レバー部に形成され、 上記第1電流センサおよび上記第2電流センサの各センサ分画部は、上記第1電流センサおよび上記第2電流センサのそれぞれが、上記ハウジングの上記レバー部が上記閉位置にあるとき、上記変圧器のターミナルを受け入れられる大きさに形成された開口部の中心を有するように構成され、 上記第1電流センサおよび上記第2電流センサは、上記ハウジング上にて、上記メータが上記変圧器の各ターミナルに装荷でき、上記第1電流センサが上記変圧器の1つのターミナルを受け入れ、上記第2電流センサが上記変圧器の他のターミナルを受け入れるように位置合わせされている、請求項 20 に記載のメータ。
- 22上記第1電圧リードおよび上記第2電圧リードは、それぞれ、上記第1電流センサおよび上記第2電流センサに隣り合う位置の上記ハウジングに装荷される導電性のクリップを含み、 上記各クリップは、対応する電流センサの開口部に受け入れられるターミナルと電気的に接続する大きさに構成されている、請求項 21 に記載のメータ。
- 23上記ハウジングの上記レバー部は、上記ハウジングのボディ部に回動するように結合され、 さらに、上記レバー部を上記閉位置において保持するためのラッチを備えている、請求項 22 に記載のメータ。
- 24少なくとも1つの給電線に接続される給電線変圧器を備える配電ネットワークを請求項 17 に記載のメータを用いてモニタする方法であって、 上記給電線は、次に複数の各配電変圧器に接続され、上記各配電変圧器のそれぞれは、次に負荷に接続され、上記各配電変圧器のそれぞれは、請求項 17 に記載のメータに接続され、 上記方法は、 上記各配電変圧器において、一定期間、上記一定期間の長さによって乗算された、変圧器での平均同相電流と等しい、積算同相電流値を記録する工程と、 上記一定期間にて、給電線メータにおいて、上記一定期間の長さによって乗算された、給電線での平均同相電流と等しい積算同相電流値を記録する工程と、 上記各配電変圧器および上記給電線メータでの各積算同相電流値を、上記各配電変圧器および上記給電線メータの各公称電圧によって乗算することによって各正規化活性エネルギー値を生成する工程と、 上記各配電変圧器において測定された各正規化活性エネルギー値の合計と、上記給電線での正規化活性エネルギー値とを比較する工程とを含む、方法。
- 25導電体に装荷可能な、上記導電体を通過する電流を感知するための電流センサであって、 上記導電体を受け入れられる大きさに形成された開口部の中心を有するハウジングと、 上記ハウジングに装荷され、各平面型コイルの第1セットおよび第2セットとを備え、 上記第1セットおよび上記第2セットの各平面型コイルは、上記開口部の中心から放射状に、かつ、上記開口部の中心軸に対して略放射対称に配置され、 上記電流センサ毎の上記各平面型コイルは、電気的に相互接続され、上記各平面型コイルの各出力電圧が組み合わされ、上記電流センサの各出力ターミナルに印加されるようになっており、 上記第1セットおよび上記第2セットの各平面型コイルは、それぞれ、第1回路および第2回路において電気的に相互接続され、 上記第1セットの各平面型コイルおよび上記第2セットの各平面型コイルは、インターリーブされ、上記第1回路は、差動増幅器におけるプラス入力に接続され、上記第2回路は、上記差動増幅器におけるマイナス入力に接続される、電流センサ。
- 26上記ハウジングは、ボディ部とレバー部とを有し、 上記レバー部は、上記ボディ部に可動的に搭載され、上記レバー部が上記ボディ部に接する閉位置と、上記レバー部が上記ボディ部から離れる開位置との間で可動であり、 上記ボディ部と上記レバー部の間に開口部が中心を有して形成され、 上記第1セットおよび上記第2セットにおける各平面型コイルの一部は、上記ハウジングの上記ボディ部に含まれ、上記第1セットおよび上記第2セットにおける各平面型コイルの他の一部は、上記ハウジングの上記レバー部に含まれる、請求項 25 に記載の電流センサ。
- 27上記レバー部は、上記ボディ部に対して回動するように連結され、 さらに、上記閉位置において上記ボディ部と上記レバー部を開放可能に保持するためのラッチ機構を備えている、請求項 26 に記載の電流センサ。
- 28上記ラッチ機構は、上記ボディ部における第1磁力部と、上記レバー部における第2磁力部とを有する磁力ラッチを含む、請求項 27 に記載の電流センサ。
- 29給電線変圧器と、少なくとも1つの給電線に接続される給電線メータとを有するタイプの配電ネットワークをモニタする方法であって、 上記給電線は、次に、複数の各配電変圧器に接続され、上記各配電変圧器は、次に、負荷に接続され、 上記方法は、 所定の期間にて、上記各配電変圧器のそれぞれにおける、変圧器での平均電流値を記録する工程と、 上記期間において、上記各配電変圧器のそれぞれにおける積算同相電流値を算出することを、上記期間の長さにて、上記変圧器での平均同相電流値を乗算することによって算出する工程と、 上記期間にて、上記給電線メータにおいて、上記給電線での平均同相電流値を記録する工程と、 上記期間にて、上記給電線メータにおける積算同相電流値を、上記期間の長さにて、上記給電線での平均電流値を乗算することによって算出する工程と、 上記各配電変圧器において測定された各積算電流値の合計と、上記給電線での、積算された電流値とを比較する工程とを含む、方法。
Independent claims29
100 paragraphs, as filed
The present invention generally relates to transformer meters that record each measured value of voltage or current from a transformer and other data, and transmit each measured value and other data to a user away from the transformer.
Meters for distribution transformers (automatic measuring instruments) have been used to monitor the status of distribution transformers and to measure the electrical energy consumed by the load connected to the distribution transformer. It was.
Traditionally, meters used to monitor distribution transformers have been large devices with built-in solid-core or split-core current sensors connected to the instrument module. While solid-core and split-core current sensors have been used to reliably measure current, they are prone to errors due to the non-linear characteristics of ferromagnetic cores, improper mounting, and noise. It was.
As a result, accurate current monitoring in distribution transformers has not always been possible. Meters for distribution transformers, which do not have the ability to measure current with a high level of accuracy, are often not needed, especially when monitoring only the condition of the transformer.
<p num="0005"> However, if the distribution transformer is to be monitored in terms of accurately and accurately measuring the electrical energy used by the load connected to the transformer, an improved meter is needed.</p><p num="0006"> In particular, meters for distribution transformers with very high accuracy are needed when the meters are used in systems that measure and measure the loss of electrical energy (power) in networks. In addition, there is a clear need for meters for distribution transformers that can be loaded quickly without the need to shut down power.</p>
<p num="0007"> According to one aspect of the invention, there is provided an improved meter for accurately measuring voltage, current, and other data in a distribution transformer. The meter is easy to load and has high accuracy.</p><p num="0008"> The meter includes a housing having a body portion and a lever portion, the lever portion is movably connected to the body portion, and a closed position where the lever portion contacts the body portion and an open position where the lever portion separates from the body portion. It is movable between. The meter has a first current sensor and a second current sensor, which are divided into two corresponding sensor portions, respectively. One sensor portion of each of the above sensors is formed on the body portion of the housing, and the corresponding other sensor portion of each of the upper sensors is formed on the lever portion of the housing.</p><p num="0009"> Each sensor part of the first current sensor and the second current sensor is such that each of the first current sensor and the second current sensor accepts the terminal of the transformer when the lever part of the housing is in the first position. It is configured to have the center of the sized opening. The first current sensor and the second current sensor are housings so that the meter can be loaded into the terminal of the transformer in which the first current sensor accepts the terminal of the transformer and the second current sensor accepts the other terminals of the transformer. Is placed in.</p><p num="0010"> Further, the meter includes a first voltage lead and a second voltage lead that can be loaded into the terminals X1 and X3 of the secondary circuit of the transformer, and an instrument module connected to each of the current sensors and each of the voltage leads. Be prepared. The instrument module is adapted and configured to record voltage and current measurements from each of the current sensors and voltage leads. Finally, the meter includes a communication module connected to the instrument module for communicating voltage and current measurements to remote users.</p><p num="0011"> According to another aspect of the invention, an improved meter for measuring voltage and current in a transformer is provided with a high degree of accuracy and accuracy. The meter has a housing and a clamp-on first current sensor and a clamp-on second current sensor that can be loaded into the transformer terminal. Each of the first current sensor and the second current sensor has a first set and a second set of each planar coil arranged radially from the center of the opening, and each of the above planar coils has a center of the opening. It is arranged so as to be substantially radial symmetric with respect to the central axis of.</p><p num="0012"> The coils are electrically interconnected in each of the current sensors so that the output voltages of the coils are combined and applied to the output terminals of the current sensor. The first and second sets of the planar coils are electrically interconnected within the first and second circuits, respectively. Each coil in the first set and each coil in the second set are interleaved, the first circuit is connected to the positive input in the differential amplifier, and the second circuit is connected to the negative input in the differential amplifier.</p><p num="0013"> Further, the meter has a first voltage lead and a second voltage lead that can be loaded into each terminal of the transformer, and an instrument module connected to each of the current sensors and each voltage lead. The instrument module is adapted and configured to record voltage and current measurements from each of the current sensors and voltage leads. The meter also has a communication module connected to an instrument module for communicating voltage and current measurements to remote users.</p><p num="0014"> According to yet another aspect of the invention, meters are provided for measuring voltage and current in a transformer. The meter has a housing, a clamp-on type first current sensor and a second current sensor, and a first voltage lead and a second voltage lead.</p><p num="0015"> The meter further comprises an instrument module connected to each of the current sensors and voltage leads. The instrument module is adapted and configured to record each measured value of voltage and current from each of the current sensors and each of the voltage leads at intermittent times. In addition, the instrument module samples the current at a sample rate much higher than the 60Hz power system frequency and multiplies each measurement by the corresponding value in a pure sinusoidal waveform to provide an integrated in-phase current or AIPC measurement. It is configured to record.</p><p num="0016"> The sine waveform has the same phase as the voltage waveform, has the same frequency, and has a root mean square amplitude of 1, and is for receiving the sum of the multiplication values and dividing by the sampling frequency. .. The meter also has a communication module connected to an instrument module for communicating voltage, current, and AIPC measurements to remote users.</p><p num="0017"> According to yet another aspect of the invention, a method of using a meter capable of recording and transmitting each measurement of AIPC, as described in each of the above clauses, which monitors an electrical distribution network Provided. The distribution network has a feeder transformer connected to one of at least one feeder, the other of the feeders is connected to each of a plurality of distribution transformers, and each of the distribution transformers , Connected to the load.</p><p num="0018"> Each distribution transformer in the network is connected to a meter capable of recording AIPC, as specified above. The above method has a step of recording AIPC in each distribution transformer for a certain period of time, the AIPC is equal to the integral of the in-phase current, and the feeder AIPC is recorded in the feeder current meter of the current passing through the feeder meter, and each The AIPC value is multiplied by the corresponding nominal voltage to determine the normalized active energy (NAE) for each AIPC, after which the sum of each NAE value from the distribution transformer is compared to the feeder NAE value.</p><p num="0019"> The present invention, with reference to the accompanying drawings, in view of the above and in terms of other advantages that will be apparent to those skilled in the art to which this invention relates, as described herein. Will be explained. This illustrates a preferred exemplary embodiment of the principles of the invention.</p>
<figref num="1">FIG. 5 is a perspective view of a meter for a transformer manufactured based on the present invention, which is loaded on a pad-type distribution transformer.</figref><figref num="2">It is a perspective view in the closing direction of the meter for a transformer manufactured based on this invention.</figref><figref num="3">It is a perspective view in the opening direction of the meter for a transformer manufactured based on this invention.</figref><figref num="4">It is a perspective view of the meter for a transformer shown in FIG. 2 in which a part of the housing is cut out to show the details of each component of the meter.</figref><figref num="5">It is a perspective view of the meter for a transformer shown in FIG. 3 in which a part of the housing is cut out to show the details of each component of the meter.</figref><figref num="6">It is a circuit diagram which shows a part of the current sensor of this invention which shows how each component of a PCB coil is constructed.</figref><figref num="7">FIG. 6 is a perspective view of a planar coil component in the current sensor shown in FIG. 6 showing how the PCB coil component is connected to a twist-to-wire.</figref><figref num="8">FIG. 7 is a perspective view of the PCB coil component shown in FIG. 7, with the planar coil partially cut out to show how the twist-to-wire is connected to the PCB supporting the planar coil.</figref><figref num="9">It is a line diagram which shows the electric current path along the plane orthogonal to the plane of the PCB coil which was improperly wired.</figref><figref num="10">It is a line diagram which shows the electric current path along the plane orthogonal to the plane of a properly wired PCB coil.</figref><figref num="11">It is a block diagram which shows each component of the meter for a transformer manufactured based on this invention.</figref><figref num="12">It is a block circuit diagram which shows the meter for the transformer manufactured based on this invention connected to the distribution transformer which communicates with a remote data controller.</figref><figref num="13">It is a schematic block diagram which shows the system of this invention.</figref><figref num="14">It is a circuit diagram of the instrument module part in the meter for a transformer manufactured based on this invention.</figref><figref num="15">It is a schematic diagram of the upper surface layer for tracing a flexible circuit board used when constructing the current sensor of this invention.</figref><figref num="16">It is a schematic diagram of the bottom layer for tracing a flexible circuit board used when constructing the current sensor of this invention.</figref><figref num="17">It is a perspective view of the flexible circuit board used when constructing the current sensor of this invention.</figref><figref num="18">It is a schematic diagram which shows each possible alternative structure of the PCB coil component of this invention.</figref><figref num="19">It is a schematic diagram which shows the alternative embodiment of the system of this invention.</figref><figref num="20">It is a schematic diagram of the upper surface layer for tracing the alternative flexible circuit board used when constructing the current sensor of this invention.</figref><figref num="21">It is a schematic diagram of the bottom layer for tracing the alternative flexible circuit used when constructing the current sensor of this invention.</figref><figref num="22">It is a top view which shows the outer shape of the alternative flexible circuit used when constructing the current sensor of this invention.</figref><figref num="23">It is a perspective view of the alternative flexible circuit having a reinforced hard substrate used when constructing the current sensor of this invention.</figref><figref num="24">FIG. 5 is a plan view of an alternative flexible circuit having a reinforced hard substrate used when constructing the current sensor of the present invention.</figref><figref num="25">It is a side view of the flexible circuit which has a reinforced hard substrate used when constructing the current sensor of this invention.</figref><figref num="26">FIG. 5 is a perspective view of an alternative flexible circuit with a reinforced rigid substrate used in the construction of the current sensor of the present invention, which has each coil arranged in a desired toroidal shape.</figref><figref num="27">FIG. 3 is a perspective view of an alternative embodiment of the present invention in a housing designed for utility poles loaded with transformers.</figref><figref num="28">FIG. 5 is a plan view of an alternative embodiment of the present invention in a housing designed for utility poles loaded with transformers.</figref><figref num="29">It is a perspective view of the alternative embodiment of this invention which shows how the transformer is loaded on the utility pole which the transformer is loaded.</figref>
In each drawing, the member symbols for similar members indicate the corresponding parts in different drawings.
First, referring to FIG. 1, the present invention partially comprises an improved distribution transformer meter, generally represented as component number 10, wherein the distribution transformer meter is a terminal 12 of the distribution transformer 16. Configured to be loaded on 14, further configured to record voltage, current, temperature, energy, and AIPC measurements from the transformer, and a remote user (not shown) Is configured to communicate each of the above measured values. The distribution transformer 16 may be a pad-mounted distribution transformer as shown in FIG. 1, or may be a utility pole-loaded distribution transformer as shown in FIG. 29.
The present invention is suitable for use in pad-mounted distribution transformers, but can also be modified for use in utility pole-loaded distribution transformers. The padded distribution transformer 16 has terminals 12, 14 representing terminals X1, X3, and a neutral (X2) terminal 18. The cover 20 is provided on the transformer 16 to protect each terminal from the elements.
Next, referring to FIG. 11, the transformer meter 10 includes a pair of current sensors 22, 24, voltage leads 26, 28, instrument modules 30 connected to each current sensor and each voltage lead, and , Has a communication module 32 connected to the instrument module. Each voltage lead 26, 28 is connected to each class CC fuse 27, 29 to provide protection against electrical failure (overcurrent), respectively. The voltage leads 26 and 28 described above can be electrically connected to the secondary terminals 14 and 12 (X1 and X3 terminals) of the distribution transformer.
The meter may optionally have a third electrical lead 34 that can be connected to the neutral terminal 18. Without the third electrical lead, only one of the fuses 27, 29 above is required. In a preferred embodiment of the invention, the current sensors 22, 24, instrument module 30, and communication module 32 may be included in the housing 36 schematically shown in FIG. Each of the current sensors 24, 22 is preferably a "clamp-on" type current sensor, which does not require disconnection of the cable (not shown) connected to the terminal 12 or It can be attached to the terminal of the transformer without the need to stop the operation of the transformer. Some "clamp-on" current sensors are currently available on the market, but they can also be used in the present invention.
However, as will be described in more detail below, the respective current sensors 22 and 24 are disclosed in US Pat. No. 6,965,225 (de Buda), all of which are similar to the coreless current sensors incorporated herein by reference. It is preferable that the coreless current sensor of the above is modified.
The instrument module includes load resistors to the current sensors when conventional iron core current sensors are used. Alternatively, when the coreless current sensor is used, the instrument module has a special integrator instead of the load resistors. The instrument module also includes a resistor divider for measuring the voltage from the voltage leads and electronic circuits required to process the voltage and current input signals. During each measurement period, the instrument module measures the maximum voltage, minimum voltage, maximum current, total energy delivered to the load, and integrated in-phase current or in-phase current value delivered to the load known as AIPC. ..
The AIPC measurement is equal to the integrated value of the common mode current, and the common mode current is a current component in phase with the voltage. Therefore, in addition to the total energy supplied to the load, the meter can measure the total AIPC supplied to the load. Meter functionality can be easily handled by integrated circuit chips such as the ADE7753 available from Analog Devices, as shown in Figure 14.
Figure 14 shows how the instrument module is constructed. In a preferred embodiment, high accuracy can be achieved if the voltage input to the ADE7753 is given a pure sinusoidal waveform with a root mean square amplitude of 1 and the same phase and frequency as the actual voltage waveform. As shown in FIG. 14, when the actual voltage waveform is given to the ADE7753, the software is required to correct this by dividing the sampled increased energy value by the measured voltage.
Referring to FIG. 14, U2 is a programmable computer that includes a CPU, flash memory, and a communication interface. The connectors J7 and J8 are connected to current sensors, while the voltage leads are connected to the connector J1. Any temperature sensor (not shown) for measuring the temperature of the transformer may be connected to connector J6. Connector J4 provides a serial port for programming U2, and connector J5 is connected to the communication module. The data stored in U2 is sent to a communication module that sends the data to a remote data controller (not shown). Some suitable devices include telephone line modems, mobile phone devices, wireless LAN devices, etc., which can be used in communication modules and are readily available on the market.
Preferably, the communication module comprises a line carrier communication module that transmits data to a remote data controller via a line connected to the transformer itself. Communication devices for such feeder carriers are disclosed in US Pat. No. 6,549,120 (de Buda), the entire contents of which are incorporated herein by reference. Each of the voltage leads functions as a signal path for the signal of the feeder carrier. Further, each of the voltage leads enables voltage measurement and power supply to the unit, and enables the unit to operate without the need for batteries.
The instrument module is programmed to measure and record both the voltage applied to the transformer and the current passing through the transformer at predetermined time intervals. The instrument module measures voltage and current and continuously calculates electric energy by multiplying the voltage and current with each other. The instrument module calculates the total electrical energy transmitted through the transformer, which is equal to the average power multiplied by the length of time programmed for each recording. The above time is optional, but is usually 15 minutes, 30 minutes, or 1 hour.
In addition to each of these records, the instrument module records the maximum and minimum voltages observed during the time, as well as the maximum current observed during the time. The instrument module is also programmed to calculate an AIPC measurement over time that is equal to the integrated value of the common mode current.
At the end of each time, the meter sends an information packet to a distant user, which includes the maximum and minimum recorded voltages, the maximum current, the total electrical energy transmitted at the time, and the time. Includes total AIPC for.
With reference to FIG. 2, each component of the meter 10 is preferably contained within a housing 36 having a body portion 38 and a lever portion 40 movably attached to the body portion 38 at the joint 46. As shown in FIG. 2, the lever portion 40 is movable between a closed position where the lever portion 40 is in contact with the body portion 38 and an open position where the lever portion 40 is away from the body portion 38 (see FIG. 3).
The current sensors 22 and 24 are formed on both the body portion 38 and the lever portion 40 around the openings 42 and 44. The electric leads 26 and 28 are formed as clips at positions adjacent to the openings 42 and 44, respectively. As can be better seen in FIG. 3, the current sensors 22 and 24 are formed as two fractions 22A and 22B, respectively, and two fractions 24A and 24B, respectively. The fractions 22A and 24A are included in the body 38, and the fractions 22B and 24B are included in the lever 40.
Similarly, the portions at the openings 42, 44 are formed on both the lever portion 40 and the body portion 38. The positions of the openings 42, 44 are set to accommodate each of the terminals 12 and 14 in the distribution transformer (see FIG. 1). The current sensors 22 and 24 are arranged so as to be adjacent to each other, and by simply arranging the current sensors on the terminals and closing the housing, the current sensors can be placed on the terminals 12 of the distribution transformer. Spacing is provided between them so that they can be loaded directly into 14.
Next, referring to FIG. 4, each of the current sensors 22 and 24 is a coreless current sensor composed of a plurality of planar coil printed circuit boards (PCB coils) 48 arranged in a radial pattern from the openings 42 and 44, respectively. Is preferably included. It is preferable that each of the PCB coils is arranged substantially radially symmetrically with respect to the central axis of each opening.
Each of the PCB coils is arranged so as to be angled and spaced from each other in each plane containing and substantially including each radial direction with respect to the axis of each of the openings. When each of the PCB coils is tilted with respect to each of the planes, they are arranged radially from the opening so that they have the same tilt.
FIG. 18 shows three possible arrangements of each of the above PCB coils relative to the center of the opening. In each example, each PCB coil 115, 117, 119 is symmetrically arranged around the center of each opening 113, 120, 122, respectively. Each PCB coil is placed relative to the center of the opening so that the coil can extract a signal from a cable (not shown) that passes through the center of the opening, and if each PCB coil is approximately radial symmetric, the other Many arrangements are possible.
Referring to FIG. 4, the PCB coils are electrically interconnected in each current sensor so that the output voltages of the PCB coils are combined and applied to each output terminal of the sensor (not shown). ing. Each of the fractions 22B and 22A of the current sensor has a plurality of PCB coils, respectively, like the fractions 24A and 24B of the current sensor. Preferably, the current sensor fractions 22A, 22B and the current sensor fractions 24A, 24B each have the same number of PCB coils.
As can be better seen in FIG. 5, the current sensor fractions 22A and 22B, and the current sensor fractions 24A and 24B, when the lever 40 rotates away from the body 38, They are separated from each other, which allows the openings 42, 44 to be opened. By opening as shown in FIG. 5, the transformer terminals (not shown) are simply placed to fit into the openings 42, 44, and the transformer meter 10 is placed in the distribution transformer terminal. It can be easily loaded.
The latching means 50 is used to hold the two parts of the housing closed to each other. Any number of latch-type devices may be used to hold the two parts of the housing closed to each other, and in this embodiment each permanent magnet 52 to hold the two parts to each other. , 54 is used.
Referring to FIG. 4, each current sensor has two sets of PCB coils 56 and set 58 of PCB coils. As schematically shown in FIG. 6, the PCB coil set 56 and the PCB coil set 58 are electrically interconnected in the circuits 60 and 62, respectively. The PCB coil set 56 and the PCB coil set 58 are interleaved so that each of the PCB coil set 56 is adjacent to each other in the PCB coil set 58. Circuit 60 is connected to the positive input 63 on the differential amplifier 64 and circuit 62 is connected to the negative input 65 on the same differential amplifier. With the above arrangement of each PCB coil, any error caused by electrostatic pickup can be reduced.
With reference to FIGS. 7 and 8, each of the plurality of PCB coils 48 may be routed using a twisted conductor pair 66. The twisted conductor pair passes through the center of the opening 68 in the PCB coil, and each conductor 70, 72 is connected to the PCB coil on the PCB coil to form a circuit. When the conductors 70, 72 are connected to the PCB coil, they form an orthogonal loop that can mistakenly pick up the stray (parasitic) signal. If the PCB coil is improperly wired, the orthogonal loops will have a width equal to the thickness of the PCB coil, which is large enough to pick up the stray signal and the current from the stray signal. The accuracy of the sensor drops.
The PCB coil 48 is routed as shown in FIG. 8 to minimize errors that may result from the presence of the orthogonal loops. FIG. 9 shows the current through the orthogonal loop due to the improperly wired PCB coil, while FIG. 10 shows the current through the properly wired PCB coil. As can be seen here, the area of the orthogonal loop is much smaller if the PCB coil is wired correctly.
A single coil with multiple coils rather than multiple separate hard PCB coils to reduce the potential for signal errors induced by orthogonal loops and to reduce the cost of assembling the current sensor. A current sensor can be constructed using a long flexible printed circuit. One embodiment of such a current sensor is schematically shown as member number 74 in FIG.
The current sensor 74 consists of a long flexible printed circuit 76 having a first set 78 of coils and a second set 80 of coils. The first set 78 of the coils and the second set 80 of the coils are interleaved as in the previous example. Basically, the long flexible printed circuit 76 is crimped (set and fixed) to form multiple panels in a substantially star shape, and the panel containing the first set 78 of coils and the second set 80 of coils , Separated by a blank panel 82, no coil is formed in the blank panel 82.
The blank panel 82 holds the conductors 84, 86 connected to the first set 78 of the coil and the second set 80 of the coil, respectively. Also, as shown in FIGS. 15 and 16, the first set 78 of the coils and the second set 80 of the coils are in different circuits and are connected to the conductors 86, 84, respectively.
Since the flexible printed circuit is much thinner than the rigid PCB coil, the maximum width of the orthogonal loop is always small. In addition, the projection patterns used in FIGS. 15 and 16 show that each orthogonal loop formed in each coil adjacent to each other makes an angle of about 180 degrees with respect to each other and is therefore induced by the presence of each of the above orthogonal loops. Each voltage error that is made tends to cancel each other out, resulting in a smaller error as a whole.
While the current sensor shown in FIG. 17 is inexpensive, it is not ideal. Because flexible printed circuits can make it difficult to align the coil accurately, the flexibility of the printed circuit can lead to coil warpage such that the coil is not located in a fully set plane. Because there is sex.
This problem can be corrected by using multiple reinforced rigid substrates to maintain the correct placement with respect to the coil. Such a sensor is shown in FIG. An alternative embodiment for the current sensor, shown as part number 250 in FIG. 26, also comprises a flexible printed circuit 210, but with a plurality of reinforced rigid substrates 216 to ensure that the coils are aligned exactly in the ideal position. Has.
As best seen in FIGS. 20-22, the coils 212, 213, 214, 215 are formed in the printed circuit 210, similar to the current sensor 74 (see FIG. 17) above. The coils are separated by gaps 228 in the printed circuit 210, and the gaps 228 are set in the final form of the sensor so that the coils are reasonably spaced from each other.
The printed circuit 210 has an upper "arm" portion 218 and a lower "arm" portion 220, which are connected to each other by connecting strips 222. Similarly, the second layer of the printed circuit 210 has the coils 224, 225, 226, and 227 formed in the second layer, and the coils 224, 225, 226, and 227 are similarly flexible printed circuits. Separated from each other by each gap 228 in. Each opening 230 is formed substantially in the center of each of the coils in the printed circuit. Each opening 230 is used to align each of the coils in the final form of the sensor.
As shown in FIGS. 23, 24, and 25, the plurality of rigid reinforcing boards 216 are mounted on the printed circuit 210 so that the gap 228 separates the reinforcing boards 216 from each other. Each of the reinforcing substrates 216 ensures that each of the coils remains rigid and flat. Preferably, the coils are sandwiched between the substrates 216 to ensure they are in the correct orientation.
As can be seen in FIG. 26, the current sensor is simply assembled by positioning each of the reinforcing substrates 216 in the correct position, as shown. The gap 228 ensures that the coils sandwiched between the substrates 216 are properly oriented.
Next, referring to FIG. 12, the distribution transformer meter (DTM) 10 is connected to terminals 12, 14, and 18 of the distribution transformer 16 connected to the high voltage feeder line 88. Feed line 88 is then connected to distribution transformer 90, which is several kilometers away. The communication module (data collector) 92 of the feeder is connected to the terminal 94 of the distribution transformer 90. The feeder line communication module 92 is, of course, adapted and configured to receive each communication signal from the DTM10 when the feeder line communication module is provided in the DTM10.
The communication module 92 not only receives the data package from the DTM10, but also transmits a time synchronization signal that can be received by the DTM10. After the DTM10 receives the time sync signal from the communication module 92, it begins to measure and record the current and voltage information from the distribution transformer 16 and sends the data package to the communication module 92 after each time. Feed line communication modules preferably used as the communication module 92 are disclosed in US Pat. No. 6,549,120 (de Buda) and are referred to above.
To facilitate the use of the present invention with utility pole-loaded transformers, the housing of the DTM can be modified so that the DTM is loaded directly onto the utility pole-loaded transformer. A DTM according to the invention configured for use in utility pole loaded transformers is shown as part number 300 in FIGS. 27, 28, and 29. As shown in FIG. 27, the DTM 300 includes a concave side portion 311 and an arched housing 310 having an opening 312 with a passage 316 and an opening 314 with a passage 318. Further, the housing 310 has each mounting member 320 at a position adjacent to the concave side surface portion 311.
As shown in FIG. 28, the DTM300 has insulating puncture connectors 322, 324 arranged within the openings 312, 314, respectively. Similar to the above-described embodiment for DTM, the DTM300 has each current sensor 326, 328 consisting of a plurality of coils 330, 332, respectively. Similar to the embodiments described above, the DTM 300 has instrument modules 334 connected to current sensors 326, 328, and insulating puncture connectors 322, 324, and a communication module 336 connected to the instrument module.
Each of the current sensors, instrument modules, and communication modules described above may be the same as those in the embodiments described above for DTM. As best seen in FIG. 29, the openings 312, 314 of the DTM300 are configured to accommodate the conductors 338, 340 of the pole-loaded transformer 342. The DTM300 is secured to the transformer 342 by a band 344 that wraps around each mounted positive member 320.
The DTM of the present invention is particularly useful as a component of an improved system for detecting power theft using the calculation of integrated common mode current (AIPC). Energy calculations as a method of detecting electricity theft are very effective at the level of distribution transformers due to the small number of customers involved. The error due to the loss on the feeder is 0.5% to 3%, and the number of customers is less than 10. In this case, the total amount of energy lost on the feeder is less than the portion of the amount used by one customer, and even smaller than the portion of the amount involved in power theft.
At the feeder level, the situation is different as more customers are involved. At feedline levels, the energy lost at each feeder tends to be many times greater than the amount used by a single customer. For this reason, the detection of power theft is more difficult, and the sensitivity and reliability of the above method largely depends on the accuracy of the energy calculation process.
Improving the accuracy of the energy calculation process is achieved by estimating and compensating for feed line losses, but there are important conceptual issues that limit the benefits of the improvements. The problem is that the feed line loss is proportional to the square of the current level, so we cannot even consider the variable loss due to the feed line resistance, which changes with load and changes with temperature. Therefore, it is very difficult to know what the loss of the feeder line is with sufficient accuracy.
For example, in the case of a feeder that supplies 100 amps to the stable and constant load of each resident customer, the feed line loss can be 1%. However, if the load is changed so that in one measurement period, the load is 200 amperes in half the time and the load is zero in the remaining time, the feed line loss in the above measurement period is doubled. become. Instead of 1%, the feed line loss is 2%. Since such changes occur within the measurement period, it is impossible to detect from the meter data.
For feed lines for 1000 customers, a change in feed line loss from 1% to 2% represents a reduction in the flow of energy to the customers, which is equivalent to 10 times the load on the average customer.
There are many ways to deal with the above changes. One is that the error can be reduced by shortening the measurement period, but the amount of data that must be transmitted and processed increases, and the above problem is not completely solved. The other is an attempt to rely on statistical averages, which takes a lot of time. Therefore, in one of the above, a trade-off remains between sensitivity and prevention of false alarms. If the threshold setting is too low, many false alarms will occur. If the threshold is set too high, no actual power theft will be detected. Between these two levels is a threshold range that causes too many false alarms to detect actual power theft.
For this reason, energy calculations as a method of detecting power theft have a unique source of error that does not depend on the accuracy of the meter used. Even if the feeder meters, distribution transformer meters, and customer meters are completely error-free, the method limits the ability to detect power theft because it has a large source of error that limits sensitivity.
An alternative method that does not have the above error source is to use integrated common mode current (AIPC). AIPC is simply a non-voltage component of energy, removing the voltage period from the equation. Since the feed line loss is characterized by voltage loss rather than current loss, the alternative method is largely immune to feed line loss. This means that overall accuracy is achieved higher and changes to higher sensitivity, and therefore the ability to detect electricity theft, which is primarily limited by meter accuracy, is higher. Therefore, AIPC provides a better method of detecting electricity theft than the use of energy consumption (kWh).
In feed line meters (FM), distribution transformer meters (DTM) and customer meters (CM) systems, AIPC provides the best way to detect power theft regardless of changing feed line losses. .. One difficulty with this concept is that CMs generally do not provide AIPC data and, of course, cannot compare AIPC to kWh. However, when DTM is used, it can be programmed to provide both AIPC and kWh. And kWh can be used to mutually understand between DTM and CM (with a small number of customers involved), while AIPC can be used with FM and DTM (with more customers involved). Used to mutually understand between.
DTM placement may not be desirable in certain measurement situations, such as in rural areas where there is only one customer for the transformer. In such cases, the customer meter may be given the ability to transmit both a read of energy consumption and a read of integrated common mode current. Energy consumption reads are used for billing, while AIPC reads are combined with feed line current meter reads to detect power theft with greater sensitivity and reliability than with energy consumption data. used.
The most accurate approach, and the one that is most sensitive to electricity theft and the least likely to cause false alarms, adds real AIPC capabilities to commercials. The question that accompanies this is what kind of implementation is required by the meter maker to achieve this capability.
However, by using the existing capabilities of the meter, an approximation to the above embodiment can be achieved. The CM may transmit the maximum and minimum voltages in addition to transmitting the integrated kWh per hour. From this data, the maximum possible AIPC and the minimum possible AIPC can be determined as follows. Maximum AIPC = kWh / minimum voltage Minimum AIPC = kWh / maximum voltage In order to compare AIPC at the feed line level with AIPC at the transformer secondary level, it is necessary to calculate the transformer ratio of the transformer, which is the primary voltage divided by the secondary voltage. A simple way to make the above calculation is to convert the AIPC to NAE, or normalized active energy, by multiplying the AIPC by the nominal voltage. This is done as follows. NAE = Normalized active energy = AIPC × Nominal voltage If the NAE of the feeder current meter minus the error margin is greater than the sum of the NAE reads in the CM, the power theft alarm is triggered. In terms of the minimum power theft load required for detection, the sensitivity of this technique can be evaluated hourly as follows. Minimum detectable power theft load = voltage x (maximum AIPC-minimum AIPC) + error margin This technique has the highest sensitivity over a constant voltage period and minimizes false alarms during periods of voltage change.
The target stealing load is a natural base load and should be easily detectable during the sensitive period. Also, the sensitivity of any 1-hour measurement period can be substantially improved by simply dividing the hour into smaller 5-minute measurement intervals. The sensitivity is limited by the amount of voltage change that occurs in 5 minutes. Since the above limitation tends to be small in any normal state, it is possible to maintain high sensitivity at any time in the above technique.
Power theft detection based on RMS current in feeder current meter The sensitivity of any feeder detection system decreases as the number of customers increases, so if you use multiple FCMs for a single feeder, each FCM (feed line current meter) covers a different subset of the feeder's customers. It is advantageous to be able to do it. This configuration works only when the end of the feeder is branched into different sections. In this case, a separate feeder meter can be installed for each branch.
Even if this configuration is possible, there is still a problem, the transmission line from the substation to the first branch (or customer) needs to be protected, and even on this transmission line, the number of customers is increased. It cannot be divided. The above section of the transmission line can be protected by two FCMs (one in the substation, one in front of the first customer) that measure the RMS (root mean squared) current. .. RMS current can be measured more accurately than kWh and even more accurately than AIPC, as there is only one input during the measurement process. Accuracy can be further improved by calibrating two identical FCMs together. Each of the above installations and each calibration can provide the best possible protection against power theft to the above sections of the transmission line.
Feed line current meter with kWh measurement capability Standard feeder current meters do not have connection terminals to which high voltage is applied, but voltage information is needed to calculate kWh. Shielded resistor dividers or potential transformers may be used as standard methods, but both have their own advantages and disadvantages. Although each method can provide excellent accuracy, it is costly and inconvenient if accuracy is required. An alternative method is to measure the voltage on the secondary side of an existing distribution transformer and multiply it by the turns ratio.
The above method can be performed on a device mounted on a distribution transformer near the location of the feeder current meter (FCM). The device measures voltage and current and combines them to generate voltage data for the primary side. The voltage data is continuously transmitted to FCM in real time using short-range radio. FCM provides kWh data using the above voltage data.
There are two main causes of error in the above method. The first is the accuracy of the turns ratio, and the second is the voltage output drop that occurs when the transformer is loaded.
If the transformer complies with the CSA standard, the turn ratio (rated high voltage / rated low voltage on the nameplate) is within ± 0.5%. In addition, the accuracy of the impedance of the transformer described on the name plate (usually within 1% to 3%) is within ± 5%. Therefore, the load current can be measured and this data can be used to compensate for the transformer voltage drop. Assuming a 0.15% instrument error for both voltage and current measurements, for a transformer with 3% impedance, the overall worst case high voltage measurement error is 3% x 5% + 0.15%. + 0.5% + 0.15% 1%.
This level of accuracy is only suitable when the number of targeted customers is small, which is true for any power theft detection system based on kWh. Ironically, this kWh power theft detection system is based on AIPC (Integrated Common Phase Current) due to the extra cost and other disadvantages associated with providing a feeder current meter with kWh measurement capability. It will not be possible to realize a power theft detection system that is more cost effective than the power theft detection system. Using AIPC instead improves the ability to detect electricity theft and reduce false alarms, and the feeder current meter eliminates the need for expensive voltage measuring equipment.
There are other advantages as well. Since it is not necessary for the feeder current meter to measure the voltage, the meter can be significantly reduced in size and weight, and is highly safe. Since the feeder current meter does not need to be connected to which a high voltage is applied, a high voltage fuse is not required, and therefore the size and weight of the feeder current meter can be reduced. Light weight means that it can be attached directly to the feeder line without the use of other weight bearing means. By doing so, the meter can be installed quickly, and the installation location can be flexibly selected.
Finally, the meter is structurally safe. In other words, unlike connected devices where high voltage is applied, this meter completely eliminates the risk of arc discharge around the fuse enclosure inside the device and therefore explodes during installation. The risk of doing so has been removed.
What is AIPC (Integrated Homeomorphism)? AIPC is simply the non-voltage component of energy.
Energy = Pdt = V<sup>*</sup>Idt = voltage x active current (non-reactive) integrated value: AIPC = Idt = Integrated value of inactive current Here, I = active current and energy are measured in kWh (kWh) as a unit, and AIPC is measured in Ah (amp-hour) as a unit.
If you have a 7.2kV feeder (phase-ground) that supplies 100A to a stable, constant load, and the feeder from the substation to the customer has 0.72Ω, the voltage drop that occurs across this feeder. Is 72V. If the voltage at the substation is 7200V, the voltage at the customer is 7200-72 = 7128V. The amount of energy recorded in one hour at the substation is 7.2 x 100 = 720kWh. At load, the measured amount of energy is 7.128 x 100 = 712.8kWh. In this case, ((720-712.8) / 720) x 100% = 1% of energy is lost due to feed line loss.
During the next hour interval, the substation will supply 200A for the first 30 minutes and no current for the rest of the time. 200 x 7.2 x 30/60 = 720kWh is recorded on the substation for the first 30 minutes, so 720kWh is recorded on the substation for the entire hour. However, for loads, the voltage drop is proportional to the current, and the customer voltage is 7200- (200 x 0.72) = 7056V for the first 30 minutes and 7200V for the next 30 minutes, so the voltage drop is doubled. At this time, the amount of energy measured by the customer is 7056 × 200 × 30/60 = 705.6kWh for the first 30 minutes. Therefore, the same applies to the entire hour. In this case, ((720-705.6) / 720) x 100% = 2% of the energy is lost due to the loss of the feeder.
In both cases, the substation records the same amount of energy (720kWh), so this measurement cannot be used to predict the amount of energy lost on the transmission line. It cannot be used for the same reason when bolted by the customer. On the customer side, in both cases, 7128 volts is recorded in the above hour, but in the second case, kWh is 7.2 less. Thus, trying to estimate AIPC by dividing the hourly watt hour by the same hourly bolt hour results in the same numerical error caused by load-induced feed line loss variations. It ends up.
With a true AIPC, 100 Ah is recorded on both the substation and the customer side (unless there is a power theft) in both cases. If AIPC cannot be used, the next best solution is to use the maximum and minimum voltages to calculate the minimum and maximum AIPC values.
The transformer manufactured based on the present invention can be used in an AIPC application system that monitors and calculates electricity consumption as described above. The system of the present invention includes a plurality of each distribution transformer 16 which is schematically shown as a member number 110 in FIG. 13 and is connected to each of the distribution transformer meters 10 manufactured based on the present invention. Each of the distribution transformers 16 is connected to a load 96 (eg, some residential power consumer) and a high voltage feeder 88. The high voltage feeder 88 is then connected to the substation transformer 100. The distribution transformer 90 is also connected to the feeder line 88, and the data collector 92 is then connected to the distribution transformer 90.
Each of the distribution transformer meters 10 records the AIPC used by the corresponding load 96 at a given time and sends this information to the data collector 92. The substation transformer 98 is connected to a feeder current meter 101a, which, like the distribution transformer meter 10, is configured to calculate and record an AIPC at a given time. The feed line current meter 101a is also configured to send AIPC measurements to the data collector 92, preferably via a power line communication signal.
The distribution transformer meter 10 is configured to transmit those AIPC measurements to the data collector 92, preferably via power line communication. The data collector 92 then sends these AIPC measurements to a central computer 112 that can connect to other data collectors that do not need to be near the data collector 92.
Each meter 10 sends a unique identification code along with each AIPC measurement, which allows the central computer 112, which is the server, to compare each AIPC measurement received from each meter 10. They can be compared with the AIPC measurements from the feeder current meter 101a at the same time. This comparison is first made by converting the AIPC value into normalized active energy, or NAE. NAE is simply an AIPC multiplied by a nominal voltage.
For the transformer meter 10, the nominal voltage is typically 240V. For feeder current meters, if the transformer ratio is 30, the nominal voltage can be, for example, 7200V. The total NAE from the meter 10 must be equal to the NAE from the measurement recorded by the feeder current meter 101a at the same time within a reasonable margin in the measurement error. If there is a significant difference in the integrated NAE, it means that there is an unknown load attached to the feeder. A facility operating the central computer 112 as a server may investigate the extra load.
The current calculation system has several advantages. First, a device that measures only the feeder current meter 101a does not require high voltage operation. Therefore, the AIPC measurement of the feeder line 88 is safer and cheaper than the energy measurement. In addition, as shown below, this system, which monitors the network via current calculation, detects direct power theft from the feeder caused by connecting the distribution transformer directly to the high voltage feeder without permission. Can be done.
DTM is configured to detect two different types of electricity theft. The first type is stealing electricity from distribution transformers owned by electric companies. The DTM performs the above detection in conjunction with an electric meter provided on the user's side. The electricity consumption in the transformer must be equal to the total electricity consumption on the part of the user.
To make this comparison, however, the electrical company must know which end user is connected to which distribution transformer. This information is gathered by using mapping. This is related to the generation of 2D images or diagrams (drawn on paper or in electronic form displayed on a computer monitor), the above 2D images or diagrams are in display form and power distribution. Shows transformers, end users, and interconnects between them.
Generating these maps involves a significant amount of work, not only generating them first, but keeping them up to date as changes occur in the power system. Once these maps have been generated and updated, the work required to interpret the maps to generate the formulas used to check for unauthorized use of electricity arises.
Referring to FIG. 13, the DTM (member number 10) made according to the present invention reduces the need to generate these maps. By measuring the signal strength of each AMR signal from the meter 96a at the end user 96 and comparing each AMR signal with the threshold value, the DTM can determine which AMR signal is of the transformer to which the meter 96a is connected. Determine if it comes from a secondary circuit. The information of the above determination is stored in the electronic memory in the DTM and relayed to the data collector 92 as requested. Therefore, the data collector is not provided with only the energy value supplied from the distribution transformer and the energy value consumed by the end user 96, and which end user is connected to which distribution transformer. Information is also provided to indicate whether or not.
Next, referring to FIG. 19, direct power theft from the feeder can be carried out by mounting a distribution transformer that is not from the electric company on the high voltage feeder without permission. Electric companies do not always know the existence of such transformers, and of course, they do not necessarily have one of the DTMs mounted on the transformers.
Therefore, the above types of electricity theft cannot be detected by comparing the energy value supplied by the distribution transformer owned by the electric company with the energy value consumed by the end user. To detect the above types of power theft, the DTM can be used in conjunction with a series of feeder meters (FM1, FM2, FM3, etc.).
According to the situation in the feeder field, the feeder meter measures the energy value supplied by the feeder. This requires multiplying the voltage and current to determine the amount of power and integrating the power for a period of time to determine the energy value. Electricity theft can be detected by comparing the energy value supplied by the feeder with the energy value supplied by the distribution transformer in the feeder.
The main drawback of this approach is that feeder meters need to be designed and built for high voltage operation. High-voltage equipment is expensive and, depending on the design, can be dangerous to install. In addition, due to current flow and line resistance, voltage drops occur for each feeder, and these voltage drops cause measurement errors in comparison. Increased measurement errors mean that more feeder meters are needed for a given number of distribution transformers to allow the distinction between measurement errors and power theft.
An alternative to the feeder meter, the feeder current meter can be used in conjunction with the DTM, which simply measures the in-phase current and integrates the above currents for a period of time (eg 1 hour) to determine the AIPC. .. If both the DTM and the feeder current meter provide AIPC measurements, they are converted to NAE and compared (energy values and AIPC cannot be compared) to detect power theft from the feeder. In order to realize the above-mentioned ability while maintaining the ability to detect power theft from a distribution transformer owned by an electric company, the DTM according to the present invention uses the energy value supplied from the distribution transformer and the above-mentioned transformer. It can be programmed to provide dual measurements with the AIPC values supplied.
FIG. 19 shows a number of each feeder current meter (FM1, FM2 and FM3), distribution transformer (DT), and end user (EU). Just as it is necessary to know which end user is connected to which distribution transformer, it is necessary to understand which distribution transformer is associated with the feeder current meter. Figure 19 shows that the situation is more complicated at the feeder level. The simplest feeder current meter arrangement is for a single feeder current meter to monitor the entire feeder and compare its NAE value to the NAE values for all distribution transformers.
However, due to limited accuracy, the total measurement error can be greater than the amount of undetected power theft. This requires having one or more feeder current meters along the feeder and its branches. At this time, each distribution transformer is not associated with any feeder meter. Instead, each distribution transformer described above is associated with a feeder segment between each of the two feeder meters. The difference in the NAE measurements of each of the two feeder meters is approximately equal to the sum of the NAE measurements of each DTM in all distribution transformers owned by the electrical company in the feeder segment between each of the two feeder meters. Should be.
In order to compare the measured value of the feeder current meter with the measured value of DTM, grasp which of the feeders has the feeder meter and which of the feeders has the connection to the distribution transformer. There is a need. That information is gathered through mapping. This relates to a two-dimensional image, or a diagram showing distribution transformers, feeder meters, and interconnects in display form. As explained earlier, generating each such map involves a considerable amount of work, not only creating each of the above maps first, but also updating each of the above maps as the power system changes. Keep it. Once each of the above maps has been created and updated, the work required to interpret each of these maps will occur in order to generate the equations used to detect the unauthorized use of electricity.
The DTM according to the present invention reduces the need to generate each of the above maps, but the process of acquiring the necessary information differs depending on the position of the feeder meter. The process begins with the data collector sending carrier copy instructions to all feeder meters on the feeder via wire carrier communication. After sending the above instructions, only carriers will be sent for a fixed period of time.
Each feeder meter then uses inductive coupling to the feeder to continuously transmit copy carriers that are substantially identical in frequency and phase. The inductive coupling used by the wire carrier transmitter of the feeder meter results in a 180 degree difference between the phase of the signal traveling in one direction from the feeder meter and the phase of the signal traveling in the other direction. Therefore, each signal in each of the above directions is classified as a plus signal or a minus signal, respectively.
Each DTM in the feeder records, for each of the feeder meters, whether each of the DTMs received a positive signal or a negative signal. The recorded information is relayed to the data collector upon request, so that the data collector is provided with each AIPC measurement (or energy value, or both) from each feeder meter and each DTM. Not only is it provided with all the information needed to make a comparison for theft detection, thus reducing the need for mapping.
Figure 19 shows how it works for power theft detection. Each DTM connected to the feeder segment between the feeder current meter FM2 and the feeder current meter FM3 has a positive signal from the feeder current meter FM2 and a negative signal from the feeder current meter FM3. Receive. All DTMs on the other side of the feeder meter FM3 receive positive signals from both of the above feed line meters, and all DTMs on the other side of the feeder current meter FM2 receive each feed line current. Receive a negative signal from the meter. The sum of the NAE measurements of all the DTMs that received the positive signal from the feeder meter FM2 and the negative signal from the feeder meter FM3 is the NAE measurement value of the feeder meter FM3 from the NAE measurement value of the feeder economy FM2. Should be equal to the value minus.
The distribution transformer meter of the present invention also has some advantages over the prior art. First, because it has a single structure, it is safe and easy to mount. In addition, the improved current sensor is much more accurate than the previous current sensor, allowing accurate measurement of current values and recording of integrated current values.
Although specific embodiments of the present invention have been disclosed, some modifications of the disclosed embodiments may also be within the scope of the present invention. The present invention is not limited to each of the above embodiments, but includes any and all embodiments within the scope of the following claims.
Every citation, both ways
| Document | Relation | Office |
|---|---|---|
| JP10170573A | Cites | Japan |
| US20040257061A1 | Cites | United States of America |
| JP11223643A | Cites | Japan |
| WO2006050321A1 | Cites | World Intellectual Property Organization (WIPO) |
| JP2005071615A | Cites | Japan |
| JP59012359A | Cites | Japan |
| JP2006343157A | Cites | Japan |
| JP2003297639A | Cites | Japan |
| JP2005080320A | Cites | Japan |
| JP2005345267A | Cites | Japan |
| JP2001050991A | Cites | Japan |
| JP2006295692A | Cites | Japan |
| JP2005507223A | Cites | Japan |
| WO2004114543A1 | Cites | World Intellectual Property Organization (WIPO) |
27 members in 7 offices
Priority claims7
| Document | Office | Kind | Date |
|---|---|---|---|
| 60949606 | United States of America | – | |
| 94960607 | United States of America | P | |
| 2008001284 | Canada | W | |
| 2007949606 | – | – | – |
| 2008001284 | – | – | – |
| US20070949606P | – | – | – |
| WO2008CA01284 | – | – | – |
Members27
| Document | Office | Kind | |
|---|---|---|---|
| AU2008278224A1 | Australia | A1 | |
| CA2692864A1 | Canada | A1 | |
| WO2009009878A1 | World Intellectual Property Organization (WIPO) | A1 | |
| US2009066317A1 | United States of America | A1 | |
| US2010007219A1 | United States of America | A1 | |
| US2010007336A1 | United States of America | A1 | |
| KR20100023043A | Republic of Korea | A | |
| CA2689776A1 | Canada | A1 | |
| CA2689777A1 | Canada | A1 | |
| KR20100083098A | Republic of Korea | A | |
| JP2010161923A | Japan | A | |
| AU2010200088A1 | Australia | A1 | |
| JP2010533843A | Japan | A | |
| US7940039B2 | United States of America | B2 | |
| CN102095926A | China | A | |
| CN102105802A | China | A | |
| US8159210B2 | United States of America | B2 | |
| JP5199358B2This record | Japan | B2 | |
| US8461823B2 | United States of America | B2 | |
| CN102105802B | China | B | |
| AU2008278224B2 | Australia | B2 | |
| CA2689777C | Canada | C | |
| JP5568321B2 | Japan | B2 | |
| CN102095926B | China | B | |
| AU2010200088B2 | Australia | B2 | |
| CA2692864C | Canada | C | |
| CA2689776C | Canada | C |
21 legal events, as the office reported them to INPADOC
Over the term
Point at a mark for the eventEvents
| Event | Code | |
|---|---|---|
| Cancellation because of no payment of annual feesLAPS | LAPS | |
| Receipt of annual feesJAPANESE INTERMEDIATE CODE: R250R250 | R250 | |
| Receipt of annual feesJAPANESE INTERMEDIATE CODE: R250R250 | R250 | |
| Receipt of annual feesJAPANESE INTERMEDIATE CODE: R250R250 | R250 | |
| Receipt of annual feesJAPANESE INTERMEDIATE CODE: R250R250 | R250 | |
| Receipt of annual feesJAPANESE INTERMEDIATE CODE: R250R250 | R250 | |
| Receipt of annual feesJAPANESE INTERMEDIATE CODE: R250R250 | R250 | |
| Receipt of annual feesJAPANESE INTERMEDIATE CODE: R250R250 | R250 | |
| Written notification of registration of transferJAPANESE INTERMEDIATE CODE: R350R350 | R350 | |
| Request for change of ownership or part of ownershipJAPANESE INTERMEDIATE CODE: R313113S111 | S111 | |
| Written request for registration of change of nameJAPANESE INTERMEDIATE CODE: R313533S533 | S533 | |
| Renewal fee payment (event date is renewal date of database)FPAY | FPAY | |
| Certificate of patent or registration of utility modelJAPANESE INTERMEDIATE CODE: R150R150 | R150 | |
| Certificate of patent or registration of utility modelJAPANESE INTERMEDIATE CODE: R150R150 | R150 | |
| First payment of annual fees (during grant procedure)JAPANESE INTERMEDIATE CODE: A61A61 | A61 | |
| Written decision to grant a patent or to grant a registration (utility model)JAPANESE INTERMEDIATE CODE: A01A01 | A01 | |
| Decision of grant or rejection writtenTRDD | TRDD | |
| Request for written amendment filedJAPANESE INTERMEDIATE CODE: A523A521 | A521 | |
| Notification of reasons for refusalJAPANESE INTERMEDIATE CODE: A131A131 | A131 | |
| Report on retrievalJAPANESE INTERMEDIATE CODE: A971007A977 | A977 | |
| Written request for application examinationJAPANESE INTERMEDIATE CODE: A621A621 | A621 |
Numbers
- Publication
- 5199358
- Publication, DOCDB
- 5199358
- Publication, EPODOC
- JP5199358B
- Application
- 2010516335
- Application, DOCDB
- 2010516335
- Application, EPODOC
- JP20100516335
Titles2
- Japanese
- 変圧器用メータおよびそれを使用するシステム
- English
- Transformer meters and systems that use them
Classification
- CPC, 6
- H04B3/56
- G01R22/06
- G01R15/18
- H04B3/54
- H04B2203/5433
- G01R15/181
- IPC, 2
- G01R19 00
- G01R15 18