JP4623888B2 - Method and system for predicting the performance of a drilling system for a given formation - Google Patents

Description

注釈¹：それぞれの列に対して示される色は、図４で示されるように、それぞれのシェーディングによって表される。
深さ、ログ・データ、岩質、孔隙率
図４に示されるように、地層２０６の深さは、数値表現の形で表される。ログ・データ２０８は、曲線表示の形で表され、岩質及び孔隙率に反応しやすい任意のログ・スイートを含む。岩質２１０は、所定の地層内の異なるタイプの岩石を識別する際に使用するためのパーセンテージ・グラフの形で表され、そのパーセンテージ・グラフは、岩質に反応しやすい任意のログ・スイートから決定される通りに、所定の深さでの各タイプの岩石のパーセンテージを図示する。１つの実施例では、岩質百分率グラフが色分けされる。孔隙率２１２は、曲線表示の形で表わされ、孔隙率に反応しやすい任意のログ・スイートから決定される。
岩石強度
図４の表示２００上で、岩石強度２１４は、曲線表示２１６、百分率グラフ表示（示されていないが、２１０に似ている）、及びバンド表示２１８から成るグループから選択される少なくとも１つの表示形態で表わされる。岩石強度の曲線表示２１６は、閉じ込め岩石強度２２０及び非閉じ込め岩石強度２２２を含む。閉じ込め岩石強度２２０及び非閉じ込め岩石強度２２２のそれぞれの曲線間のエリア２２４が、グラフで図示されているが、それは、閉じ込め応力の結果としての岩石強度の増加を表わす。岩石強度のバンド表示２１８は、所定の深さでの岩石強度の離散的な範囲（ｄｉｓｃｒｅｔｅ ｒａｎｇｅ）を示すグラフィカルな図解を提供し、より一般的に、所定のドリルホールに沿って岩石強度の様々な個別の範囲を示す。好適な実施例では、岩石強度のバンド表示２１８が色分けされ、軟岩強度範囲を表わす第１の色、硬岩強度範囲を表わす第２の色、及び１つ以上の中性岩強度範囲を表わす追加の色を含む。さらにまた、青色が軟岩強度範囲を示し、赤色が硬岩質強度範囲を示し、そして黄色が中性岩強度範囲を示すように用いられることができる。凡例２２６は、様々な表示された地質的特徴及び予測される穿孔メカニックスの解釈を助けるためにディスプレイ上に提供される。
シェール塑性
図５の表示２００上で、シェール塑性２２８は、曲線表示２３０、百分率グラフ表示（示されていないが、２１０に似ている）、及びバンド表示２３２から成るグループから選択される少なくとも１つの表示形態で表わされる。シェール塑性２２８の曲線表示２３０は、含水率、粘土タイプ、及び粘土容積から成るグループから選択されるシェール塑性パラメータの少なくとも２つの曲線を含み、そこでのシェール塑性は、規定されたシェール塑性モデル１５０（図３）に従って、含水率、粘土タイプ、及び粘土容積から決定される。さらに、シェール塑性の表示は、色分けされることが好適である。シェール塑性２２８のバンド表示２３２は、所定の深さでのシェール塑性の個別の範囲を示すグラフィカルな図解を提供し、より一般的には、所定のドリルホールに沿ってシェール塑性の様々な個別の範囲を示す。好適な実施例では、シェール塑性２２８のバンド表示２３２が色分けされ、低シェール塑性範囲を表わす第１の色、高シェール塑性範囲を表わす第２の色、及び１つ以上の中間シェール塑性範囲を表わす追加の色を含む。さらにまた、青色が低シェール塑性範囲を示し、赤色が高シェール塑性範囲を示し、そして黄色が中間シェール塑性範囲を示すように用いられることができる。上述されたように、表示２００上の凡例２２６は、様々な表示された地質的特徴及び予測される穿孔メカニックスの解釈を助けるために提供される。
ビット作業／摩耗関係
ビット摩耗２３４は、規定されたビット摩耗モデル１５６（図３）に従って、為された累積作業の関数として決定される。図５の表示２００上で、ビット摩耗２３４は、曲線表示２３６及び百分率グラフ表示２３８から成るグループから選択される少なくとも１つの表示形態で表わされる。ビット摩耗の曲線表示２３６は、ビットでの比エネルギー・レベルとして表わされるビット作業、ビットによって為された累積作業、及び研磨による任意の作業損失を含む。百分率グラフ表現に関して、ビット摩耗２３４は、所定の深さでのビット摩耗状態を示すグラフ式に図解される百分率グラフ２３８として表わされることができる。好適な実施例では、ビット摩耗のグラフ式に図解される百分率グラフ２３８が色分けされ、期限切れビット寿命を表わす第１の色２４０、及び残存ビット寿命を表わす第２の色２４２を含む。さらに、第１の色は赤、第２の色は緑が好適である。
メカニカル効率
ビット・メカニカル効率は、規定されたメカニカル効率モデル１５２（図３）に従って、所定のビットに対するトルク／ビット上重量サインの関数として決定される。図５の表示２００上で、ビット・メカニカル効率２４４は、曲線表示２４６及び百分率グラフ表示２４８から成るグループから選択される少なくとも１つの表示形態で表わされる。ビット・メカニカル効率の曲線表示２４６は、ビットでの全トルク（ＴＯＢ（ｆｔ・ｌｂ））及び切削トルク（ＴＯＢ−ＣＵＴ（ｆｔ・ｌｂ））を含む。ビット・メカニカル効率２４４の百分率グラフ表示２４８は、グラフ式で全トルクを図示し、そこでの全トルクは、切削トルク及び摩擦トルク・コンポーネントを含む。好適な実施例では、メカニカル効率のグラフ式に図示された百分率グラフ２４８が色分けされ、切削トルク２５０を図示する第１の色、摩擦の制限されないトルク２５２を図示する第２の色、及び摩擦の制限されたトルク２５４を図示する第３の色を含む。また凡例２２６が、メカニカル効率の様々なトルク・コンポーネントの解釈を助けるために提供される。さらにまた、第１の色は青、第２の色は黄、第３の色は赤が好適である。
【００７２】
曲線表示２４６及び百分率グラフ２４８に加えて、メカニカル効率２４４はさらに、メカニカル効率に悪影響を及ぼす穿孔システム操作上の制約を図示する百分率グラフ２５６の形で表される。穿孔システム操作上の制約は、摩擦の制限されたトルク（例えば百分率グラフ２４８内の参照番号２５４で図示されるような）の発生を引き起こす制約に相当し、その百分率グラフ２５６は、各制約が、所定の深さでのメカニカル効率の摩擦が制限されたトルク・コンポーネント上で及ぼす、対応する衝撃の百分率を示す。穿孔システム操作上の制約は、最大のビット上トルク（ＴＯＢ）、最大のビット上重量（ＷＯＢ）、最小の毎分回転数（ＲＰＭ）、最大の掘穿速度（ＲＯＰ）、それらの任意の組合せ、及び制限されない状態、を含むことができる。好適な実施例では、メカニカル効率に関わる穿孔システム操作上の制約についての百分率グラフ表示２５６が、色分けされ、異なる制約を識別するために異なる色を含む。さらに凡例２２６が、百分率グラフ表示２５６に関して、メカニカル効率についての様々な穿孔システム操作上の制約の解釈を助けるために提供される。
出力
図６の表示２００上で、出力２５８は、曲線表示２６０及び百分率グラフ表示２６２から成るグループから選択される少なくとも１つの表示形態で表わされる。出力２５８に対する曲線表示２６０は、出力制限（ＰＯＢ−ＬＩＭ（ｈｐ））及び操作出力レベル（ＰＯＢ（ｈｐ））を含む。出力制限（ＰＯＢ−ＬＩＭ（ｈｐ））は、ビットに適用されるべき最大出力に相当する。操作出力レベル（ＰＯＢ（ｈｐ））は、制限される操作出力レベル、推奨される操作出力レベル、及び予測される操作出力レベルから成るグループから選択される少なくとも１つを含む。曲線表示２６０に関して、出力制限（ＰＯＢ−ＬＩＭ（ｈｐ））及び操作出力レベル（ＰＯＢ（ｈｐ））の曲線間の差異が、制約を示している。
【００７３】
さらに出力２５８は、出力に悪影響を及ぼす穿孔システム操作上の制約を図示する百分率グラフ表示２６２の形で表される。穿孔システム操作上の制約は、結果として出力損失になる制約に相当する。出力制約百分率グラフ２６２は、各制約が、所定の深さでの出力上に及ぼす、対応する衝撃の百分率を示す。好適な実施例では、出力に関する穿孔システム操作上の制約の百分率グラフ表示２６２は、色分けされ、異なる制約を識別するために異なる色を含む。さらに、赤が最大ＲＯＰを識別するために、青が最大ＲＰＭを識別するために、紺色が制限されない状態を識別するために用いられることが好適である。さらに凡例２２６は、百分率グラフ表示２６２に関して、出力についての様々な穿孔システム操作上の制約の解釈を助けるために提供される。
操作用パラメータ
図６に示されるように、操作用パラメータ２６４は、曲線表示２６６の形で表わされる。上で説明されたように、操作用パラメータは、ビット上重量、ロータリｒｐｍ（毎分回転数）、コスト、掘穿速度、及びトルク、から成るグループから選択される少なくとも１つを含む。さらに掘穿速度は、掘穿瞬間速度（ＲＯＰ）及び掘穿平均速度（ＲＯＰ−ＡＶＧ）を含む。
ビット選択／推奨
さらに表示２００は、提案又は推奨される穿孔設備の詳細についての表示２６８を生成するための手段を提供する。すなわち、提案又は推奨される穿孔設備の詳細は、地質的特徴２０２及び予測される穿孔メカニックス２０４に加えて表示２００上に表示される。提案又は推奨される穿孔設備は、穿孔システムの性能を予測するために用いられる少なくとも１つのビットを含むことが好適である。さらに、それぞれ参照番号２７０及び２７２で示される、第１及び第２のビット選択が、ドリルホールの穿孔について予測される性能で用いられるよう推奨される。第１及び第２のビット選択は、それぞれ第１及び第２の識別子２７６及び２７８で識別される。また第１及び第２の識別子２７６及び２７８は、それぞれ、地質的特徴２０２及び予測される穿孔メカニックス２０４に加えて表示され、そこでの、表示２００上での第１及び第２の識別子の位置決めは、第１及び第２のビット選択がそれぞれ当てはまる、予測される性能の部分に合致するように選択される。さらにまた、その表示は、各推奨されるビット選択、及び対応するビット仕様の説明図を含み得る。
破線
さらに図６を参照すると、表示２００は、ビット選択の変更インディケータ２８０をさらに含む。ビット選択の変化インディケータ２８０は、第１の推奨されたビット選択２７０から第２の推奨されたビット選択２７２へのビット選択の変更が、所定の深さで必要であることを示すために提供される。ビット選択の変更インディケータ２８０は、地質的特徴２０２及び予測される穿孔メカニックス２０４に加えて、表示２００上に表示されることが好適である。
【００７４】
このように本開示の方法及び装置は、有利に、穿孔プログラム内での穿孔システム及びその使用の最適化が、穿孔プログラム内の早期に得られることを可能にする。さらに本方法及び装置は、穿孔プログラム内の早期に、適切な改善を行うよう促進する。穿孔プログラム内で早期に施される改善の結果として生じるいかなる経済的利益も、穿孔プログラム内で穿孔される残りのドリルホールの数だけ掛け合わせられて、利益をもたらす。穿孔プログラムを委任している会社にとって重大で実質的な節約が、有利に達成される。さらに、特定の穿孔システム設備が最適化されて使用されていることを検証するために、本発明の方法と装置により穿孔プログラムの全般に渡って、各ドリルホールの穿孔中に測定がなされる。さらに、穿孔システム設備の性能が、本開示の方法及び装置を用いて、より容易にモニタされることができ、さらに、潜在的な悪条件が実際に起こる前にそれらを識別するためにもモニタされることができる。
【００７５】
さらにまた、本方法及び装置の使用で、有利に、複数の油井のうち所定の油産出ドリルホールがオンラインでもたらされる、成功した穿孔作業を得るまでに要する時間が減少させられる。このように本開示の方法及び装置は、作業効率を高める。さらに、本方法及び装置の使用は、例えば所定の地理的ロケーションで３年間に渡って１００本台の油井を確立するという開発プロジェクトにとっては、特に有利である。本方法及び装置で、例えば以前の方法を使用すれば６０日（あるいはそれ以上）であるのに対して、３０日程度で、所定の油井を完成させ、ラインに載せることができる、つまり市場性のある商品にすることができる。本開示に従って穿孔システムの穿孔性能の効率が高められることで、石油生産に関する時間の利得が可能となり、それはさらに、より早い時期に市場取引が可能となる何百万ドルという石油製品に形を変える。あるいは、本方法及び装置を使用すれば、所定の期間で、同じ期間に以前の方法を用いて完成されるであろう油井の数以上に、１つ以上のさらなる油井が完成されることができる。言いかえれば、より少ない時間で新しい油井を穿孔することが、有利に、より早い時期に市場性のある商品となって換算される。
【００７６】
本実施例は、所定の地層内にドリルホールを実際に穿孔する前、及び穿孔中に、提案される様々な穿孔設備の評価、さらに穿孔プログラムに関する使用法、を提供する。穿孔設備の選択及び使用法が、所定の地層内でのドリルホール（あるいは区間）の特定の区間あるいは区間（複数）に対して最適化されることができる。穿孔メカニックス・モデルは、岩質の変化によって、進行するビット摩耗の影響を考慮に入れることで、利益をもたらす。推奨される操作用パラメータは、特定の岩質でのビットの摩耗状態を反映し、使用される特定の穿孔装置の操作上の制約もまた考慮に入れる。所定の地層に対して単位深さ当たりの地質的特徴及び予測される穿孔メカニックスのプリントアウトあるいは表示は、穿孔操作員にとって非常に役立ち、特に、穿孔プログラムの穿孔工程の最適化のために使用される、重要な情報を提供する。プリントアウトあるいは表示はさらに、有利に、予期される穿孔条件及び推奨される操作用パラメータについてのヘッド・アップ・ビューを提供する。
【００７７】
本実施例は、明確な形で、例えば図４を参照しながら本文で図解し説明したようなグラフの形式で、コミュニケートされる多くの複合した重大な情報を提供する。さらに、グラフの形式内に色を使用することで、重要な情報を強調する。さらにまた、表示２００は、有利に、穿孔者のロードマップを提供する。例えば、ガイドとしてその表示を持つことで、穿孔者は、所定のビットをいつ引くべきかの決定を支援される。その表示はさらに、性能及び穿孔メカニックスに対する操作上の制約の影響に関する情報を提供する。さらにまた、その表示は、推奨される操作用パラメータを選択する際の手助けとなる。表示を使用することで、より効率的で安全な穿孔が得られる。最も有益なことは、重要な情報が明確に伝達されることである。
リアルタイムな側面
本開示の別の実施例によれば、装置５０（図１）は、本文の上記で説明された通りで、さらに下で説明されるようなリアルタイムな側面を含む。特に、コンピュータ・コントローラ５２は、穿孔システムでドリルホールを穿孔する際の制御パラメータを制御するための予測される穿孔メカニックス出力信号に反応する。制御パラメータは、ビット上重量、ｒｐｍ、ポンプ流量、及び水圧、から成るパラメータのうちの少なくとも１つを含む。さらに、本文で説明されるように、コントローラ５２、検層計測器１６、測定デバイス・プロセッサ４４、及び他の適切なデバイスが、ドリルホールの穿孔中にリアルタイムで少なくとも１つの測定パラメータを得るために使用される。
【００７８】
コンピュータ・コントローラ５２は、さらに測定パラメータの逆算値と測定パラメータとを履歴照合させるための手段を含む。特に、測定パラメータの逆算値は、穿孔メカニックス・モデル及び少なくとも１つの制御パラメータ、の関数である。測定パラメータと測定パラメータの逆算値との間の規定された偏差に応じて、コントローラ５２は、次の、ａ）穿孔メカニックス・モデルを調整するステップ、ｂ）制御パラメータの制御を修正するステップ、あるいは、ｃ）警告操作を実行するステップ、のうちの少なくとも１つを実行する。
【００７９】
本開示の別の実施例によれば、穿孔システムの性能を予測するための方法及び装置は、所定の地層内でのドリルホールの穿孔中に、規定されたリアルタイム穿孔パラメータを測定するための手段を含む。穿孔パラメータは、所定のリアルタイム・パラメータを得るのに適した市販の（ＭＷＤデバイスのような）測定装置を用いて、ドリルホールの穿孔中に得られることができる。さらに穿孔システム装置は、所定のリアルタイム穿孔パラメータと、対応する予測されたパラメータとを比較するための、規定されたリアルタイム・モードで作用する。従って、本実施例は、一度だけか、繰り返しか、又は周期的なやり方で、１つ以上の操作モードを、単独か、又は組合せのいずれかで促進する。操作モードは、例えば、予測モード、較正モード、最適化モード、及びリアルタイム制御モードを含む。
【００８０】
本開示のさらに別の実施例では、コンピュータ・コントローラ５２は、この分野ではよく知られたプログラミング技法を用いて、本文で記述されるようなリアルタイム機能を実行するようプログラムされる。コンピュータ・ディスク又はコンピュータ読取り可能コードを伝達するための他の媒体（世界的なコンピュータ・ネットワーク、衛星通信など）といったような、コンピュータ読取り可能な媒体が含まれ、そのコンピュータ読取り可能な媒体は、その上に格納されたコンピュータ・プログラムを持つ。コンピュータ・コントローラ５２による実行用のコンピュータ・プログラムは、初期に開示されたものに似ていて、追加のリアルタイム能力の機能を持つ。
【００８１】
リアルタイム能力に関して、そのコンピュータ・プログラムは、予測される穿孔メカニックス出力信号に応じて、穿孔システムでドリルホールを穿孔する際の制御パラメータを制御するための命令を含み、そしてその制御パラメータは、ビット上重量、ｒｐｍ、ポンプ流量、及び水圧、からなるグループから選択される少なくとも１つを含む。またそのコンピュータ・プログラムは、ドリルホールの穿孔中にリアルタイムで測定パラメータを得るための命令を含む。最後に、そのコンピュータ・プログラムは、測定パラメータと測定パラメータの逆算値との履歴照合を行うための命令を含み、そこでの測定パラメータの逆算値とは、穿孔メカニックス・モデルと、少なくとも１つの制御パラメータとから成るグループから選択される少なくとも１つの関数である。さらに制御パラメータを制御するための命令は、測定パラメータと測定パラメータの逆算値との間の規定された偏差に応じて、ａ）穿孔メカニックス・モデルを調整するステップ、ｂ）制御パラメータの制御を修正するステップ、あるいはｃ）警告操作を実行するステップ、のうちの少なくとも１つを実行するための命令を含む。
【００８２】
穿孔予測解析システムの１つの実施例では、そのシステムが、ドリルホールの穿孔中に蓄積された実際のデータで見ること、及び、対応する計画段階で作られた予測と実際のデータとを比較することによって、履歴照合を実行する。履歴照合の結果に応じて、穿孔メカニックス予測モデルのいくつかの因数（例えば基礎的な仮定）が、予測された性能と実際の性能とがより良く照合するように調整される必要がある。これらの調整は、特定の地理的な地域に特有の地層環境に関係する様々な因数、及びその環境が特定のビット設計とどのようにインターフェースするかということ、に起因していると言える。
【００８３】
言及されたように、本実施例のリアルタイムの側面は、ドリルホールが穿孔されている間に、予測された性能と実際のパラメータとの比較を実行することを含む。リアルタイムの側面を持つことで、本実施例は、エンドオブジョブ分析の１つの欠点、すなわち、エンドオブジョブ分析と共に、「学習されたレッスン」がそれに続くドリルホールに単に適用されることができるだけであるという欠点を克服する。それとは対照的に、本実施例のリアルタイムの側面を持つことで、（穿孔されているドリルホールに適用可能な）穿孔メカニックス予測モデルに要求される任意の調整を行なうことができるし、特定のドリルホールに対する穿孔工程をより良く最適化するのに適した他の調整も行なうことができる。さらにリアルタイムの側面は、所定の現場でのドリルホール（複数可）に関する習熟曲線、及び各々のドリルホールに対応する最適化工程を、加速する。さらに本文の後段で説明されるように、これらの利点のすべてが、測定ツールとしてビットを用いることに依存しない。
リアルタイム最適化
ここで図７を参照して、本開示の実施例に従う、所定の地層用の穿孔システムの予測性能についてのディスプレイ３００が、前に本文で記述された図１の穿孔予測解析及び制御システム５０と関連させて示される。ディスプレイ３００は、深さに対するデータのプロットを含み、そのデータは、深さ３０２、ログ・データ３０４、岩質３０６、孔隙率３０８、岩石強度３１０、ビット摩耗３１２、及び操作用パラメータ３１４を含む。各それぞれのプロット用に表示されるデータは、図１〜６に関して本文の前段で説明されるように、そして後段で説明されるようにして得られる。
【００８４】
ディスプレイ３００の第１の領域３１６は、ＭＷＤセンサの深さ位置より上のそれぞれの深さに関係する情報及びデータによって特徴づけられる。第１の領域３１６のそのような情報は、本質的に、あたかも作業が完了した後にデータが収集され解析されたかのように、正確であると考えられる。従って、第１の領域３１６のデータは、たいていエンドオブジョブの場合の「較正モード」のように見える。操作用パラメータの列３１４内の実線３１８は、実際のＲＯＰを示し、そして破線３２０は、予測モデルが、実際の穿孔パラメータ（例えばＷＯＢ３２２及びＲＰＭ３２４）を用いてログ計算された岩石強度３１０から、ＲＯＰに対して予測していたものを表す。
【００８５】
「エンドオブジョブ」モードにおいて、穿孔予測解析及び制御システムは、所定のドリルホールに対する予測モデルの精度を評価するために、及び、特定の現場あるいは地域におけるそれに続くドリルホールに対する調整を必要に応じて行うために、予測されたＲＯＰと実際のＲＯＰとを比較する。リアルタイム（ＲＴ）ジョブであるため、接近した履歴照合が、達成され、予測モデルが所定の環境内でうまく作動していることを示すようになるまで、穿孔予測解析及び制御システム５０（図ｌ）が、所定のドリルホール内で作動しているビットに対して初期の穿孔段階で調整を行う。従って、穿孔予測解析及び制御システムは、よいオフセット情報があると仮定して、今後のＲＯＰをうまく予測すべき立場にある。より良く予測された今後のＲＯＰは、穿孔予測解析及び制御システムが、特定の現場のそれに続くドリルホール内で、いつビットの切れ味が悪くなり、引き抜かれるべきであるかを判断するのを支援することができる。
測定ツールとしてのビット
次の例は、岩石強度の逆算を取り扱うが、本文で開示されるような異なるパラメータに関して逆算を行うことが可能である。図７を再び参照して、第２の領域３２６は、ビットとＭＷＤセンサ間の区域におけるそれぞれの深さに対応する情報及びデータによって特徴づけられる。穿孔パラメータ・データ（例えばＷＯＢ、ＲＰＭ、及びＲＯＰ）は、ほとんど瞬時測定されることができるので、ビットの深さでのそれらのデータが知られる。穿孔予測解析及び制御システム５０（図１）は、ＭＷＤセンサの上の領域３１６では、よいＲＯＰ履歴照合を得る。従って、穿孔予測解析及び制御システム５０は、所定の深さ（複数可）での実際の穿孔パラメータ及び結果としてのＲＯＰから、何等かの「示唆される」測定パラメータを逆算することができる。
【００８６】
「示唆される」パラメータとは、ビットに対応する深さとＭＷＤセンサに対応する深さの間の区間である領域３２６内で生じるパラメータ（複数可）のことであり、したがって、測定デバイスが所与の時間内にその区間をまだ横断していないので、「示唆される」パラメータは、測定されたデータから計算されることはできない。関連するＭＷＤセンサ・データが利用可能になった後、穿孔予測解析及び制御システム５０は、そこから岩質及び岩石強度パラメータを決定することができる。そうして、例えば穿孔予測解析及び制御システム５０は、ログで計算された岩石強度と「示唆される」岩石強度とを比較することができる。図７では、ログで計算された岩石強度が、実線３２８として図示される。また、「示唆される」岩石強度は点線３３０として図示される。
【００８７】
以下の説明は、穿孔予測解析及び制御システム５０が、「示唆される」パラメータを決定するための、上記で説明された技術を利用する方法を説明する。「ビットでの」測定が、「検証」測定から外れ始めた場合、穿孔予測解析及び制御システムは、ダウンホールで何かが間違って進行したことを示唆する。ビットが破損されたか又はボールアップされた、坑洗浄効率に問題がある、穿孔効率が変化した、などである。例えば、領域３１６において利用可能であるように、対応する実際に測定されたパラメータ値が、ログ・データから引き出されることができるまでは、穿孔予測解析及び制御システム５０は、他の何等かの計算に対して、示唆されるパラメータ値を用いることになる。
【００８８】
良いオフセットデータが利用可能な場合、穿孔予測解析及び制御システム５０は、穿孔されているドリルホールの最適化を促進するために、それに依存することができる。しかしながら、全くオフセット情報の無い調査井を穿孔する場合、穿孔予測解析及び制御システムは、そのドリルホールを最適化するために穿孔ドリルホールからの「示唆される」データを用いる。
【００８９】
言いかえれば、逆算された測定パラメータの値は、測定パラメータの値と履歴照合されるか、あるいは比較される。第１の例では、逆算された測定パラメータは、ＭＷＤセンサのレベルより上のドリルホールの第１の区間（図７の領域３１６のような）の値に対応する。この第１の区間で逆算された値に関して、穿孔予測解析及び制御システムは履歴照合を実行する。この第１の区間で履歴照合を行う１つの理由は、穿孔予測解析及び制御システムが、穿孔メカニックス・モデル（複数可）が適切に動作しているかどうかを判定するためである。
【００９０】
第１の区間で、履歴照合比較での規定された量より大きな任意の偏差に関しては、穿孔解析及び制御システムは、予測穿孔メカニックスの生成用の穿孔メカニックス・モデルに対して適切な調整を行う。特に、偏差の許容レベルが達成されるまでは（つまり測定パラメータと測定パラメータの逆算値との間の履歴照合偏差が、偏差の許容レベル内になるまで）、穿孔予測解析及び制御システムは、それぞれのモデルの基礎を成す仮定を調整する。
【００９１】
さらに第１の区間に関連して、１つ以上のそれぞれの穿孔メカニックス・モデルに適切な調整を行うことで、穿孔解析及び制御システムは、ドリルホールをさらに穿孔するための、穿孔メカニックスについての対応する予測を向上させる。言いかえれば、穿孔解析及び制御システムは、穿孔工程中に穿孔メカニックス・モデルを微調整する。それに応じて、穿孔システムは、微調整された穿孔メカニックス・モデルに基づいて、１つ以上の制御パラメータの制御を修正する。微調整は、ドリルホールの穿孔が前進するにつれて、穿孔パラメータの最適化に役立つ。
【００９２】
第２の例では、（図７の領域３２６のような）ＭＷＤ測定デバイスとドリルビットとの間のドリルホールの第２の区間内で、穿孔予測解析及び制御システムが、第１の区間とはわずかに異なるやり方で、測定パラメータと測定パラメータの逆算値との履歴照合を利用する。この第２の区間で履歴照合を行う１つの理由は、穿孔予測解析及び制御システムが、ビットの状態、及びビットが地層とどのように相互作用しているかということを見抜くことができるようにするためである。
【００９３】
第２の区間内で、規定された制限より大きな偏差があることが履歴照合によって明らかになる場合、履歴照合の偏差は、穿孔システムによるドリルホールの穿孔に潜在的な問題があること（例えばビットに）を示す。そうではなくて、許容範囲内の履歴照合内の偏差は、予測された通りに穿孔システムによるドリルホールの穿孔がなされたことを示す。第２の区間内での測定パラメータの逆算値に関して、逆算値は、それぞれの区間に対してドリルホールを穿孔する際の実際のパラメータ（地質的な値は欠如している）によって示唆される。
【００９４】
ここで説明されたようなリアルタイムの機能は、穿孔予測解析及び制御システムの能力に強力な追加能力を提供する。
従って、本開示の穿孔システム方法及び装置は、穿孔モードが後に続く予測モードを実現するための、規定されたやり方で動作する。予測モードで得られるパラメータと、穿孔モードで得られたパラメータとの比較は、所定のドリルホール又はそれに続くドリルホールの予測モデル及び穿孔に関して修正し（又は）調整を行うことに関する有益な洞察力を提供する。また穿孔システムの方法及び装置は、単位深さ当たりの予測パラメータ（例えば予測岩石強度）に照らしてリアルタイム・パラメータを調べること、及び（例えば穿孔メカニックス・モデル内で用いられる基礎的な仮定に対して）適切な調整を行うこと、によって穿孔の最適化を実施する。
【００９５】
穿孔予測装置は、実際の穿孔サイトとは異なるロケーションに配置されることができる。すなわち、予測装置は、リモート・ロケーションにあって、インターネット又はそれと同種のものといったような世界的な通信網を介して実際の穿孔サイトとインタフェースすることができる。また予測装置は、リアルタイム・オペレーション・センタ（ＲＯＣ）にあってもよく、その場合のＲＯＣは、穿孔サイト及び穿孔装置とつながる衛星リンク又は他の適切な通信リンクを持つ。
【００９６】
また本実施例は、ドリルホールを穿孔している間の測定デバイスとして、規定のビットの使用を促進する。岩石の圧縮強度の変化の発生といったような、ドリルホール穿孔中の地層変化と共に、それに対応する変化が、ドリルホール穿孔中のビットの反応に生じる。例えば、地層の変化で、ビットは不平衡になるか、振動するか、あるいは他の同じような変化を受けることがある。穿孔システム装置は、適切な測定デバイスを用いて、ビット性能におけるそのような変化をモニタする。例えば、ビット性能をモニタするための１つの方法は、ビットの適切なセンサを介するものである。
【００９７】
ビットのセンサはまた、ボアホールの所定のパラメータをマッピングするための手段を提供することができる。例えば、ドリルホールの穿孔中に、穿孔システム装置は、測定パラメータの関数としてビットで測定された（あるいは実際の）岩質と、予測された岩質とを比較することができる。ビット内、あるいはドリルストリングに沿ったビットに最も近いところに配置される適切なセンサが使用され得る。
【００９８】
また穿孔システム装置は、穿孔センサがビットの後ろのドリルストリング上に配置される、典型的な穿孔間測定（ＭＷＤ）センサを含む。例えば、ＭＷＤセンサは、ほぼ５０〜１００フィート程度、ビットから離れたところにある。その結果、ＭＷＤセンサによって為される測定は、ドリルホールの穿孔中にリアルタイムで、ビットの後を遅れて進む。ビット摩耗のパラメータに関して、本実施例の方法は、ドリルホールを穿孔するステップと、穿孔しながら、予測されたビット摩耗パラメータ及び逆算されたビット摩耗パラメータ（ＭＷＤ測定値から決定されるような）を比較するステップとを含む。さらにその方法は、測定されるビット摩耗が、予測された摩耗に関連して周期的に更新され、全体的に最良の穿孔性能を達成するための適切な調整が推奨され（又は）為されるといった、ビット摩耗状態の強化を含む。言いかえれば、予測された摩耗性能は、測定されるビット摩耗性能を表わすリアルタイムで測定さえるパラメータと比較されることができる。
【００９９】
本実施例はさらに、１週間程度かそれ以上事後の最適化及び較正と比較されながら、事実上同日の「リアルタイム」での最適化及び較正を促進する。リアルタイムでの最適化及び較正は、有利に、ドリルホール穿孔中のビットの穿孔性能にプラスの効果を提供する。従って、本実施例の穿孔システム及び方法は、予測された穿孔パラメータ及び性能に対する実際のそれとの比較結果（あるいは履歴照合）に基づいて、現実世界のシナリオにより良く適合するように、適切なパラメータ調整を促進する。
【０１００】
実際のパラメータと予測されたパラメータとの相違がカバーされなくなる（つまり規定の最大量を越える）場合、本実施例の穿孔システム方法及び装置は、規定された反応に従って、それに応じて動作する。例えば、履歴照合に所定の制限を越える任意の偏差があると査定されることに反応して、穿孔システム及び方法は、予測された穿孔性能と実際のそれとの比較の結果の関数として様々なパラメータを調整する。予測された穿孔パラメータと実際のそれとの比較によって、不利な又は望ましくないビット摩耗であるという指摘がなされることもある。さらなる査定によって、その偏差が、ビット摩耗又は他のいくつかの悪条件によるものであるかどうかの指摘がなされることも可能である。
【０１０１】
典型的なシナリオでは、穿孔システムは、自動的な穿孔制御モードと手動の制御モードとの間で作動する。規定された制限を越える履歴照合の相違に応じて、本開示の実施例は警告操作を実行することができる。警告操作は、何かが間違っていて、注意が必要であるという指示を提供するステップを含む。またシステム及び方法は、自動の穿孔制御モードをやめて、対応する相違が解消されるまでは、自らを手動の制御モードに置く。
【０１０２】
また穿孔システム装置及び方法は、色分けされたインディケータ、あるいは所定の表示及び／又はフィールド・アプリケーションに適する他の適切なインディケータといったような適切な警報インディケータを含む警告操作を実行することができる。所定の警告操作において、ディスプレイに保持される規定の情報は、対応する情報に注意を引き付けるやり方で、強調表示されたり、動かされたりしてもよい。
【０１０３】
赤いインディケータは、例えば初期のビット故障の可能性があることを表わすために、提供されされてもよい。そのような初期のビット故障は、予測されたパラメータと実際のパラメータとの相違が、規定された最大限の相違より大きくなる場合に、引き起こされることがある。黄色のインディケータは、警告の状態を示してもよく、そこでは、予測されたパラメータと実際のパラメータとの相違が、規定された最小限の相違より大きいが、最大限の相違より小さい。最後に、緑のインディケータは、全体的に受入可能な状態を示してもよく、そこでは、予測されたパラメータと実際のパラメータとの相違が、規定された最小の相違より小さい。後の例においては、予測と実際との相違は予定通りで、穿孔は比較的乱されずに進み得る。
【０１０４】
本実施例は、適宜に、警報あるいは初期警告の形態を提供する。そうして、調整するか、あるいは調整しないかのリアルタイムの決定が、以前に可能であったよりも、より多くの情報に基づくやり方で為されることができる。さらに本実施例は、例えばディスプレイを利用して、ドリルホールの穿孔についてのリアルタイムでの観察を提供する。
【０１０５】
ドリルホールを穿孔しているドリルビットの実性能と予測性能との差に関してさらに説明すると、ビットが、検層ツールに先んじて、最初にボアホール内にあることが注目される。ビットでのリアルタイム・パラメータは、所定の量だけ、検層ツールより先んじている。ビットでのリアルタイム・パラメータが先行するのは、時間及び距離の見地においてであり、そのような時間及び距離は、検層ツールがドリルストリングに沿ってビットから離れて配置されているその対応する距離を、検層ツールが通過するのに要する時間に相当する。適切な穿孔メカニックス・モデルに関連して、ビットによって穿孔されている岩石の圧縮強度といったような特定の測定値が、これらのリアルタイム・パラメータでもって示唆されることができる。ビットでの他の典型的なリアルタイム・パラメータは、ＷＯＢ、ＲＰＭ及びトルクを含む。
【０１０６】
リアルタイム・パラメータ及び測定情報と共に、穿孔システム装置は、ビットが示唆したもの、つまり、示唆されたものが実際にそこにあったのか否かを検証するために、（ＭＷＤ設備のような）穿孔しながら検層する計測器を使用する。ＭＷＤ検層ツールは、予測されたパラメータ及び実際の性能によって与えられるような、ビットが示唆したものを連続的に検証するために使用されることができる。例えば、検層ツールが岩石強度に比例するパラメータを感知している場合、そのパラメータ情報は、処理のために穿孔システム予測兼解析装置に送られる。予測兼解析装置は、穿孔されている岩石の本当の状態についての指摘を作成することにより、その圧力情報を処理する。岩石の本当の状態が予測通りである場合、穿孔工程は先に進むことが許される。もし予測通りでない場合、穿孔工程は適切になるよう変更されるか、又は修正される。従って、穿孔予測及び解析システムは、規定されたやり方で、ドリルホールの穿孔を制御することができる。１つの規定されたやり方は、自動の穿孔制御モードと手動の穿孔制御モードとの間の交替を含む。
【０１０７】
別の典型的なＭＷＤツールは、ビット振動測定ツールを含む。振動データに基づいて、穿孔予測及び解析システムは、所定のビットがダウンホールでビット損傷を受けたかどうかの判定をする。振動測定ツール出力データ内に生じる反曲点は、振動レベルの較正あるいは更新が必要であることを示す。振動データに基づくビット・パラメータの最適化を用いて、穿孔予測及び解析システムは、所定のビットが、重大な又は破局的な損傷を発生すること無く、どれだけの力に耐えることができるかを判定する。そのような解析は、先のビット振動／性能の検討から引き出される性能データの使用を含み得る。ここで説明されるように、穿孔予測及び解析システムは、ここで説明されるような機能を実行するための適切なプログラム・コードを持つ少なくとも１つのコンピュータ読取り可能な媒体を含む。
【０１０８】
また本発明は、ボアホールの安定性関係の診断に関連する。適切な描写を用いて、ボアホール・マッピングが、所定の地層内の任意のひび割れを解析するために、実施されることができる。地層内のひび割れの配置が、穿孔の可能性に影響を及ぼすことがある。断裂又はひび割れのマッピングは、岩石が破損される範囲について、いくつかの指示を提供する。断裂は岩石強度の急速な低下の存在を示すものである。
【０１０９】
また、誤差が最小限になるよう留意することが重要である。多くの未知のものがある。あるダイレクトな量子化が存在しないならば、ある原因へ誤差を配分することは正しくない。これは推定と測定との差に関係する。穿孔しながら測定する適切な装置を用いるので、様々なログ・データを地表へ送ることができる。しかし、ダウンホールには多くの測定値がありながら、選択されたものしか地表へ送ることができない。そのような制限は、現在の技術では、可能な測定値のすべてを直ちに地表へ伝送することができないことが、主たる原因である。
【０１１０】
本実施例の穿孔システム装置及び方法はまた、測定ツールとしてビットを利用する。例えば、ビットの震動の高調波は、測定ツールとしてビットを使用することを可能にする。震動データは、較正の目的に役立つことが分かる。ドリルホールを穿孔するある例では、特定の岩質に関する、並びにＷＯＢ、トルク及びＲＯＰの様々なパラメータを指定するための、利用可能なデータを考慮に入れるために、ビットが指定されることができる。その方法は、ドリルホールを穿孔しＲＯＰをモニタするステップと、岩質を観察するステップと、プロセスの一環としてＷＯＢを決定するステップとを含む。この例において、ビットは、何が穿孔されつつあるかの予測を開始するための最初の測定デバイスであり、そして様々な検層ツールがビット測定値を検証する。
【０１１１】
本方法及びシステム装置はさらに、パラメータの逆算を含み、そうして、予測されたパラメータに逆算されたパラメータを重ね、何が実際に起こっているかを評価する。その後、その方法とシステムの装置は、そのビットに何が実際に起こっているかを決定することに応じて、微調整、及び／又は適切な調整を行う。従って、測定ツールとしてビットを用いれば、ダウンホールでビットに何が起こっているのかを分析検査するための５０〜１００フィート程度早い（段階での）事前通知が、可能となる。
【０１１２】
さらに、測定ツールとしてビットを用いると、ビットがまだ活動状態にある（つまり、穿孔を継続することができる）かどうか、あるいは他のしかるべき評価を分析検査することができる。例えば、ビット測定は、ビットが予期しない何かが行ったことを指摘することができる。ドリルストリング上のＭＷＤセンサは、ビット測定が指摘したものを検証することができる。ＭＷＤセンサは、予期されたより早かったのか、遅かったのか。講ずるべき適切な処置は何であるか。障害があるか。センサとしてビットを用いることによって、予測及び解析システムは、ビットが予測されたように機能しているかどうかを示すための振動を観察し（又は）測定することができる。従って、予測及び解析システムは、測定ツールとしてビットを用いて観察されるものに基づいて、推奨される穿孔パラメータを更新することができる。予測及び解析の装置は、測定ツールとしてビットを用いると共に、（例えばビットの１フィート先を見る）ルックアヘッド・アプリケーションに対して、穿孔装置があると予想される場所にパラメータを調整することができる。
【０１１３】
測定ツールとしてビットを用いることで、予測及び解析システムは、岩石の異方性、方向特性、圧縮強度、及び／又は孔隙率を分析検査することができる。水平のドリルホールについては、ドリルが垂直面から９０度の角度で進む必要がある。相対的な傾斜角度が変化しても、孔隙率は同じである。
【０１１４】
履歴照合モード又は最適化モードにおいて、ＭＷＤセンサは、ビットより５０〜１００フィート後ろにあるか、ビットのところにあるか、あるいは、ビットの前方を測定しているか、である。１つの操作モードでは、システムが提案を生成し、ドリルホールの穿孔中にその提案を利用する。例えば、その提案は、単位深さ当たりの岩質及び予測される岩石強度を含み得る。穿孔中に、システムは、所定の深さの岩石強度を逆算し、次に、その岩石強度の逆算された測度を、測定ツールが対応する境界線を横断する（つまり、地層を通過する）ことによって利用可能となる情報と、比較する。その後、システムは、予測された岩石強度及び実際の岩石強度との履歴照合を実行する。履歴照合の後に続いて、システムは適切なパラメータ調節（複数可）を行う。
【０１１５】
システムは、穿孔システムが、ビットで反応すると予測されたように反応していることを検証するか又は判定するために、履歴照合を実行する。システムはさらに、表示メカニックス及び有効な岩石強度の逆算値（予測された）、を利用するリアルタイム・モードで、動作する。センサが所定の深さ付近を通過する時、システムは圧縮の岩石強度（又は孔隙率）パラメータを計算する。泥水自動記録器が、測定された岩石強度と予測された岩石強度較正との対比と共に、用いられるが、そこでの泥水自動記録器は使用に先立って、適切に較正される。
【０１１６】
ここで説明されるように、穿孔予測解析及び制御システムは、ビットに近いところのデータを利用する。従って、そのシステム及び方法は、以前のいかなる不確定要素をも、はるかに小さくする。ドリルホールの穿孔に関して、このことは進歩である。経験に基づいて言えば、予期しない地質学的なシナリオがオフセット井で生じるのが、一般的である。
【０１１７】
本実施例によれば、リアルタイムは、データがダウンホールで取得される時刻と、そのデータが所定の瞬間に穿孔操作員に利用可能となる時刻との間の時間の消失によって特徴づけられることができる。すなわち、穿孔操作員がデータを得るまでに、どれくらいの時間がかかるかということである（２週間と１日との対比）。穿孔予測解析及び制御システムのリアルタイムの側面によって、システムは、短時間内にビットが何を行っているかを判定し、何が調整される必要があるかを判定することが出来、修正されたＷＯＢ、ＲＰＭ、又は他の適切な操作用パラメータをリアルタイムで出力する。
【０１１８】
ビット摩耗に関して、穿孔解析及び制御システムは、ビット摩耗インディケータを含む。ビット摩耗インディケータは、ビットが摩耗すると、ビット摩耗の異なった状態に対して異なるサイン又は音響信号が生成されるということを特徴とする。またシステムは、適切な測定デバイスを介して、ビットの摩耗状態の測定を決定するためのサインあるいは音響信号を測定する能力を含む。
【０１１９】
ここで説明されたように、操作用パラメータは、少なくとも１つの予測されたＲＰＭ、ＷＯＢ、コスト、ＲＯＰ及びＲＯＰ−ＡＶＧを含む。これらの予測された操作用パラメータは、図１の穿孔予測解析及び制御システム５０のディスプレイ出力に表示される。測定パラメータは、リアルタイムで測定されるか又は（例えば適切な計算によって）得られるドリルホールの穿孔に関連する任意のパラメータを含むことができる。測定パラメータは、１つ以上の操作用パラメータを含むことができる。制御パラメータは、ドリルホールの穿孔に影響を及ぼすか又は変更するために、手動で又は自動制御を介してのいずれかで、修正されるか又は制御されることを前提とする任意のパラメータを含むことができる。例えば、制御パラメータは、直接（あるいは間接の）制御を受ける１つ以上の操作用パラメータを含む。
【０１２０】
本発明のほんの少しの典型的な実施例が、上記で詳細に記述されたが、この分野の技術を持つ人々であれば、典型的な実施例において本発明の斬新な教え及び長所から大きく外れること無く、多くの修正が可能であることが容易に理解されるだろう。従って、そのような修正はすべて、次の特許請求の範囲に定義されるような本発明の範囲内で含まれるように意図される。特許請求の範囲では、手段及び機能の条項が、列挙された機能を実行するものとしてここに記述された構造、及び構造的な同等物だけでなく、等価な構造をもカバーするように意図される。
【図面の簡単な説明】
【図１】図１は、所定の地層における規定された穿孔プログラムに従って、ドリルホール（複数可）を穿孔するための穿孔システムの性能を予測するための装置を含む穿孔システムを図示する。
【図２】図２は、所定の地層における規定された穿孔プログラムに従って、ドリルホール（複数可）を穿孔するための穿孔システム及びその使用法を最適化するための方法であって、さらに穿孔システムの性能の予測も含む、方法を図示する。
【図３】図３は、本開示の穿孔性能を予測する方法及び装置の実施例に使用するための地質モデル及び穿孔メカニックス・モデルを示す。
【図４】図４は、本開示の方法及び装置に従って、所定の地層用の穿孔システムについて予測された性能を表示する１つの実施例を図示する。
【図５】図５は、本開示の方法及び装置に従って、所定の地層用の穿孔システムについて予測された性能を表示する１つの実施例を図示する。
【図６】図６は、本開示の方法及び装置に従って、所定の地層用の穿孔システムについて予測された性能を表示する１つの実施例を図示する。
【図７】図７は、本開示の穿孔予測解析及び制御システムのパラメータ及びリアルタイムな側面についての典型的な表示の実施例を図示する。
【符号の説明】
１２ 穿孔装置
１４ ボアホール
１６ 検層ツール
１８ サブ
２０ ドリルストリング
２２ ドリルビット
２４ 地層
２６ 掘穿泥水
２８ 泥溜め
３０ 坑口
３２ 環状空間
３４ 金属ケーシング
３６ 側壁
３８ ポンプシステム
４０ 泥水供給管路
４２ 流体排出ダクト
７０ ダウンホール・モータ
７２ トップ・ドライブモータ
７４ ロータリ・テーブルモータ[0001]
BACKGROUND OF THE INVENTION
Cross references to pending applications
This application is dated March 26, 1998, which is a continuation-in-part of US Patent No. 08 / 621,411 filed March 25, 1996, now US Pat. No. 5,794,720. This is a continuation-in-part of US 09 / 192,389, filed on November 13, 1998, which is a continuation-in-part of US 09 / 048,360 filed. Pending applications and issued patents are hereby incorporated by reference in their entirety.
[0002]
The present invention relates to ground drilling operations and, more particularly, to a method and system apparatus for predicting the performance of a drilling system for a given formation.
[0003]
[Prior art]
As you know, from the very beginning of the oil and gas well drilling industry, one of the biggest challenges is the inability to see what is happening in the downhole. It was due to the fact that There are any number of downhole conditions and / or events that can be very important in deciding how to proceed. It goes without saying that all methods of attempting to analyze such underground hole conditions and / or events are indirect. To that extent, they are not all ideal and the industry is constantly striving to develop simpler and / or more accurate methods.
[0004]
In general, the approach to the technology was to focus on a particular downhole condition or event and develop a direction to analyze that particular condition or event. For example, US Pat. No. 5,305,836 discloses a method in which the wear of currently used bits can be modeled electronically based on the rock quality of the hole drilled in the bit. This helps the driller determine when to replace the bit.
[0005]
[Problems to be solved by the invention]
The process of determining which type of bit should be used in a given part of a given formation has traditionally been, at best, based only on very rough general considerations and, if bad, scientific. Rather, it has been made by skill and speculation.
[0006]
Other examples can be given for other types of conditions and / or events.
In addition, there are other conditions and / or events that are useful to know. However, they are less necessary and priority is given to developing better methods for analyzing what is more important than that, so there is little or no way to evaluate these other conditions. Attention has not been paid.
[0007]
[Means for Solving the Problems]
According to one embodiment of the present disclosure, an apparatus for predicting the performance of a drilling system for drilling a drill hole in a given formation is a geological feature of the formation per unit depth according to a defined geological model. Means for generating The means for generating the geological feature is for outputting a signal representative of the geological feature, wherein the geological feature further includes at least rock strength. The apparatus further includes means for inputting the specifications of the proposed drilling facility for use in drilling a drill hole. The specification includes at least one bit specification of the recommended drill bit. Finally, the device is a means for determining the expected drilling mechanics according to the specifications of the proposed drilling equipment as a function of the geological features per unit depth according to the prescribed drilling mechanics model Further included. The means for determining the predicted drilling mechanics is further for outputting a signal representative of the predicted drilling mechanics. The predicted drilling mechanics include at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operational parameters.
[0008]
In another embodiment, the device further includes a geological feature output signal and a predicted drilling mechanics output signal to generate a display of the geological features per unit depth and the predicted drilling mechanics. Including means for reacting. The means for generating the display includes either a display monitor or a printer. In the printer example, the display of geological features per unit depth and predicted drilling mechanics includes printouts.
[0009]
In another embodiment, a method for predicting the performance of a drilling system for drilling holes in a given formation a) generates geological features of the formation per unit depth according to a defined geological model And outputting a signal representative of geological features, the geological features including at least rock strength, b) obtaining a proposed drilling equipment specification for use in drilling a drill hole A step, the specification of which includes at least one bit specification of the recommended drill bit, c) proposed as a function of geological features per unit depth according to a defined drilling mechanics model Determining a predicted drilling mechanics according to the specifications of the drilled equipment and outputting a signal representing the predicted drilling mechanics, the prediction Drilling mechanics that includes, bit wear, mechanical efficiency, output, and at least one selected from the group consisting of operating parameters, step, the steps such.
[0010]
In yet another embodiment, a computer program stored on a computer-readable medium executed by a computer for predicting the performance of a drilling system for drilling drill holes in a given formation comprises: a Instructions for generating a geological feature of the formation per unit depth according to a defined geological model and outputting a signal representative of the geological feature, the geological feature including at least rock strength; b) instructions for obtaining the specifications of the proposed drilling equipment for use in drilling drill holes, the specifications including at least one bit specification of the recommended drill bit, c) Predicted according to the specifications of the proposed drilling equipment as a function of geological features per unit depth according to the prescribed drilling mechanics model A command for determining a hole mechanics and outputting a signal representative of the predicted drilling mechanics, the predicted drilling mechanics being a group comprising bit wear, mechanical efficiency, output, and operating parameters An instruction including at least one selected from:
[0011]
In yet another embodiment, an indication of the predicted performance of a drilling system suitable for use as an index in drilling a drill hole in a given formation is disclosed. The representation includes geological features of the formation per unit depth, and the geological features are obtained according to a defined geological model and include at least rock strength. The indication further includes a drilling equipment specification proposed for use in drilling drill holes. The specification includes at least one bit specification of the recommended drill bit. Finally, the display includes the predicted drilling mechanics, and the predicted drilling mechanics are proposed as a function of geological features per unit depth according to a defined drilling mechanics model. It is determined according to the specifications of the drilling equipment. The predicted drilling mechanics include at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operational parameters.
[0012]
Further, with respect to the predicted performance display, the geological features further include at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display, and a display of the predicted drilling mechanics Includes at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display.
[0013]
This embodiment advantageously provides an evaluation of various proposed drilling facilities as well as usage with respect to drilling programs before and during the actual drilling of drill holes in a given formation. The drilling facility, its selection and usage can be optimized for the specific section (s) of the drill hole in a given formation. The drilling mechanics model advantageously takes into account the effects of bit wear that progresses through rock changes. The recommended operating parameters reflect the wear conditions of the bits in the particular rock mass and also take into account the operational constraints of the particular drilling device used. The geological features per unit depth for a given formation and the printout or display of the predicted drilling mechanics are important for drilling operators, especially when used in optimizing drilling processes. Provide information. The printout or display further advantageously provides a head-up view of expected drilling conditions and recommended operating parameters.
[0014]
The foregoing description of the invention and other teachings and advantages will become more apparent in the detailed description of the best mode for carrying out the invention as given later. In the following detailed description, reference will be made to the following accompanying drawings.
[0015]
DETAILED DESCRIPTION OF THE INVENTION
Referring now to FIG. 1, the drilling system 10 includes a drilling device 12 that is disposed over the borehole 14. A logging tool 16 is carried by a sub 18 which is typically a drill collar, incorporated into a drill string 20 and placed in a bore hole 14. The drill bit 22 is located at the lower end of the drill string 20 and engraves the bore hole 14 in the formation 24. The drilling mud water 26 is pumped from a mud reservoir 28 near the wellhead 30, down a shaft center passage (not shown) in the drill string 20, exits the opening of the bit 22, and passes through the annular region 32. Return to the surface. A metal casing 34 is placed in the borehole 14 above the drill bit 22 to maintain the integrity of the upper portion of the borehole 14.
[0016]
Still referring to FIG. 1, the annular space 32 between the drill stem 20, the sub 18, and the side wall 36 of the bore hole 14 forms a return channel for the drilling mud. Mud is pumped from a storage mine near the wellhead 30 by a pump system 38. The muddy water travels through a muddy water supply line 40 that is connected to a central passage that extends the entire length of the drill string 20. The drilling mud is thus pushed down in the drill string 20 to cool and smooth the drill bit and to bring back the formation digs produced during the drilling operation to the ground. Go into the borehole through the opening. The fluid discharge duct 42 is connected to the annular passage 32 at the drill hole head to handle the flow of muddy water returning from the borehole 14 to the mud pool 28. Drilling mud is typically manipulated and processed by various devices (not shown) such as venting devices and circulation tanks to maintain a preselected mud viscosity and concentration.
[0017]
The logging tool or instrument 16 may be any conventional logging tool, such as sound waves (sometimes called acoustic), neutrons, gamma rays, density, photoelectrons, nuclear magnetic resonance, or other conventional logging instruments, or combinations thereof. A stratification instrument used to measure the rock quality or porosity of the formation surrounding a borehole in the ground.
[0018]
Since the logging tool is embodied in the drill string 20 of FIG. 1, the system can be considered a measurement-while-drilling (MWD) system, that is, a system in which the drilling process is recorded as it progresses. The logging data can be stored in a conventional downhole recorder (not shown), which is accessed at the surface when the drill string 20 is removed, or a conventional mud pulse remote It can be transmitted to the surface using telemetry such as a measurement system. In any event, the logging data from the logging tool 16 is sent to the surface measurement device processor 44 so that the data can be processed for use in accordance with embodiments of the present disclosure as described herein. Finally reached. That is, the processor 44 processes the logging data to be suitable for use in the embodiments of the present disclosure.
[0019]
In addition to MWD instruments, wireline logging instruments may be used. That is, a wireline logging instrument can also be used for logging of the formation surrounding the borehole as a function of depth. Along with the wireline instrument, a wireline track (not shown) is usually placed on the surface of the drill hole. The wireline logging tool is suspended in the borehole with a logging cable that passes over the pulley and the depth measurement sleeve. The logging tool records the formation surrounding the borehole as a function of depth as it moves along the borehole. The logging data is transmitted through the logging cable to a logging track or a processor located near the logging track to process the logging data for use in embodiments of the present disclosure. Similar to the MWD embodiment of FIG. L, a wireline instrument can be used to measure rock quality, such as acoustic, neutron, gamma ray, density, photoelectron, nuclear magnetic resonance, or other conventional types. Any conventional logging instrument that can be used to measure the rock quality and / or porosity of the formation surrounding the borehole in the ground, such as a logging tool, or a combination thereof.
[0020]
Still referring to FIG. 1, an apparatus 50 for predicting the performance of a drilling system 10 for drilling a series of drill holes, such as drill holes 14, in a given formation 24 is shown. Prediction device 50 includes a defined set of geological models and drilling mechanics models, and further described in the optimization mode, prediction mode, and calibration mode operations (see FIG. 3, later in the text). )including. The predictor 50 further includes a device 52 that includes any suitable commercially available computer, controller or data processor, and is programmed to perform the methods and apparatus as described herein. The computer / controller 52 includes at least one input for receiving input information and / or commands, eg, from any suitable input device (s) 58. The input device (device) 58 includes a keyboard, keypad, pointing device, or the like, and further includes a network interface or other communication interface for receiving input information from a remote computer or database. Furthermore, the computer / controller 52 includes at least one output for outputting information signals and / or device control commands. The output signal can be output through signal line 54 to display device 60 for use in generating a display of information contained in the output signal. The output signal can also be output to a printer device 62 for use in generating a printout 64 of information contained in the output signal. The information and / or control signals may also be used as necessary to control remote parameters for use in controlling one or more various drilling parameters for the drilling device 12, for example as described herein. It can be output to the device through signal line 66. In other words, a suitable device or means that reacts to the predicted drilling mechanics output signal is provided on the drilling system to control the parameters when actually drilling the drill hole (or section) in the drilling system. Is done. For example, the drilling system includes a device such as one of a controllable motor selected from a downhole motor 70, a top drive motor 72 or a rotary table motor 74, and each of those respective motors. The predetermined number of revolutions per minute can be remotely controlled. The parameters may also include one or more selected from the group such as weight-on-bit, revolutions per minute, mud pump flow rate, water pressure, or other suitable drilling system control parameters. .
[0021]
The computer / controller 52 provides a means for generating geological features of the formation per unit depth according to a defined geological model. In addition, computer / controller 52 provides output of signals representative of geological features on signal lines 54,56. The input device 58 can be used to input the specifications of the proposed drilling facility for drilling a drill hole (or section of a drill hole). The specification includes at least one bit specification of the recommended drill bit. In addition, the computer / controller 52 further determines the predicted drilling mechanics according to the specifications of the proposed drilling facility as a function of geological features per unit depth according to a further defined drilling mechanics model. Provide the means. Furthermore, the computer / controller 52 provides an output of signals representing the expected drilling mechanics on signal lines 54,56.
[0022]
Computer / controller 52 is programmed to perform the functions as described herein using programming techniques well known in the art. In one embodiment, a computer readable medium is included, and the computer readable medium has a computer program stored thereon. The computer program executed by the computer / controller 52 is for predicting the performance of a drilling system for drilling a drill hole of a given formation. The computer program includes instructions for generating a geological feature of the formation per unit depth according to a defined geological model and outputting a signal representative of the geological feature. However, the geological features include at least rock strength. The computer program also includes instructions for obtaining a proposed drilling equipment specification for use in drilling a drill hole. However, the specification includes at least one bit specification for the recommended drill bit. Finally, the computer program determines the predicted drilling mechanics according to the proposed drilling equipment specifications as a function of geological features per unit depth, according to the prescribed drilling mechanics model, Instructions are included for outputting a signal representative of the predicted drilling mechanics. However, the predicted drilling mechanics includes at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operational parameters. Further, programming of a computer program to be executed by computer / controller 52 is accomplished using well-known programming techniques to implement the embodiments as described and described herein. In this way, the geology of a given formation per unit depth can be generated, and further the predicted drilling mechanics performance of the drilling system is determined. Furthermore, the drilling operation can be advantageously optimized while recognizing its expected performance, as further explained later in the text.
[0023]
In a preferred embodiment, the geological features include at least rock strength. In alternative embodiments, the geological features further include any one or more of log data, rock quality, porosity, and shale plasticity.
[0024]
As described above, the input device 58 can be used to enter the specifications of a proposed drilling facility for drilling a drill hole (or section of a drill hole). In the preferred embodiment, the specification includes at least one bit specification of the recommended drill bit. In an alternative embodiment, the specifications include one or more specifications of equipment including a downhole motor, a top drive motor, a rotary table motor, a mud system, and a mud pump. Corresponding specifications include maximum torque output, mud type, or mud pump power rating, for example, as appropriate for a particular drilling facility.
[0025]
In a preferred embodiment, the predicted drilling mechanics include at least one of the drilling mechanics selected from the group consisting of bit wear, machine efficiency, power and operating parameters. In another example, operational parameters can include weight on bit, rotational rpm (revolutions per minute), cost, drilling speed, and torque, which are further described below. The drilling speed further includes the instantaneous speed of drilling (ROP) and the average speed of drilling (ROP-AVG).
[0026]
Referring now to FIG. 2, a flowchart illustrating a method for drilling a series of drill holes in a given formation using an apparatus 50 for predicting the performance of a drilling system will now be described. The method further relates to drilling one or more drill holes (or sections of drill holes) in a given formation to optimize both the drilling system and its usage within the drilling program. Is for. The method includes, in step 100, starting a specific drilling program for a given formation or continuing the drilling program. Regarding the continuation of the drilling program, for some reason, for example due to equipment failure or downtime, the drilling program has been interrupted, so that the drilling program is only partially completed. In the case of repair or replacement of a failed facility, the disclosed method can resume at step 100. Although preferably implemented from the beginning of a given drilling program, the method of the present disclosure may be implemented from any point in the given drilling program to optimize the particular drilling system and its use. It should be noted that it can be done.
[0027]
At step 102, predicted drilling performance for a drilling system for drilling a drill hole in a given formation is generated in accordance with the present disclosure. Furthermore, the drilling performance predicted for a given drill hole drilling is predicted using a defined set of geology and drilling mechanics using at least one mode selected from the group consisting of an optimization mode and a prediction mode. Generated according to the model. In other words, either an optimization mode and / or a prediction mode is used in generating the predicted drilling performance for the drilling system. The predicted drilling performance includes predicted drilling mechanics measurements. The optimization mode and prediction mode are further described later in the text in connection with FIG.
[0028]
At step 104, the drilling operator determines whether an actual drilling mechanics measurement should be obtained during drilling of a given drill hole (or section of drill hole). If the actual drilling mechanics measurements (eg, operating parameters) are to be obtained in step 106, the predetermined drill hole (or section) is drilled with a drilling system that uses the predicted drilling performance as an index. Is done. Further, in step 106, actual drilling mechanics measurements are obtained during drilling of the drill hole (or section). Alternatively, if the determination does not result in a measurement of the operating parameter during drilling of a given drill hole (or section of a drill hole), the method as further described below in the text Moves to step 132.
[0029]
At step 108, the predicted drilling performance is compared to the actual drilling performance using a calibration mode of operation. The calibration mode of operation is further described herein with reference to FIG. In that comparison, the actual drilling mechanics measurements are compared to the predicted drilling mechanics measurements. The comparison process preferably overlays the actual performance plot on the predicted performance (or vice versa) to visually determine any deviation between actual and predicted performance. It is. The comparison may also be realized with the aid of a computer for comparing appropriate data.
[0030]
Referring to step 110 of FIG. 2, step 110 includes a query whether the defined geology and drilling mechanics model is optimized for a particular geology and drilling system. In other words, if the model is optimized for a specific geology and a specific drilling system, a comparison of predicted drilling mechanics measurements with actual drilling mechanics measurements is acceptable. It is. The method then moves to step 112 in connection with the subsequent drilling of the series of drill holes. On the other hand, if the model is not optimized for a particular geology and drilling system, the method moves from step 110 to step 114. If the comparison of the predicted drilling mechanics measurement with the actual drilling mechanics measurement at step 108 is not acceptable, at least one of the geology and drilling mechanics models is calibrated for operation. Fine tune using the mode. At step 114, the geology and drilling mechanics model is fine-tuned (all or partly) using the calibration mode. Using the calibration mode, all or some of the geological and drilling mechanics models are fine-tuned to be appropriate, as determined from a comparison of actual and predicted drilling performance. Once the model has been fine-tuned in step 114, the method moves to step 112 in connection with the subsequent drilling of the series of drill holes.
[0031]
At step 112, the actual drilling performance of the current drill hole is compared with the actual performance of the previous drill hole (s). Such a comparison can determine whether any improvement in performance has occurred. For example, the comparison reveals that the current drill hole was drilled in 18 days compared to the previous drill hole 20 days. In step 116 following step 112, an inquiry is made as to whether the geology and drilling mechanics model has been optimized for the previous drill hole (s). If the model has been optimized, the method moves to step 118. Alternatively, if the model has not been optimized for the previous drill hole (s), the method moves to step 120.
[0032]
At step 118, the values of the operating parameters optimized for drilling performance are documented. Further, the values of the operating parameters optimized for drilling performance are documented and / or recorded in any suitable manner that can be easily accessed and retrieved. Documents and / or records may include, for example, progress reports, computer files, or databases. Thus, step 118 facilitates collection of values that optimize operational parameters on drilling performance. Examples of optimization values include, for example, the economic benefits of optimized drilling, reduced travel to a specific site where drilling is to be performed, reduced drill hole drilling time, or other suitable value measurement Can include various benefits. In a more simple example, running an ocean drilling program would cost $ 150,000 per day. A saving or reduction of 2 days per drill hole (as a result of optimization of the drilling system and its use) would be comparable to a saving of $ 300,000 per drill hole. For the 30 drill hole drilling program, the combined optimization results can potentially be as much as $ 9 million for a given drilling program.
[0033]
At step 120, an inquiry is made as to whether any design changes have been made to the previous drill hole (s). If a design change has been made, the method moves to step 122. At step 122, the design change values for drilling performance are documented in a manner similar to step 118. That is, it is documented (or recorded) in any suitable manner that can be easily accessed and retrieved. Documents and / or records may include, for example, progress reports, computer files, or databases. Thus, step 122 facilitates collection of design change values for drilling performance. Alternatively, if no design changes have been made to the previous drill hole (s), the method proceeds to step 124.
[0034]
At step 124, an inquiry is made as to whether the drilling system is optimized for that particular geology. For example, in current drill holes, if the drilling system is not optimized for a particular geology, certain drilling facility constraints may severely affect drilling performance. For example, if a muddy water pump is inadequate for a given geology, the resulting hydraulic power is insufficient and the holes cannot be cleaned sufficiently, which makes the drilling performance of a drilling system for a particular geology Adversely affects. If the drilling system is not optimized for a particular geology, the method proceeds to step 126, otherwise proceeds to step 128. At step 126, appropriate design changes are implemented or made to the drilling system. The design changes can include equipment replacement, modernization and / or modification, or other design changes as deemed appropriate for the particular geology. In this way, the drilling system equipment and its use can be optimized for drilling to a given geology. The method then proceeds to step 128.
[0035]
At step 128, an inquiry is made as to whether the last drill hole of the drilling program has been drilled. If the last drill hole has been drilled, the method ends at step 130. If the last drill hole has not yet been drilled, the method again proceeds to step 102 and the process as described above continues.
[0036]
In step 132, if no drilling system operating parameters are likely to be obtained, a given drill hole (or section) is drilled with a drilling system that uses the predicted drilling performance as a guide without taking measurements. The In step 132, no drilling mechanics measurements are obtained during drilling of the drill hole (or section). Upon completion of drilling the current drill hole (or section) in step 132, the method proceeds to step 128 and the process as described above continues.
[0037]
The method and apparatus of the present disclosure advantageously allows a drilling system in a drilling program and optimization of its use to be obtained early in a predetermined drilling program. For example, using this method and apparatus, optimization could be obtained by the first few drill holes out of 30 drill hole programs, but without using this method or apparatus. , Optimization may not be achieved up to the 15th drill hole out of 30 drill hole programs. The method further facilitates making appropriate improvements early in the drilling program. Any economic benefits resulting from improvements made early in the drilling program are multiplied by the number of remaining drill holes drilled in the drilling program to yield a benefit. As a result, significant and contentive savings are advantageously achieved for companies that delegate drilling programs. Throughout the drilling program, measurements are made during drilling of each drill hole using the present method and apparatus to verify that a particular drilling system facility has been optimized and used. In addition, the performance of the drilling system equipment can be more easily monitored using the disclosed method and apparatus, and also monitored to identify them before potential adverse conditions actually occur. Can be done.
[0038]
With reference to FIG. 3, a model of the overall drilling system is provided by the predictive model 140. The prediction model further includes a geological model 142 and a drilling mechanics model 144 in accordance with the present method and apparatus. FIG. 3 shows an overview of the various prediction models 140 and how they are linked together. As further described herein, the prediction model 140 is stored and executed by the computer / controller 52 of FIG.
[0039]
The geological model 142 includes a rocky model 146, a rock strength model 148, and a shale plastic model 150. The rock model is the “METHOD FOR QUANTIFYING THE LITHOLOGIC COMPOSTION OF FORMATIONS SURROUNDING EARTH BOREHOLES” published on March 28, 2000, and the lithologic composition of the geological structure surrounding the borehole on the ground. It is preferred to include a rocky model as described in published US Pat. No. 6,044,327. The patent is incorporated in the text as a reference. The rock model provides a method for quantifying the rock component ratio of a given formation, including rock quality and porosity. The rock model utilizes a log suite that is sensitive to any rock or porosity, including, for example, nuclear magnetic resonance, photoelectrons, neutron density, acoustics, gamma rays, and spectral gamma rays. Furthermore, the rocky model provides an improved multi-composition analysis. For example, the rocky row of FIG. 4 shows four compositions, including sandstone, limestone, dolomite, and shale, at a depth of 575 feet. Composition can add weight to a particular log or group of logs. The rocky model recognizes that certain logs are superior to others in elucidating a given rocky composition. For example, it is generally well known that the gamma ray log is the best shale indicator. Coal deposits can be clearly elucidated by neutron logs, but will be missed completely by acoustic logs. A weighting factor is applied so that a given rock quality is resolved by the log or group of logs that can most accurately resolve it. In addition, the rocky model allows the maximum concentration of any rocky composition to vary from zero to 100 percent, which allows the model to be calibrated for core analysis. The rocky model also takes into account the limited range for each rocky composition and can be further based on core analysis. The rocky model can also include any other model suitable for predicting rock quality and porosity.
[0040]
The Rock Strength Model 148 is described in US Pat. No. 5,767,399 entitled “METHODF ASSAYING COMPRESSIVE STRENGTH OFROCK” issued June 16, 1998. It is preferred to include a rock strength model as described. The patent is incorporated herein by reference. The rock strength model provides a way to determine the confinement stress and rock strength within a given formation. The rock strength model can also include any other model suitable for predicting confinement stress and rock strength.
[0041]
The Shale Plastic Model 150 is a United States entitled “METHOD AND APPARATUS FOR QUANTIFYING SHALE PLASTICITY FROM WELL LOGS” published on April 18, 2000. It is preferred to include the shale plasticity model described in US Pat. No. 6,052,649. The patent is incorporated herein by reference. The shale plasticity model provides a method for quantifying the shale plasticity of a given formation. The shale plasticity model can also include any other model suitable for predicting shale plasticity. Thus, the geological model is ready to generate a model for a specific geological application for a given formation.
[0042]
The drilling mechanics model 144 includes a mechanical efficiency model 152, a hole cleaning efficiency model 154, a bit wear model 156, and a drilling speed model 158. The mechanical efficiency model 152 was filed on March 26, 1998, “METHOD OF ASSAYING DOWNHOLE OCCURRRENNCESN CONDITIONS” (agent docket BT-1307 CIP1 / 5528. It is preferred to include a mechanical efficiency model such as that described in pending patent application 09 / 048,360 entitled 322). The patent application is incorporated in the text as a reference. The mechanical efficiency model provides a method for determining the mechanical efficiency of a bit. In the mechanical efficiency model, mechanical efficiency is defined as the percentage of torque to cut. The remaining torque is distributed as friction. The mechanical efficiency model reflects a) the 3D bit shape, b) linked to the cutting torque, c) takes into account the effects of working constraints, and d) analyzes the torque and drag. Use.
[0043]
With respect to the hole cleaning efficiency (HCE) model 154, the model takes into account perforated fluidity type, hydraulics, rock quality and shale plasticity. The hole cleaning efficiency model is a measure for the effectiveness of perforation fluidity and water pressure. If the hole cleaning efficiency is low, drilling debris that is not removed or slowly removed will adversely affect the drilling mechanics.
[0044]
The bit wear model 156 was issued on August 18, 1998 and is entitled “METHODF ASSAYING DOWNHOLE OCCURRENCES AND CONDITIONS”, US Pat. No. 5,794, It is preferred to include the bit wear model described in 720. The patent is incorporated herein by reference. The bit wear model provides a method for determining bit wear, i.e., predicting bit life and abrasion of the formation. In addition, the bit wear model is used to apply a work rating to a given bit.
[0045]
The drilling speed model 158 was issued on January 16, 1998 and is entitled “METHOD OF REGULATING DRILLING CONDITIONS APPLIED TO A WELL BIT”. It is preferred to include a drilling speed model as described in US Pat. No. 5,704,436. The patent is incorporated herein by reference. The drilling speed model provides a method for optimizing operating parameters and for predicting the drilling speed of the bit and drilling system. ROP model maximizes drilling speed, limits output to avoid impact damage to bits, considers all operational constraints, optimizes operating parameters Providing one or more of minimizing bit-induced vibrations.
[0046]
The drilling mechanics model 144 as described herein is used or intended for drilling a drill hole, a section of a drill hole, or a series of drill holes placed in a predetermined drilling operation. Providing a comprehensive model generation of a specific drilling system proposed. The drilling mechanics model 144 further enables the generation of drilling mechanics performance predictions for drilling systems at a given geology. Comparison of actual and predicted performance is used to match history with drilling mechanics models and to optimize each drilling mechanics model on demand be able to.
[0047]
Still referring to FIG. 3, the present method and apparatus includes several modes of operation. The operation mode includes an optimization mode, a prediction mode, and a calibration mode. For various modes of operation, predictive economics are provided to provide a measure of day shortening per drill hole that is achieved when the drilling system is optimized using the methods and apparatus of the present disclosure.
Optimization mode
In the optimization mode, the purpose is to optimize the operating parameters of the drilling system. Optimization criteria are: 1) maximize drilling speed, 2) avoid impact damage to the bit, 3) consider all operational constraints, and 4) minimize bit-induced vibration It is to limit.
[0048]
In the optimized mode, the rock model 146 receives data from the porosity log, rock log, and / or mud log on input 160. Porosity or rocky logs can include nuclear magnetic resonance (NMR), photoelectrons, neutron density, acoustics, gamma rays, and spectral gamma rays, or any other log that is sensitive to porosity or rock quality. Mud logs are used to identify rocky compositions that are not shale. In response to the log input, the rock model 146 provides a measure of the rock quality and porosity of a given formation per unit depth on the output 162. With respect to rock quality, the output 162 preferably includes the volume ratio of each rocky composition of the formation per unit depth. With respect to porosity, the output 162 preferably includes the volume ratio of the amount of porosity in the formation rock per unit depth. The measures for rock quality and porosity on output 162 are input to rock strength model 148, shale plastic model 150, mechanical efficiency model 152, hole cleaning efficiency model 154, bit wear model 162, and drilling speed model 158. .
[0049]
In addition to receiving measures of rock quality and porosity output 162 for rock strength model 148, rock strength model 148 further receives mud weight and pore pressure data at input 164. The muddy water weight is used to calculate the overbalance. The pore water pressure is used to calculate the overbalance, but alternatively, the design overbalance may be used to estimate the pore water pressure. In response to that input, the rock strength model 148 creates a measure on the output 166 for the confinement stress and rock strength of a given formation per unit depth. Among other things, the rock strength model creates measures of overbalance, effective pore water pressure, confinement stress, unconfined rock strength, and confined rock strength. Overbalance is defined as the muddy water weight minus the pore water pressure. Effective pore water pressure is similar to pore water pressure, but reflects a reduction in permeability in shale and non-shale with low porosity. Confinement stress is an estimate of the confinement stress at the original location of the rock. Unconfined rock strength is the rock strength at the earth's surface. Finally, the confinement rock strength is the rock strength in the state where the stress is confined at the original position. As shown, rock strength output 166 is input to mechanical efficiency model 152, bit wear model 162, and drilling speed model 158.
[0050]
With respect to the mechanical efficiency model 152, in addition to receiving the rock quality and porosity output 162, and the confinement stress and rock strength output 166, the mechanical efficiency model 152 is an operational, all related to the drilling system, on the input 168. Input data regarding constraints, 3D bit model, and torque and drag. Operational constraints include maximum torque, maximum weight on bit (WOB), maximum and minimum RPM, and maximum drilling speed. In particular, with respect to mechanical efficiency, operational constraints in drilling systems include maximum torque, maximum weight on bit (WOB), minimum RPM, and maximum drilling speed. Operational constraints limit the amount of optimization that can be achieved with a particular drilling system. In addition, regarding the assessment of the impact of operational constraints on mechanical efficiency, not all constraints affect both mechanical efficiency and power, but these impacts on either mechanical efficiency or power. In order to quantify the impact of constraints, it is necessary to know all of the constraints. The 3D bit model input includes the bit working rating and the torque-WOB signature. Finally, torque and drag analysis includes direction planning, casing and drill string shapes, mud weight and flow rate, coefficient of friction, or torque and drag measurements. Torque and drag analysis is necessary to determine how much surface torque is actually transmitted to the bit. Alternatively, measurements of off-bottom and on-bottom torque can be used instead of torque and drag analysis. In addition, a near bit measurement system from between drilling (MWD) measurements can be used instead of torque and drag analysis. Depending on the input information, the mechanical efficiency model 152 may generate an output 170 on the mechanical efficiency, constraint analysis, predicted torque, and optimum bit for a drilling system in a given formation per unit depth. Create a measure of weight (WOB). Among other things, the mechanical efficiency model 152 provides a measure of total torque, cutting torque, friction torque, mechanical efficiency, constraint analysis, and optimal WOB. Total torque represents the total torque applied to the bit. Cutting torque represents the cutting component of the total torque. The friction torque is a friction component of the total torque. With respect to the mechanical efficiency model 152, mechanical efficiency is defined as a percentage as the total torque to cut. The constraint analysis quantifies the decrease in mechanical efficiency from the theoretical maximum that results from each operational constraint. Finally, the optimum WOB that maximizes the drilling speed is determined while the WOB considers all operational constraints. The optimal WOB is used by the drilling speed model 158 to calculate the optimal RPM. Furthermore, the mechanical efficiency model 152 uses the bit wear measure from the previous iteration as an input, as described further below for the bit wear model.
[0051]
Here, in conjunction with the bit wear model 156, the bit wear model receives input from the rock model via output 162, input from the rock strength model via output 166, and mechanical efficiency model via output 170. Receives input from. In addition, bit wear model 156 receives 3D bit model data on input 172. The 3D bit model input includes the bit working rating and the torque-WOB signature. Depending on the rock quality, porosity, mechanical efficiency, rock strength, and input of the 3D bit model, the bit wear model 156 has a specific energy for a bit in a given formation per unit depth on the output 174. Create measures of cumulative work, formation polishing, and bit wear. The specific energy is the total energy applied to the bit and is equivalent to the value obtained by dividing the bit force by the bit cross-sectional area. The cumulative work done by the bits reflects both rock strength and mechanical efficiency. The formation polishing measure models the wear accelerated by formation polishing. Finally, the bit wear measure corresponds to the wear conditions linked to the bit axial contact area and mechanical efficiency. In addition to output 174, bit wear model 156 includes providing a measure of bit wear from a previous iteration to mechanical efficiency model 152 on output 176, where mechanical efficiency model 152 further includes on output 170. In calculating the mechanical efficiency output data, the bit wear measure from the previous iteration is used.
[0052]
Prior to describing the digging speed model 158, first, the shale plastic model 150 is returned. As shown in FIG. 3, the shale plastic model 150 receives input from a rocky model. In particular, the shale volume is provided from a rocky model 146. In addition to receiving the rock and porosity output 162, the shale plastic model 150 receives log data from the drill hole log defined on the input 178, which includes the clay type, clay moisture, and Includes any log that is sensitive to clay volume. Such logs include nuclear magnetic resonance (NMR), neutron density, acoustic density, spectral gamma rays, gamma rays, and cation exchange capacity (CEC). In response to the input, shale plasticity model 150 creates a measure of formation shale plasticity per unit depth on output 180. In particular, the shale plasticity model 150 provides a measure of standard clay type, standard clay moisture content, standard clay volume, and shale plasticity. The standard clay type reveals the maximum concentration of smectite, the smectite being the clay type that most likely causes clay swelling. Standard clay moisture content reveals the moisture content at which maximum shale plasticity occurs. The standard clay volume reveals the range of clay volumes in which plasticity can occur. Finally, shale plasticity is a weighted average of the properties of standard clay and reflects the overall plasticity.
[0053]
With respect to the hole cleaning efficiency model 154, the model 154 receives shale plastic input from the shale plastic model 150 and rocky input from the rocky model 146. In addition to receiving the rocky model output 162 and the shale plastic model output 180, the hole cleaning efficiency model 154 receives hydraulic and drilling water data on input 182. In particular, the hydraulic input can include any standard measure of hydraulic efficiency such as hydraulic horsepower per square inch of bit diameter. Further, drilling mud types include water-based mud, oil-based mud, polymer, or other well-known mud types. Depending on the input, the hole cleaning efficiency model 154 provides on the output 184 a measure of the hole cleaning efficiency predicted for the bit and drilling system when drilling drill holes (or sections) in the formation per unit depth. create. Hole cleaning efficiency is defined herein as the predicted drilling speed divided by the actual drilling speed. While other drilling mechanics models assume perfect hole cleaning, the hole cleaning efficiency (HCE) model predicts drilling speed to compensate for hole cleaning that deviates from the ideal movement. Is a measure for correcting. Thus, the hole cleaning efficiency (HCE) measure reflects the influence of rock quality, shale plasticity, water pressure, and drilling mud water type on drilling speed.
[0054]
Referring now to the drilling speed model 158, the drilling speed model 158 receives the mechanical efficiency, predicted torque and optimal WOB via the output 170 of the mechanical efficiency model 152. The model 158 further receives bit wear via the output 174 of the bit wear model 156, rock strength via the output 166 of the rock strength model 148, and predicted HCE via the output 184 of the HCE model 154. Further, the drilling speed model 158 receives operational constraint information on the input 186. In particular, operational constraints include maximum torque, maximum weight on bit (WOB), maximum and minimum RPM, and maximum drilling speed. In addition, with respect to assessing the impact of operational constraints on output, not all constraints affect both mechanical efficiency and output, but these constraints affect either mechanical efficiency or output. In order to quantify the impact, it is necessary to know all of the constraints. In response to the input, the drilling speed model 158 generates output level analysis and constraint analysis for the bit and drilling system when drilling a drill hole (or section) in the formation per unit depth on the output 188. , As well as in addition, measures of optimal RPM, drilling speed, and economy. Among other things, the output level analysis involves determining the maximum limit of output. The maximum power limit maximizes drilling speed without causing impact damage to the bit. The operation output level is smaller than the maximum output level due to operational restrictions. The constraint analysis includes quantifying the reduction of the operational output level from the maximum limit of output that results from each operational constraint. The optimal RPM is the RPM that maximizes the drilling speed while taking into account all operational constraints. The drilling speed is the predicted drilling speed at the optimal WOB and optimal RPM. Finally, the economy can be said to be an industry standard cost analysis per foot.
Prediction mode
In the prediction mode, the object or purpose is to predict the drilling performance when the user-specified operation parameters are provided, which are not necessarily optimal. Operational restrictions do not apply to this mode. As explained later in the text, the prediction mode is essentially similar to the optimization mode, with the exception of the mechanical efficiency model 152, the bit wear model 156, and the permeability model 158. The hole cleaning efficiency model 154 is the same for both the optimization mode and the prediction mode because the hole cleaning efficiency does not depend on the parameters for mechanical operation (ie user specified WOB and user specified RPM).
[0055]
In addition to receiving rock quality and porosity output 162 and confinement stress and rock strength output 166 for mechanical efficiency model 152 in predictive mode, mechanical efficiency model 152 is associated with the drilling system on input 168. Receives user-specified operating parameters and input data relating to the 3D bit model. User-specified operating parameters for the drilling system may include user-specified weight on bit (WOB) and user-specified RPM. This option is used to evaluate a scenario of “what happens if it is so”. The 3D bit model input includes the bit working rating and the torque-WOB signature. In response to that input, the mechanical efficiency model 152 creates a measure of mechanical efficiency for the drilling system in a given formation per unit depth at the output 170. Among other things, the mechanical efficiency model 152 provides a measure of total torque, cutting torque, friction torque, and mechanical efficiency. Total torque represents the total torque applied to the bit. In the prediction mode, the total torque corresponds to the weight on the bit specified by the user. Cutting torque represents the cutting component of the total torque on that bit. Friction torque is the friction component of the total torque on that bit.
[0056]
With respect to the mechanical efficiency model 152, mechanical efficiency is defined as a percentage as the total torque to cut. The prediction mode also includes analysis of mechanical efficiency by range, i.e., by range of mechanical efficiency with respect to the mechanical efficiency torque-WOB signature of the bit. The first range of mechanical efficiency is defined by the first on-bit weight (WOB) range from zero WOB to a threshold WOB, where the threshold WOB is a predetermined WOB required to just drill the rock. Furthermore, just digging corresponds to a depth of cut of zero (or negligible). Furthermore, the first range of mechanical efficiency corresponds to a drilling efficiency such as efficient grinding. The second range of mechanical efficiency is defined by the second on-bit weight range from the threshold WOB to the optimal WOB, where the optimal WOB is the maximum depth of cut at the bit before the bit body contacts the formation. This corresponds to the predetermined WOB necessary to achieve the above. Furthermore, the second range of mechanical efficiency corresponds to a drilling efficiency such as efficient cutting. The third range of mechanical efficiency is defined by the third on-bit weight range from optimal WOB to grinding WOB, where grinding WOB is such that the cutting torque of the bit is essentially just zero or negligible. Corresponds to the predetermined WOB required to be reduced. Furthermore, the third range of mechanical efficiency corresponds to drilling efficiency such as inefficient cutting. Finally, the fourth range of mechanical efficiency is defined by the weight range on the fourth bit beyond that of the grinding WOB. Furthermore, the fourth range of mechanical efficiency corresponds to drilling efficiency such as inefficient grinding. With respect to the third and fourth ranges, although the bit achieves the maximum depth of cut, as the WOB increases, the frictional contact with the rock layer of the bit body also increases.
[0057]
In addition, the mechanical efficiency model 152 utilizes the bit wear measure from the previous iteration as an input, as described further below with respect to the bit wear model.
[0058]
In the prediction mode, in relation to the bit wear model 156, the bit wear model receives input from the rock model via output 162, input from the rock strength model via output 166, and output 170. Receive input from mechanical efficiency model. In addition, bit wear model 156 receives 3D bit model data on input 172. The 3D bit model input includes the bit working rating and the torque-WOB signature. Depending on the rock quality, porosity, mechanical efficiency, rock strength, and input of the 3D bit model, the bit wear model 156 has a specific energy for a bit in a given formation per unit depth on the output 174. Create measures of cumulative work, formation polishing, and bit wear. The specific energy is the total energy applied to the bit and is equivalent to the value obtained by dividing the bit force by the bit cross-sectional area. Furthermore, the calculation of specific energy is based on user-specified operating parameters. The cumulative work done by the bits reflects both rock strength and mechanical efficiency. The cumulative work done by the bits is also based on user-specified operating parameters. The formation polishing measure models the wear accelerated due to formation polishing. Finally, the bit wear measure corresponds to the wear conditions linked to the bit axial contact area and mechanical efficiency. Similar to the calculation of specific energy and cumulative work, the calculation of bit wear is based on user-specified operating parameters. In addition to the output 174, the bit wear model 156 includes providing a measure of bit wear from the previous iteration to the mechanical efficiency model 152 on the output 176, where the mechanical efficiency model 152 further includes the output 170 on the output 170. The bit wear measure from the previous iteration is used in calculating the mechanical efficiency output data.
[0059]
Referring now to the drilling speed model 158, the drilling speed model 158 receives mechanical efficiency and predicted torque via the output 170 of the mechanical efficiency model 152. The model 158 further receives bit wear via the output 174 of the bit wear model 156, rock strength via the output 166 of the rock strength model 148, and predicted HCE via the output 184 of the HCE model 154. Further, the drilling speed model 158 receives user-specified operating parameters on the input 186. In particular, user-specified operating parameters include user-specified weight on bit (WOB) and user-specified RPM. As described above, the prediction mode of this operation is used to evaluate a scenario of “what happens if so”. In response to the input, the drilling speed model 158 outputs on the output 188 the power level for the bit and drilling system in predicting and drilling drill holes (or sections) in the formation per unit depth. Analyze, as well as measures of drilling speed and economy. Among other things, the output level analysis involves determining the maximum limit of output. The maximum power limit corresponds to a defined power output that maximizes drilling speed without causing impact damage to the bit when applied to the bit. The operation output level resulting from the user-specified operation parameters is less than or greater than the maximum output limit. Operational output levels that exceed the maximum limit of output on the bit are automatically flagged, for example by appropriate programming, to indicate or clarify the area of the drill hole where impact damage to the bit is likely to occur be able to. The power level analysis is applied to a specific drilling system and its use when drilling a drill hole (or section) within a given formation. Further, the digging speed is a digging speed predicted when the user-specified WOB and the user-specified RPM are used. Finally, economy is an industry standard cost analysis per foot.
Calibration mode
Finally, in calibration mode, the object or purpose is to calibrate the drilling mechanics model to the measured operating parameters. In addition, the geological model can also be calibrated to the measured core data. Any model or group of models can be partially or fully calibrated. As in the prediction mode, operational constraints do not apply to the calibration mode.
[0060]
Beginning with the geological model 142, the measured core data is used to calibrate the geological model. With respect to the rocky model, the rocky model 146 receives on the input 160 data from the porosity log, rocky log and / or mud log, and core data. As described above, porosity or rocky logs can be nuclear magnetic resonance (NMR), photoelectrons, neutron density, acoustics, gamma rays, and spectral gamma rays, or any other log that is sensitive to porosity or rock quality. Can be included. Mud logs are used to identify non-shale rock components. The core data includes measured core data that can be used to calibrate the rock model. By calibrating the rock model with measured core data, the predicted rock composition will better match the measured core composition. The measured core porosity is also used to calibrate any porosity drawn from the log. In response to that input, the rock model 146 provides a measure of the rock quality and porosity of a given formation per unit depth on the output 162. For calibrated rock quality, the output 162 is each preferred for formation per unit depth. It is preferable to include the volume ratio of the rocky composition. With respect to the calibrated porosity, it is preferred that the output 162 drawn from the log is calibrated to the measured core porosity. Also, less accurate logs can be calibrated to more accurate logs. Calibration for rock quality and porosity on output 162 is input to rock strength model 148, shale plastic model 150, mechanical efficiency model 152, hole cleaning efficiency model 154, bit wear model 152, and drilling speed model 158. .
[0061]
For the rock strength model 148, the inputs and outputs are very similar to those described above for the optimization mode. However, in calibration mode, the input 164 further includes core data. Core data includes measured core data used to calibrate the rock strength model. Calibration allows the predicted rock strength to better match the measured core strength. Furthermore, the measured pore water pressure data can be used to calibrate the confinement stress calculation.
[0062]
For the shale plastic model 150, the inputs and outputs are very similar to those described above for the optimization mode. However, in calibration mode, input 178 further includes core data. The core data includes measured core data used to calibrate the shale plasticity model. Calibration allows the predicted plasticity to better match the measured core plasticity. In response to that input, the shale plasticity model 150 provides on the output 180 a measure of shale plasticity for a given formation per unit depth. For calibrated shale plasticity, output 180 preferably includes a weighted average of standard clay properties that reflect the overall plasticity calibrated for core analysis.
[0063]
For the mechanical efficiency model 152, the inputs and outputs are very similar to those described above for the optimization mode with the following exceptions. In calibration mode, input 168 includes measured operational parameters, although it does not include operational constraints or torque and drag analysis. The measured operating parameters include weight on bit (WOB), RPM, drilling speed, and torque (optional), which are used to calibrate the mechanical efficiency model. In response to that input, mechanical efficiency model 152 provides a measure of total torque, cutting torque, friction torque, and calibrated mechanical efficiency at output 170. With respect to total torque, total torque is the total torque applied to the bit, which is calibrated to the measured torque if data is available. The cutting torque is the cutting component of the total torque on the bit and is calibrated to the actual mechanical efficiency. Friction torque is the friction component of the total torque on the bit and is calibrated for actual mechanical efficiency. With respect to the calibrated mechanical efficiency model 152, mechanical efficiency is defined as a percentage of the total torque to be cut. The predicted mechanical efficiency is calibrated to the actual mechanical efficiency. The calibration becomes more accurate if measured torque data is available. However, even if torque data is not available, it is possible to partially calibrate the mechanical efficiency by using torque predicted by other measured operating parameters.
[0064]
The calibration mode also includes mechanical efficiency analysis by range, ie, by mechanical efficiency range with respect to the bit mechanical efficiency torque-WOB signature. As indicated above, the first range of mechanical efficiency is defined by the first over-bit weight (WOB) range from zero WOB to the threshold WOB, where the threshold WOB is just drilled into the rock. It corresponds to a predetermined WOB necessary for the operation, and further, just digging corresponds to a cutting depth of zero (or negligible). Further, the first range of mechanical efficiency corresponds to the drilling efficiency such as efficient grinding. The second range of mechanical efficiency is defined by the second on-bit weight range from the threshold WOB to the optimal WOB, where the optimal WOB is the maximum depth of cut at the bit before the bit body contacts the formation. This corresponds to the predetermined WOB necessary to achieve the above. Furthermore, the second range of mechanical efficiency corresponds to drilling efficiency such as efficient cutting. The third range of mechanical efficiency is defined by the third on-bit weight range from optimal WOB to grinding WOB, where grinding WOB is such that the cutting torque of the bit is essentially just zero or negligible. Corresponds to the predetermined WOB required to be reduced. Furthermore, the third range of mechanical efficiency corresponds to drilling efficiency such as inefficient cutting. Finally, the fourth range of mechanical efficiency is defined by the weight range on the fourth bit beyond that of the grinding WOB. Furthermore, the fourth range of mechanical efficiency corresponds to drilling efficiency such as inefficient grinding. With respect to the third and fourth ranges, although the bit achieves the maximum depth of cut, as the WOB increases, the frictional contact with the rock layer of the bit body also increases.
[0065]
For the bit wear model 156, the inputs and outputs are similar to those described above for the optimization mode. However, in the calibration mode, input 172 further includes bit wear measurements. The bit wear measurement includes a measure of the current axial contact area of the bit. In addition, bit wear measurements correlate with the cumulative work done by the bits based on the measured operating parameters. Depending on its input, the bit wear model 156 can be configured on the output 174 for specific energy, cumulative work, calibrated formation polishing, and calibrated bit work rating for a given drilling system and formation per unit depth. Provides a measure. With respect to specific energy, specific energy corresponds to the total energy applied to the bit. Furthermore, the specific energy is equivalent to the value obtained by dividing the bit force by the bit cross-sectional area, and the calculation is further based on the measured operational parameters. With respect to cumulative work, the cumulative work performed by the bit reflects both rock strength and mechanical efficiency. Furthermore, the calculation of cumulative work is based on the measured operational parameters. With respect to calculated formation polishing, the bit wear model accelerates wear due to formation polishing. In addition, bit wear measurements and the cumulative work done can be used to calibrate formation polishing. Finally, with respect to the calibrated bit work rating, the sharp bit wear condition is linked to the cumulative work done. In calibration mode, the bit work rating of a given bit is calibrated to the bit wear measurement and calibration work done.
[0066]
For the hole cleaning efficiency model 154, the inputs and outputs are very similar to those described above for the optimization mode. However, in the calibration mode, as further described below in the text, the hole cleaning efficiency is calibrated by correlating with the HCE measured in the drilling speed model.
[0067]
For the drilling speed model 158, the inputs and outputs are very similar to those described above for the optimization mode. However, in calibration mode, input 186 does not include operational constraints, but rather includes measured operational parameters and bit wear measurements. The measured operating parameters include weight on bit (WOB), RPM, drilling speed, and torque (optional). The bit wear measurement is a measure of the current axial contact area of the bit and identifies the dominant wear type of uniform and non-uniform wear. For example, impact damage is a non-uniform wear pattern. The measured operating parameters and bit wear measurements are used to calibrate the drilling speed model. Depending on its input, the drilling speed model 158 provides a measure of the calibrated drilling speed, the calibrated HCE, and the calibrated power limit. With respect to the calibrated drilling speed, the calibrated drilling speed is the predicted drilling speed when using the measured operational parameters. The predicted drilling speed is calibrated to the measured drilling speed using HCE as the correction factor. For a calibrated HCE, the HCE is defined as the expected drilling speed divided by the actual speed. The HCE predicted from the HCE model is calibrated to the HCE calculated in the drilling speed model. Finally, with respect to calibrated power limits, the maximum power limit maximizes drilling speed without causing impact damage to the bit. If the operating power level due to the measured operating parameters exceeds the power limit, impact damage can occur. The software or computer program for realizing the performance prediction of the drilling system can be set to automatically flag all operational output levels that exceed the output limit. Furthermore, the power limit is adjusted to reflect the type of wear that is actually seen on the biting bits. For example, the program flags an area where impact damage is likely to occur, but the wear seen on a biting bit is largely uneven, so its power limit is probably too modest and raised. Should.
[0068]
Further, performance analysis including analysis of operation parameters may be executed. The operational parameters to be measured include WOB, TOB (optional), RPM, and ROP. In order to obtain a more accurate performance analysis result, measurement near the bit is preferable. Other performance analysis measurements include bit wear measurements, drilling mud type and water pressure, and economy.
Overview
Referring again to FIG. 1, an apparatus 50 for predicting the performance of the drilling system 10 for drilling a drill hole 14 in a given formation 24 will now be further described. The predictor 50 includes a computer / controller 52 for generating geological features of the formation per unit depth according to a defined geological model and for outputting signals representing the geological features. Suitably the geological features include at least rock strength. Further, the geological feature generation means 52 generates at least one of additional features selected from the group consisting of log data, rock quality, porosity, and shale plasticity.
[0069]
An input device 58 is provided for inputting the specifications of a proposed drilling facility for drill hole drilling, where the specifications include at least one bit specification of a recommended drill bit. Further, the input device (s) 58 is at least one of the proposed drilling equipment selected from the group consisting of downhole motors, top drive motors, rotary table motors, mud systems, and mud pumps. Used to enter additional proposed drilling facility input specifications that may further include two additional specifications.
[0070]
Finally, the computer / controller 52 determines the predicted drilling mechanics according to the proposed drilling equipment specifications as a function of the geological features per unit depth according to a defined drilling mechanics model. Is. The computer / controller 52 is further for outputting a signal representative of the predicted drilling mechanics, including at least one selected from the group consisting of bit wear, mechanical efficiency, output, and operational parameters. . The operating parameters include at least one selected from the group consisting of weight on bit, rotary rpm (revolutions per minute), cost, drilling speed, and torque. Further, the excavation speed includes an instantaneous excavation speed (ROP) and an average excavation speed (ROP-AVG).
[0071]
As shown in FIG. 1, the display 60 and the printer 62 respectively generate a geological feature output signal and a predicted to generate a display of geological features per unit depth and predicted drilling mechanics. Means are provided for reacting to drilling mechanics output signals. For the printer 62, the display of geological features per unit depth and predicted drilling mechanics includes a printout 64. In addition, the computer / controller 52 provides a drilling operation control signal on line 66 for a predetermined predicted drilling mechanics output signal. In such instances, the drilling system further includes one or more responsive to drilling operation control signals based on the predicted drilling mechanics output signal to control parameters in the actual drilling of the drill hole in the drilling system. Including devices. Typical parameters include at least one selected from the group consisting of weight on bit, rpm, pump flow, and water pressure.
Display of predicted performance
Referring now to FIG. 4, a display 200 of predicted performance of the drilling system 50 (FIG. 1) for a given formation 24 (FIG. 1) is described in further detail. Display 200 includes a display of geological features 202 and a display of predicted drilling mechanics 204. The display of the geological feature 202 includes at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display. Further, the predicted drilling mechanics 204 display includes at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display. In a preferred embodiment, at least one graphical representation for the geological feature 202 and at least one graphical representation for the predicted drilling mechanics 204 are color coded.
Header description
Below is a list of various symbols, corresponding schematic descriptions, units, and data ranges for the various columns of information shown in FIG. It should be noted that this list is merely exemplary and not limiting. This list is incorporated here to provide a complete understanding of the illustration of FIG.
Other symbols, descriptions, units, and data ranges are possible.

Comment¹: The color shown for each column is represented by the respective shading as shown in FIG.
Depth, log data, rock quality, porosity
As shown in FIG. 4, the depth of the formation 206 is expressed in the form of a numerical expression. The log data 208 is represented in a curvilinear display and includes any log suite that is sensitive to rock quality and porosity. Rocky 210 is represented in the form of a percentage graph for use in identifying different types of rock within a given formation, and the percentage graph is from any log suite that is sensitive to rock quality. As determined, the percentage of each type of rock at a given depth is illustrated. In one embodiment, the rocky percentage graph is color coded. The porosity 212 is expressed in the form of a curve and is determined from any log suite that is sensitive to porosity.
Rock strength
On the display 200 of FIG. 4, the rock strength 214 is at least one display form selected from the group consisting of a curve display 216, a percentage graph display (not shown but similar to 210), and a band display 218. It is represented by The rock strength curve representation 216 includes a confined rock strength 220 and an unconfined rock strength 222. An area 224 between the respective curves of the confined rock strength 220 and the unconfined rock strength 222 is graphically represented, which represents an increase in rock strength as a result of the confinement stress. The rock strength band display 218 provides a graphical illustration showing a discrete range of rock strength at a given depth, and more generally, a variety of rock strengths along a given drill hole. Individual ranges are shown. In the preferred embodiment, the rock strength band display 218 is color coded, with a first color representing a soft rock strength range, a second color representing a hard rock strength range, and an additional representing one or more neutral rock strength ranges. Including colors. Furthermore, blue can be used to indicate a soft rock strength range, red to indicate a hard rock strength range, and yellow to indicate a neutral rock strength range. A legend 226 is provided on the display to help interpret the various displayed geological features and predicted drilling mechanics.
Shale plasticity
On the display 200 of FIG. 5, the shale plasticity 228 is at least one display form selected from the group consisting of a curve display 230, a percentage graph display (not shown but similar to 210), and a band display 232. It is represented by The shale plasticity 228 curve representation 230 includes at least two curves of shale plasticity parameters selected from the group consisting of moisture content, clay type, and clay volume, where the shale plasticity is defined by a defined shale plasticity model 150 ( According to FIG. 3) it is determined from the water content, clay type and clay volume. Further, the shale plasticity display is preferably color-coded. The band display 232 of shale plastic 228 provides a graphical illustration showing the individual ranges of shale plastic at a given depth, and more generally, various individual shale plastics along a given drill hole. Indicates the range. In a preferred embodiment, the band representation 232 of shale plastic 228 is color coded to represent a first color representing a low shale plastic range, a second color representing a high shale plastic range, and one or more intermediate shale plastic ranges. Includes additional colors. Furthermore, blue can be used to indicate a low shale plastic range, red to indicate a high shale plastic range, and yellow to indicate an intermediate shale plastic range. As described above, the legend 226 on the display 200 is provided to help interpret various displayed geological features and predicted drilling mechanics.
Bit work / wear relation
Bit wear 234 is determined as a function of cumulative work done according to a defined bit wear model 156 (FIG. 3). On the display 200 of FIG. 5, the bit wear 234 is represented in at least one display form selected from the group consisting of a curve display 236 and a percentage graph display 238. The bit wear curve representation 236 includes bit work expressed as specific energy level at the bit, cumulative work done by the bit, and any work loss due to polishing. With respect to the percentage graph representation, the bit wear 234 can be represented as a percentage graph 238 illustrated in a graph expression showing bit wear conditions at a given depth. In the preferred embodiment, the percentage graph 238 illustrated in the bit wear graph is color coded and includes a first color 240 representing the expired bit life and a second color 242 representing the remaining bit life. Further, red is preferable for the first color, and green is preferable for the second color.
Mechanical efficiency
Bit mechanical efficiency is determined as a function of the torque / bit weight signature for a given bit according to a defined mechanical efficiency model 152 (FIG. 3). On the display 200 of FIG. 5, the bit mechanical efficiency 244 is represented in at least one display form selected from the group consisting of a curve display 246 and a percentage graph display 248. The bit mechanical efficiency curve display 246 includes the total torque (TOB (ft · lb)) and cutting torque (TOB-CUT (ft · lb)) at the bit. The percentage graphical representation 248 of the bit mechanical efficiency 244 graphically illustrates the total torque, where the total torque includes cutting torque and friction torque components. In the preferred embodiment, the percentage graph 248 illustrated in the mechanical efficiency graph is color coded, a first color illustrating the cutting torque 250, a second color illustrating the friction-free torque 252, and the friction Includes a third color illustrating the limited torque 254. A legend 226 is also provided to help interpret the various torque components of mechanical efficiency. Furthermore, the first color is preferably blue, the second color is yellow, and the third color is red.
[0072]
In addition to the curve display 246 and the percentage graph 248, the mechanical efficiency 244 is further represented in the form of a percentage graph 256 that illustrates drilling system operational constraints that adversely affect mechanical efficiency. The perforation system operational constraints correspond to constraints that cause the generation of a friction limited torque (eg, as illustrated by reference numeral 254 in the percentage graph 248), where the percentage graph 256 is Figure 5 shows the corresponding impact percentage that mechanical efficiency friction at a given depth exerts on a limited torque component. Drilling system operational constraints include: maximum torque on bit (TOB), maximum weight on bit (WOB), minimum revolutions per minute (RPM), maximum drilling speed (ROP), any combination thereof , And unrestricted conditions. In a preferred embodiment, the percentage graph display 256 for drilling system operational constraints related to mechanical efficiency is color coded and includes different colors to identify different constraints. In addition, a legend 226 is provided with respect to the percentage graph display 256 to help interpret various drilling system operational constraints on mechanical efficiency.
output
On the display 200 of FIG. 6, the output 258 is represented in at least one display form selected from the group consisting of a curve display 260 and a percentage graph display 262. The curve display 260 for the output 258 includes an output limit (POB-LIM (hp)) and an operation output level (POB (hp)). The output limit (POB-LIM (hp)) corresponds to the maximum output to be applied to the bit. The operation output level (POB (hp)) includes at least one selected from the group consisting of a limited operation output level, a recommended operation output level, and a predicted operation output level. Regarding the curve display 260, the difference between the curves of the output limit (POB-LIM (hp)) and the operation output level (POB (hp)) indicates a restriction.
[0073]
Further, the output 258 is represented in the form of a percentage graph display 262 illustrating drilling system operational constraints that adversely affect the output. The constraints on drilling system operation correspond to constraints that result in power loss. The output constraint percentage graph 262 shows the corresponding impact percentage that each constraint exerts on the output at a given depth. In the preferred embodiment, the perforation system operational constraint percentage graph display 262 for output is color coded and includes different colors to identify different constraints. Further, it is preferred that red is used to identify the maximum ROP, and blue is used to identify the state where the scarlet is not restricted, in order to identify the maximum RPM. In addition, a legend 226 is provided with respect to the percentage graph display 262 to help interpret various drilling system operational constraints on the output.
Operation parameters
As shown in FIG. 6, the operation parameter 264 is represented in the form of a curve display 266. As explained above, the operational parameters include at least one selected from the group consisting of weight on bit, rotary rpm (revolutions per minute), cost, drilling speed, and torque. Further, the excavation speed includes an instantaneous excavation speed (ROP) and an average excavation speed (ROP-AVG).
Bit selection / recommendation
Further, the display 200 provides a means for generating a display 268 for details of suggested or recommended drilling equipment. That is, details of the proposed or recommended drilling equipment are displayed on the display 200 in addition to the geological features 202 and the predicted drilling mechanics 204. The proposed or recommended drilling facility preferably includes at least one bit that is used to predict the performance of the drilling system. Furthermore, it is recommended that the first and second bit selections, indicated by reference numbers 270 and 272, respectively, be used with the expected performance for drilling holes. The first and second bit selections are identified by first and second identifiers 276 and 278, respectively. The first and second identifiers 276 and 278 are also displayed in addition to the geological features 202 and the predicted drilling mechanics 204, respectively, where the first and second identifiers are positioned on the display 200. Are selected to match the portion of expected performance to which the first and second bit selections apply, respectively. Furthermore, the display may include an illustration of each recommended bit selection and corresponding bit specification.
Broken line
Still referring to FIG. 6, the display 200 further includes a bit selection change indicator 280. A bit selection change indicator 280 is provided to indicate that a change in bit selection from the first recommended bit selection 270 to the second recommended bit selection 272 is required at a predetermined depth. The The bit selection change indicator 280 is preferably displayed on the display 200 in addition to the geological features 202 and the predicted drilling mechanics 204.
[0074]
Thus, the method and apparatus of the present disclosure advantageously allows an optimization of the drilling system and its use within the drilling program to be obtained early within the drilling program. Further, the method and apparatus facilitates appropriate improvements early in the drilling program. Any economic benefits resulting from improvements made early in the drilling program are multiplied by the number of remaining drill holes drilled in the drilling program to yield a benefit. Significant and substantial savings are advantageously achieved for companies that delegate drilling programs. In addition, measurements are made during drilling of each drill hole throughout the drilling program by the method and apparatus of the present invention to verify that a particular drilling system facility has been optimized and used. In addition, the performance of the drilling system equipment can be more easily monitored using the disclosed method and apparatus, and also monitored to identify them before potential adverse conditions actually occur. Can be done.
[0075]
Furthermore, the use of the present method and apparatus advantageously reduces the time required to obtain a successful drilling operation in which a given oil producing drill hole is brought online among a plurality of wells. As described above, the method and apparatus of the present disclosure increase work efficiency. Furthermore, the use of the method and apparatus is particularly advantageous for development projects, for example, establishing 100 wells over a three year period at a given geographical location. With this method and apparatus, for example, the previous method can be used for 60 days (or more), but in about 30 days, a predetermined well can be completed and put on the line. It can be made a product with. Increasing the efficiency of the drilling system's drilling performance in accordance with the present disclosure allows for a time gain related to oil production, further transforming into millions of dollars of petroleum products that can be marketed earlier. . Alternatively, using the present method and apparatus, one or more additional wells can be completed in a given period, in excess of the number of wells that would be completed using previous methods in the same period. . In other words, drilling a new well in less time is advantageously converted into a marketable product earlier.
[0076]
This embodiment provides an evaluation of the various proposed drilling equipment, as well as the use of the drilling program, before and during the actual drilling of drill holes in a given formation. The selection and usage of drilling equipment can be optimized for a specific section or sections of drill holes (or sections) within a given formation. The drilling mechanics model benefits by taking into account the effects of progressive bit wear due to rock changes. The recommended operating parameters reflect the wear conditions of the bit at the particular rock mass and also take into account the operational constraints of the particular drilling device used. The geological features per unit depth for a given formation and the printout or display of the predicted drilling mechanics are very useful for drilling operators, especially for optimizing the drilling process of the drilling program Provide important information. The printout or display further advantageously provides a head-up view of expected drilling conditions and recommended operating parameters.
[0077]
This embodiment provides a lot of complex critical information to be communicated in a clear manner, for example in the form of a graph as illustrated and described herein with reference to FIG. In addition, the use of colors in the form of the graph emphasizes important information. Furthermore, the display 200 advantageously provides a perforator roadmap. For example, having the display as a guide helps the puncher decide when to pull a given bit. The display further provides information regarding the impact of operational constraints on performance and drilling mechanics. Furthermore, the display assists in selecting recommended operating parameters. By using the display, more efficient and safe drilling can be obtained. The most useful thing is that important information is clearly communicated.
Real-time aspect
According to another embodiment of the present disclosure, the apparatus 50 (FIG. 1) includes real-time aspects as described above in the text and further described below. In particular, the computer controller 52 is responsive to a predicted drilling mechanics output signal for controlling control parameters when drilling a drill hole in a drilling system. The control parameters include at least one of the parameters consisting of weight on bit, rpm, pump flow rate, and water pressure. Further, as described herein, the controller 52, the logging instrument 16, the measurement device processor 44, and other suitable devices are used to obtain at least one measurement parameter in real time during drilling of a drill hole. used.
[0078]
The computer controller 52 further includes means for historically comparing the back-calculated value of the measurement parameter with the measurement parameter. In particular, the back-calculated value of the measurement parameter is a function of the drilling mechanics model and at least one control parameter. In response to the defined deviation between the measured parameter and the back-calculated value of the measured parameter, the controller 52 performs the following steps: a) adjusting the drilling mechanics model; b) modifying the control of the control parameter; Alternatively, at least one of c) performing a warning operation is performed.
[0079]
According to another embodiment of the present disclosure, a method and apparatus for predicting the performance of a drilling system is a means for measuring defined real-time drilling parameters during drilling of a drill hole in a given formation. including. Drilling parameters can be obtained during drilling of a drill hole using a commercially available measuring device (such as an MWD device) suitable for obtaining predetermined real-time parameters. Furthermore, the drilling system apparatus operates in a defined real-time mode for comparing predetermined real-time drilling parameters with corresponding predicted parameters. Thus, the present embodiment facilitates one or more modes of operation, either alone or in combination, in a one-time, repeated, or periodic manner. The operation modes include, for example, a prediction mode, a calibration mode, an optimization mode, and a real-time control mode.
[0080]
In yet another embodiment of the present disclosure, the computer controller 52 is programmed to perform real-time functions as described herein using programming techniques well known in the art. Computer readable media, such as computer disks or other media for transmitting computer readable code (global computer networks, satellite communications, etc.), including Has a computer program stored on top. The computer program for execution by the computer controller 52 is similar to that originally disclosed and has the capability of additional real-time capabilities.
[0081]
With respect to real-time capability, the computer program includes instructions for controlling control parameters in drilling a drill hole in the drilling system in response to an expected drilling mechanics output signal, and the control parameter is a bit It includes at least one selected from the group consisting of upper weight, rpm, pump flow rate, and water pressure. The computer program also includes instructions for obtaining measurement parameters in real time during drilling of the drill hole. Finally, the computer program includes instructions for historical verification of the measured parameter and the back calculated value of the measured parameter, where the back calculated value of the measured parameter includes the drilling mechanics model and at least one control. At least one function selected from the group consisting of parameters. Further, the instructions for controlling the control parameter include: a) adjusting the drilling mechanics model according to a prescribed deviation between the measurement parameter and the back-calculated value of the measurement parameter; b) controlling the control parameter. Instructions for performing at least one of the step of modifying, or c) performing the warning operation.
[0082]
In one embodiment of a drilling prediction analysis system, the system looks at the actual data accumulated during drilling of the drill hole and compares the actual data with the prediction made at the corresponding planning stage. Thus, history matching is executed. Depending on the results of historical matching, some factors (eg, basic assumptions) of the drilling mechanics prediction model need to be adjusted to better match the predicted performance with the actual performance. These adjustments can be attributed to the various factors associated with the geological environment specific to a particular geographic region and how that environment interfaces with a particular bit design.
[0083]
As mentioned, the real-time aspect of the present embodiment includes performing a comparison of predicted performance with actual parameters while the drill hole is drilled. By having a real-time aspect, this embodiment can only be applied to the drill hole that follows, with one drawback of end-of-job analysis, namely end-of-job analysis. Overcoming the drawbacks. In contrast, having the real-time aspects of this embodiment allows any adjustments required for drilling mechanics prediction models (applicable to drilled drill holes) to be made and specified. Other adjustments can be made that are better suited to better optimize the drilling process for the other drill holes. Further, the real-time aspect accelerates the learning curve for the drill hole (s) at a given site and the optimization process corresponding to each drill hole. Furthermore, as will be explained later in the text, all of these advantages do not depend on using bits as a measurement tool.
Real-time optimization
Referring now to FIG. 7, a display 300 for the predictive performance of a drilling system for a given formation, according to an embodiment of the present disclosure, and the drilling prediction analysis and control system 50 of FIG. Shown in relation. Display 300 includes a plot of data against depth, which includes depth 302, log data 304, rock mass 306, porosity 308, rock strength 310, bit wear 312, and operational parameters 314. The data displayed for each respective plot is obtained as explained earlier in the text with respect to FIGS. 1-6 and as explained later.
[0084]
The first region 316 of the display 300 is characterized by information and data relating to each depth above the depth position of the MWD sensor. Such information in the first region 316 is considered to be accurate essentially as if the data was collected and analyzed after the work was completed. Thus, the data in the first region 316 usually looks like a “calibration mode” for end-of-jobs. The solid line 318 in the operational parameter column 314 shows the actual ROP, and the dashed line 320 shows the ROP from the rock strength 310 where the prediction model was logged using the actual drilling parameters (eg, WOB 322 and RPM 324). Represents what had been predicted.
[0085]
In “end-of-job” mode, the drilling prediction analysis and control system evaluates the accuracy of the prediction model for a given drill hole and makes adjustments to subsequent drill holes in a particular site or area as needed. Therefore, the predicted ROP is compared with the actual ROP. Because it is a real-time (RT) job, drilling prediction analysis and control system 50 (FIG. 1) until close history matching is achieved and indicates that the prediction model is working well within a given environment. However, adjustments are made during the initial drilling stage for bits operating within a given drill hole. Therefore, the drilling prediction analysis and control system is in a position to successfully predict future ROPs, assuming good offset information. A better predicted future ROP will help the drilling prediction analysis and control system determine when the bit will be sharp and should be pulled in subsequent drill holes at a particular site be able to.
Bit as a measurement tool
The following example deals with the back calculation of rock strength, but it is possible to do back calculation for different parameters as disclosed herein. Referring back to FIG. 7, the second region 326 is characterized by information and data corresponding to respective depths in the area between the bit and the MWD sensor. Since drilling parameter data (eg WOB, RPM, and ROP) can be measured almost instantaneously, their data at bit depth is known. The drilling prediction analysis and control system 50 (FIG. 1) obtains a good ROP history match in the region 316 above the MWD sensor. Thus, the drilling prediction analysis and control system 50 can back-calculate any “suggested” measurement parameters from the actual drilling parameters at the given depth (s) and the resulting ROP.
[0086]
A “suggested” parameter is the parameter (s) that occur in region 326, which is the interval between the depth corresponding to the bit and the depth corresponding to the MWD sensor, and therefore the measurement device is given a The “suggested” parameter cannot be calculated from the measured data since it has not yet been crossed within that time. After the associated MWD sensor data is available, the drilling prediction analysis and control system 50 can determine the rock quality and rock strength parameters therefrom. Thus, for example, the drilling prediction analysis and control system 50 can compare the rock strength calculated in the log with the “suggested” rock strength. In FIG. 7, the rock strength calculated in the log is illustrated as a solid line 328. Also, the “suggested” rock strength is illustrated as a dotted line 330.
[0087]
The following description describes how the drilling prediction analysis and control system 50 utilizes the techniques described above for determining “implied” parameters. If a “bit” measurement begins to deviate from a “verification” measurement, the drilling prediction analysis and control system suggests that something went wrong in the downhaul. The bit was broken or balled up, there was a problem with the well cleaning efficiency, the drilling efficiency was changed, etc. For example, the drilling prediction analysis and control system 50 may perform some other calculation until the corresponding actually measured parameter value can be derived from the log data, as available in region 316. In contrast, suggested parameter values will be used.
[0088]
If good offset data is available, the drill prediction analysis and control system 50 can rely on it to facilitate optimization of the drill hole being drilled. However, when drilling a well that has no offset information, the drilling prediction analysis and control system uses the “suggested” data from the drilling drill hole to optimize the drill hole.
[0089]
In other words, the back-calculated measurement parameter value is history-checked or compared with the measurement parameter value. In the first example, the back-calculated measurement parameter corresponds to the value of the first segment (such as region 316 in FIG. 7) of the drill hole above the level of the MWD sensor. The drilling prediction analysis and control system performs a history matching on the value back-calculated in this first interval. One reason for performing history matching in this first interval is for the drilling prediction analysis and control system to determine whether the drilling mechanics model (s) are operating properly.
[0090]
In the first interval, for any deviation greater than the specified amount in the historical matching comparison, the drilling analysis and control system will make appropriate adjustments to the drilling mechanics model for generating the predicted drilling mechanics. Do. In particular, until an acceptable level of deviation is achieved (that is, until the historical matching deviation between the measured parameter and the back-calculated value of the measured parameter is within the acceptable level of deviation), the drilling prediction analysis and control system respectively Adjust the assumptions underlying the model.
[0091]
Further, with respect to the first segment, by making appropriate adjustments to one or more respective drilling mechanics models, the drilling analysis and control system allows the drilling mechanics to drill further drill holes. Improve the corresponding prediction of. In other words, the drilling analysis and control system fine tunes the drilling mechanics model during the drilling process. In response, the drilling system modifies the control of one or more control parameters based on the fine-tuned drilling mechanics model. Fine tuning helps to optimize drilling parameters as drill hole drilling advances.
[0092]
In the second example, within the second section of the drill hole between the MWD measurement device (such as region 326 in FIG. 7) and the drill bit, the drilling prediction analysis and control system In a slightly different way, a historical verification of the measured parameter and the back-calculated value of the measured parameter is used. One reason for performing history matching in this second interval is to allow the drilling prediction analysis and control system to see the state of the bits and how they interact with the formation. Because.
[0093]
If the history verification reveals that there is a deviation within the second interval that is greater than the specified limit, the history matching deviation is a potential problem in drilling the drill hole by the drilling system (eg, bit In). Rather, deviations in the historical verification within the tolerance range indicate that the drill hole has been drilled by the drilling system as expected. Regarding the back calculation value of the measurement parameter in the second section, the back calculation value is suggested by the actual parameter (geological value is lacking) when drilling a drill hole for each section.
[0094]
Real-time functions as described herein provide a powerful addition to the capabilities of drilling prediction analysis and control systems.
Accordingly, the drilling system method and apparatus of the present disclosure operates in a defined manner to achieve a prediction mode followed by a drilling mode. Comparison of the parameters obtained in the prediction mode with the parameters obtained in the drilling mode provides valuable insights about making a correction (or) adjustment for a given drillhole or subsequent drillhole prediction model and drilling. provide. Drilling system methods and apparatus also examine real-time parameters in light of predicted parameters per unit depth (eg, predicted rock strength) and (for example, for basic assumptions used in drilling mechanics models). ) Perform perforation optimization by making appropriate adjustments.
[0095]
The drilling prediction device can be placed at a different location from the actual drilling site. That is, the predictor is at a remote location and can interface with the actual drilling site via a global communications network such as the Internet or the like. The predictor may also be in a real-time operations center (ROC), where the ROC has a drilling site and a satellite link or other suitable communication link to the drilling device.
[0096]
This embodiment also facilitates the use of a defined bit as a measuring device while drilling a drill hole. Along with the formation changes during drill hole drilling, such as the occurrence of rock compressive strength changes, corresponding changes occur in the bit response during drill hole drilling. For example, changes in the formation may cause the bit to become unbalanced, vibrate, or undergo other similar changes. The drilling system apparatus monitors such changes in bit performance using an appropriate measurement device. For example, one way to monitor bit performance is through an appropriate sensor on the bit.
[0097]
The bit sensor can also provide a means for mapping predetermined parameters of the borehole. For example, during drilling of a drill hole, the drilling system apparatus can compare the measured (or actual) rock quality with a bit as a function of the measurement parameter to the predicted rock quality. Any suitable sensor placed in the bit or closest to the bit along the drill string may be used.
[0098]
The drilling system apparatus also includes a typical inter-drilling measurement (MWD) sensor where the drilling sensor is placed on the drill string behind the bit. For example, the MWD sensor is about 50-100 feet away from the bit. As a result, the measurements made by the MWD sensor proceed behind the bit, in real time, during drill hole drilling. With respect to bit wear parameters, the method of the present embodiment includes the steps of drilling a drill hole and predicting bit wear parameters and back-calculated bit wear parameters (as determined from MWD measurements) while drilling. Comparing. In addition, the method is such that the measured bit wear is periodically updated in relation to the predicted wear and appropriate adjustments are recommended (or) to achieve the best overall drilling performance. This includes strengthening the bit wear state. In other words, the predicted wear performance can be compared to a real time measured parameter representing the measured bit wear performance.
[0099]
This example further facilitates “real-time” optimization and calibration on the same day, as compared to post-optimization and calibration for about a week or more. Real-time optimization and calibration advantageously provides a positive effect on bit drilling performance during drill hole drilling. Thus, the drilling system and method of this embodiment can be used to adjust the parameters appropriately to better fit the real world scenario based on the predicted drilling parameters and the actual results compared to the drilling parameters (or historical matching). Promote.
[0100]
If the difference between the actual parameter and the predicted parameter is not covered (i.e. exceeds the specified maximum amount), the drilling system method and apparatus of this example operates accordingly according to the specified reaction. For example, in response to assessing that there is any deviation in the history verification that exceeds a predetermined limit, the drilling system and method may use various parameters as a function of the results of a comparison of predicted drilling performance with actual ones. Adjust. A comparison of the predicted drilling parameters with actual ones may indicate that there is an adverse or undesirable bit wear. Further assessment can also indicate whether the deviation is due to bit wear or some other adverse condition.
[0101]
In a typical scenario, the drilling system operates between an automatic drilling control mode and a manual control mode. In response to differences in history matching that exceed specified limits, embodiments of the present disclosure can perform alert operations. The alert operation includes the step of providing an indication that something is wrong and needs attention. The system and method also stops the automatic drilling control mode and puts itself in the manual control mode until the corresponding differences are resolved.
[0102]
The drilling system apparatus and method can also perform alert operations including appropriate alarm indicators such as color-coded indicators or other suitable indicators suitable for a given display and / or field application. In a given warning operation, the prescribed information held on the display may be highlighted or moved in a manner that draws attention to the corresponding information.
[0103]
A red indicator may be provided, for example, to indicate the possibility of an early bit failure. Such an initial bit failure may be caused when the difference between the predicted parameter and the actual parameter is greater than the specified maximum difference. A yellow indicator may indicate a warning condition, where the difference between the predicted and actual parameters is greater than the specified minimum difference but less than the maximum difference. Finally, the green indicator may indicate an overall acceptable state, where the difference between the predicted and actual parameters is less than the specified minimum difference. In later examples, the difference between expected and actual is as planned and the drilling can proceed relatively undisturbed.
[0104]
This embodiment provides an alarm or initial warning form as appropriate. Thus, a real time decision to adjust or not adjust can be made in a more informed manner than previously possible. Furthermore, the present embodiment provides real-time observation of drill hole drilling, for example using a display.
[0105]
To further explain the difference between the actual and predicted performance of a drill bit drilling a drill hole, it is noted that the bit is initially in the borehole prior to the logging tool. Real-time parameters in bits are ahead of the logging tool by a predetermined amount. The real-time parameters at the bit are preceded in terms of time and distance, such time and distance being the corresponding distance at which the logging tool is located along the drill string away from the bit. Is equivalent to the time required for the logging tool to pass. In connection with a suitable drilling mechanics model, specific measurements such as the compressive strength of the rock drilled by the bit can be suggested with these real-time parameters. Other typical real-time parameters at the bit include WOB, RPM and torque.
[0106]
Along with real-time parameters and measurement information, the drilling system device drills (such as an MWD facility) to verify what the bits suggested, that is, what was suggested was actually there. Use a measuring instrument that logs well. The MWD logging tool can be used to continuously verify what the bits suggest, as given by the predicted parameters and actual performance. For example, if the logging tool senses a parameter proportional to rock strength, the parameter information is sent to the drilling system prediction and analysis device for processing. The prediction and analysis device processes the pressure information by creating an indication of the true state of the rock being drilled. If the real condition of the rock is as expected, the drilling process is allowed to proceed. If not as expected, the drilling process is changed or modified as appropriate. Thus, the drilling prediction and analysis system can control drilling of drill holes in a defined manner. One defined manner includes an alternation between an automatic drilling control mode and a manual drilling control mode.
[0107]
Another typical MWD tool includes a bit vibration measurement tool. Based on the vibration data, the drilling prediction and analysis system determines whether a given bit has suffered bit damage in a downhole. An inflection point in the vibration measurement tool output data indicates that the vibration level needs to be calibrated or updated. Using bit parameter optimization based on vibration data, the drilling prediction and analysis system can determine how much force a given bit can withstand without causing significant or catastrophic damage. judge. Such analysis may include the use of performance data derived from previous bit vibration / performance considerations. As described herein, the drilling prediction and analysis system includes at least one computer readable medium having suitable program code for performing the functions as described herein.
[0108]
The present invention also relates to the diagnosis of borehole stability relationships. With appropriate depiction, borehole mapping can be performed to analyze any cracks in a given formation. The placement of cracks in the formation can affect the possibility of drilling. Rupture or crack mapping provides some indication as to the extent to which the rock is damaged. Rupture indicates the presence of a rapid decline in rock strength.
[0109]
It is also important to take care to minimize errors. There are many unknowns. If there is no direct quantization, it is not correct to distribute the error to a cause. This is related to the difference between estimation and measurement. A variety of log data can be sent to the ground using an appropriate device that measures while drilling. However, while there are many measurements in the downhole, only selected ones can be sent to the surface. Such limitations are mainly due to the fact that current technology cannot immediately transmit all possible measurements to the surface.
[0110]
The drilling system apparatus and method of this embodiment also utilizes a bit as a measurement tool. For example, the harmonics of bit vibrations make it possible to use the bit as a measurement tool. It can be seen that the vibration data is useful for calibration purposes. In one example of drilling a drill hole, bits can be specified to take into account available data relating to a particular rock mass and for specifying various parameters of WOB, torque and ROP. . The method includes drilling a drill hole and monitoring ROP, observing rock quality, and determining WOB as part of the process. In this example, the bit is the first measurement device to start predicting what is being drilled, and various logging tools verify the bit measurements.
[0111]
The method and system apparatus further includes back-calculation of the parameters, thus superimposing the back-calculated parameters on the predicted parameters and evaluating what is actually happening. The method and system apparatus then makes fine adjustments and / or appropriate adjustments in response to determining what is actually happening to the bits. Therefore, if a bit is used as a measurement tool, advance notification (in stages) of about 50 to 100 feet for analyzing and inspecting what is happening to the bit in a downhole is possible.
[0112]
In addition, using the bit as a measurement tool can analyze whether the bit is still active (ie, drilling can continue), or other appropriate evaluation. For example, a bit measurement can indicate that something unexpected has happened to the bit. The MWD sensor on the drill string can verify what the bit measurement indicated. Was the MWD sensor faster or slower than expected? What are the appropriate actions to take? Is there a disability? By using the bit as a sensor, the prediction and analysis system can observe (or) measure vibration to indicate whether the bit is functioning as expected. Thus, the prediction and analysis system can update the recommended drilling parameters based on what is observed using bits as a measurement tool. The prediction and analysis device can use the bit as a measurement tool and adjust the parameters where the drilling device is expected to be for look-ahead applications (eg looking one bit ahead of the bit). .
[0113]
By using the bit as a measurement tool, the prediction and analysis system can analyze and examine rock anisotropy, directional properties, compressive strength, and / or porosity. For horizontal drill holes, the drill needs to travel at an angle of 90 degrees from the vertical plane. The porosity is the same even if the relative tilt angle changes.
[0114]
In history verification mode or optimization mode, the MWD sensor is 50-100 feet behind the bit, is at the bit, or is measuring in front of the bit. In one mode of operation, the system generates a proposal and uses the proposal while drilling a drill hole. For example, the proposal may include rock quality per unit depth and predicted rock strength. During drilling, the system back-calculates the rock strength at a given depth, and then the back-calculated measure of that rock strength crosses the corresponding boundary line (ie passes through the formation) Compare with the information made available by. The system then performs a historical match with the predicted rock strength and the actual rock strength. Following history matching, the system makes appropriate parameter adjustment (s).
[0115]
The system performs a historical match to verify or determine that the drilling system is responding as expected to respond with a bit. The system further operates in a real-time mode that utilizes display mechanics and back-calculated (predicted) effective rock strength. As the sensor passes near a predetermined depth, the system calculates a compression rock strength (or porosity) parameter. A mud logger is used with a contrast between the measured rock strength and the predicted rock strength calibration, where the mud logger is properly calibrated prior to use.
[0116]
As described herein, the drilling prediction analysis and control system utilizes data that is close to bits. Therefore, the system and method make any previous uncertainty much smaller. This is an advance regarding drill hole drilling. Based on experience, it is common for unexpected geological scenarios to occur in offset wells.
[0117]
According to this embodiment, the real time may be characterized by the loss of time between the time when the data is acquired downhole and the time when the data is available to the drilling operator at a given moment. it can. That is, how long does it take for the drilling operator to obtain data (2 weeks versus 1 day). The real-time aspect of the drilling prediction analysis and control system allows the system to determine what a bit is doing in a short time and what needs to be adjusted, modified WOB , RPM, or other suitable operating parameters in real time.
[0118]
With respect to bit wear, the drilling analysis and control system includes a bit wear indicator. Bit wear indicators are characterized in that when the bit wears, different signs or acoustic signals are generated for different states of bit wear. The system also includes the ability to measure a sine or acoustic signal to determine a bit wear condition measurement via a suitable measurement device.
[0119]
As described herein, the operational parameters include at least one predicted RPM, WOB, cost, ROP, and ROP-AVG. These predicted operational parameters are displayed in the drilling prediction analysis and control system 50 display output of FIG. The measurement parameters can include any parameters related to drilling a drill hole that are measured in real time or obtained (eg, by appropriate calculations). The measurement parameter can include one or more operational parameters. Control parameters include any parameters that are assumed to be modified or controlled, either manually or via automatic control, to affect or change drill hole drilling. be able to. For example, the control parameters include one or more operational parameters that are subject to direct (or indirect) control.
[0120]
Although only a few exemplary embodiments of the present invention have been described in detail above, those skilled in the art will depart significantly from the novel teachings and advantages of the present invention in the exemplary embodiments. It will be readily appreciated that many modifications are possible without. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims. In the claims, means and function clauses are intended to cover not only the structures described herein as performing the recited functions, but also structural equivalents, as well as equivalent structures. The
[Brief description of the drawings]
FIG. 1 illustrates a drilling system including an apparatus for predicting the performance of a drilling system for drilling drill hole (s) according to a defined drilling program in a given formation.
FIG. 2 is a drilling system for drilling drill hole (s) and a method for optimizing its use according to a defined drilling program in a given formation, further comprising a drilling system; 1 illustrates a method that also includes prediction of performance of
FIG. 3 shows a geological model and a drilling mechanics model for use in embodiments of the method and apparatus for predicting drilling performance of the present disclosure.
FIG. 4 illustrates one example of displaying predicted performance for a drilling system for a given formation in accordance with the disclosed method and apparatus.
FIG. 5 illustrates one example of displaying predicted performance for a drilling system for a given formation in accordance with the disclosed method and apparatus.
FIG. 6 illustrates one example of displaying predicted performance for a drilling system for a given formation in accordance with the disclosed method and apparatus.
FIG. 7 illustrates an example of an exemplary display for parameters and real-time aspects of the drilling prediction analysis and control system of the present disclosure.
[Explanation of symbols]
12 Drilling device
14 Borehole
16 Logging tool
18 sub
20 Drill string
22 Drill bit
24 strata
26 Drilling mud water
28 Mud pool
30 wellhead
32 Annular space
34 Metal casing
36 side wall
38 Pump system
40 Mud supply pipeline
42 Fluid discharge duct
70 Downhole motor
72 Top drive motor
74 Rotary table motor

Claims (50)

An apparatus for predicting the performance of a drilling system for drilling a drill hole in a given formation,
Means for generating geological features of the formation per unit depth according to a defined geological model and outputting a signal representative of the geological features, wherein the geological features include at least rock strength;
Means for inputting specifications of a proposed drilling facility for use in drilling a drill hole, wherein said specifications include at least one bit specification of recommended drill bits;
According to the drilling mechanics model, the predicted drilling mechanics are determined according to the proposed drilling equipment specifications as a function of geological features per unit depth, and a signal representing the predicted drilling mechanics is output. Means for performing said predicted drilling mechanics comprising at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operational parameters;
Means responsive to predicted drilling mechanics output signal for controlling control parameters when drilling a drill hole in a drilling system, wherein the control parameters are derived from weight on bit, rpm, pump flow rate, and water pressure. Means comprising at least one selected from the group consisting of:
Means for obtaining measurement parameters in real time during drilling of the drill hole;
Means for historical verification of the measured parameter with a back-calculated value of the measured parameter, wherein the back-calculated value of the measured parameter is a function of a drilling mechanics model and at least one control parameter, and the measured parameter and the In response to a defined deviation from the back-calculated value of the measured parameter, the control means a) adjust the drilling mechanics model, b) modify the control parameter control, and c) a warning operation. Performing at least one selected from the group consisting of:
The apparatus characterized by including. The apparatus of claim 1, further comprising:
An apparatus comprising: a means for responding to the geological feature output signal and the predicted drilling mechanics output signal to generate a display of the geological features per unit depth and the predicted drilling mechanics. 3. The apparatus of claim 2, wherein the means for generating the display includes at least one selected from the group consisting of: a) a display monitor, and b) a printer, and the geological features per unit depth and Apparatus, wherein the predicted drilling mechanics indication includes a printout. The apparatus of claim 1, wherein the means for generating geological features further generates at least one additional feature selected from the group consisting of log data, rock quality, porosity, and shale plasticity. A device characterized by. The apparatus of claim 1, wherein said means for inputting specifications of said proposed drilling facility is further selected from the group consisting of a downhole motor, a top drive motor, a rotary table motor, a mud system, and a mud pump. Input an additional specification of at least one proposed drilling facility to be performed. The apparatus of claim 1, wherein the operational parameters include at least one selected from the group consisting of weight on bit, rotary rpm (revolutions per minute), cost, drilling speed, and torque. Equipment. 7. The apparatus according to claim 6, wherein the drilling speed further includes an instantaneous drilling speed (ROP) and an average drilling speed (ROP-AVG). The apparatus of claim 2.
The display of geological features includes at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display;
The apparatus wherein the predicted drilling mechanics display includes at least one graphical display selected from the group consisting of a curve display, a percentage graph representation, and a band display. 9. The apparatus of claim 8, wherein the means for generating the display includes at least one selected from the group consisting of a) a display monitor and b) a printer, and the geological features per unit depth and predicted. An apparatus wherein the perforation mechanics display includes a printout. 9. The apparatus of claim 8, further comprising color-coded at least one graphical representation of the geological feature and at least one graphical representation of the predicted drilling mechanics. 9. The apparatus of claim 8, wherein the rock strength is expressed in at least one display format selected from the group consisting of a curve display, a percentage graph display, and a band display.
The curve representation of rock strength includes confined rock strength and unconfined rock strength, and the area between each curve of confined rock strength and unconfined rock strength is graphically illustrated as a result of confinement stress. Represents an increase in rock strength,
The band representation of rock strength provides a graphical illustration showing a discrete range of rock strength at a given depth, and the band representation of rock strength is coded to represent a soft rock strength range An apparatus comprising: a first cord; a second cord representing a hard rock strength range; and an additional cord representing one or more neutral rock strength ranges. 9. The apparatus of claim 8, wherein the means for generating geological features further generates at least one additional feature selected from the group consisting of log data, rock quality, porosity, and shale plasticity;
The apparatus is characterized in that the operating parameters include at least one selected from the group consisting of weight on bit, bit rpm (revolutions per minute), cost, drilling speed, and torque. The apparatus of claim 12.
Log data is represented in the form of a curvilinear display, and the log data includes any log suite that is sensitive to rock quality and porosity;
The rock quality is expressed in the form of a percentage graph for use in identifying different types of rocks within a given formation, said percentage graph showing the percentage of each type of rock at a given depth;
The porosity is expressed in the form of a curve display,
Shale plasticity is represented in at least one display format selected from the group consisting of a curve display, a percentage graph display, and a band display;
The curve representation of shale plasticity includes a curve of at least one shale plasticity parameter selected from the group consisting of moisture content, clay type, and clay volume, and the shale plasticity is hydrated according to a defined shale plasticity model. Determined from rate, clay type and clay volume, and
The band representation of the shale plastic provides a graphical illustration showing a discrete range of shale plasticity at a given depth, and further, the band representation of the shale plastic is coded to provide low shale plasticity An apparatus comprising: a first code representing a range; a second code representing a high shale plastic range; and an additional code representing one or more neutral shale plastic ranges. 9. The apparatus of claim 8, wherein bit wear is determined as a function of cumulative work done according to a defined bit wear model and is in at least one display format selected from the group consisting of a curve display and a percentage graph display. Expressed,
The curve representation of bit wear can include bit work expressed as specific energy level at the bit, cumulative work done by the bit, and voluntary work loss due to polishing,
The percentage graph display indicates a bit wear condition at a predetermined depth, and the bit wear percentage graph is encoded, a first code representing an expired bit life, and a second code representing a remaining bit life. The apparatus characterized by including. 9. The apparatus of claim 8, wherein the bit mechanical efficiency is determined as a function of torque / bit weight signature for a given bit according to a defined mechanical efficiency model and is selected from the group consisting of a curve display and a percentage graph display. Represented in at least one display format,
The curve representation of bit mechanical efficiency includes the total torque and cutting torque at the bit,
The percentage graph representation of bit mechanical efficiency graphically illustrates total torque, the total torque includes cutting torque and friction torque components, and the percentage graph of bit mechanical efficiency is encoded, An apparatus comprising: a first code representative of a cutting torque; a second code representative of a friction unrestricted torque; and a third code representative of a friction limited torque. 16. The apparatus of claim 15, wherein the mechanical efficiency is further represented in the form of a percentage graph illustrating the drilling system operating constraints that adversely affect the mechanical efficiency, wherein the drilling system operating constraints are a friction limited torque. The percentage graph further shows the corresponding impact percentage that each constraint exerts on the torque component with limited friction of mechanical efficiency at a given depth;
Drilling system operational constraints include maximum torque on bit (TOB), maximum weight on bit (WOB), minimum and maximum bits per minute (RPM), maximum drilling speed (ROP), those Any combination and unrestricted states can be included, and the percentage graph display for drilling system operational constraints related to mechanical efficiency is coded and includes different codes to identify different constraints A device characterized by. 9. The apparatus of claim 8, wherein the output is represented in at least one display format selected from the group consisting of a curve display and a percentage graph display.
The curve display for output includes an output limit and an operation output level, the output limit corresponds to a maximum output to be applied to the bit, and the operation output level is a limited operation output level, a recommended operation Including at least one selected from the group consisting of an output level and a predicted operational output level;
The percentage graph display of output illustrates drilling system operational constraints that adversely affect the output, the drilling system operational constraints correspond to constraints that result in output loss, and the percentage graph of the output constraint is In addition, each constraint shows the percentage of the corresponding impact on the output at a given depth, and the percentage graph display of drilling system operational constraints on output is coded to identify different constraints A device comprising different codes. The apparatus of claim 2, further comprising:
In addition to geological features and predicted drilling mechanics, means for generating a display of details of the proposed drilling facility, wherein the proposed drilling facility is used to predict the performance of the drilling system. Means comprising at least one recommended bit selection to be used. 19. The apparatus of claim 18, wherein first and second bit selections are recommended to be used with the expected performance for drilling holes, and wherein the first and second bit selections are first respectively. Wherein the first and second identifiers are displayed with geological features and predicted drilling mechanics, and the positioning of the first and second identifiers on the display. Is selected to match the portion of expected performance to which each of the first and second bit selections applies. The apparatus of claim 2, further comprising:
On the display of geological features and predicted drilling mechanics that a bit selection change from the first recommended bit selection to the second recommended bit selection is required at a given depth And a bit selection change indicator for indicating. In a method for predicting the performance of a drilling system for drilling a drill hole in a given formation,
Generating a geological feature of a formation per unit depth according to a defined geological model and outputting a signal representative of the geological feature, wherein the geological feature includes at least rock strength;
Obtaining a specification of a proposed drilling facility for use in drilling a drill hole, the specification including a bit specification of at least one of the recommended drill bits;
According to the drilling mechanics model, the predicted drilling mechanics are determined according to the specifications of the proposed drilling facility as a function of geological features per unit depth and a signal representing the predicted drilling mechanics is output And wherein the predicted drilling mechanics includes at least one selected from the group consisting of bit wear, mechanical efficiency, power, and operational parameters;
In response to the predicted drilling mechanics output signal, controlling a control parameter when drilling a drill hole in the drilling system, the control parameter comprising: weight on bit, rpm, pump flow rate, and water pressure Including at least one selected from a group;
Obtaining measurement parameters in real time during drill hole drilling;
History-checking the measurement parameter with a back-calculated value of the measurement parameter, wherein the back-calculated value of the measurement parameter is at least one function selected from the group consisting of a drilling mechanics model and at least one control parameter And the controlling step further comprises: a) adjusting the drilling mechanics model, and b) controlling the control parameter according to a defined deviation between the measurement parameter and the back-calculated value of the measurement parameter. A step for performing at least one selected from the group consisting of: a step of modifying; and c) performing a warning operation;
A method comprising the steps of: The method of claim 21, further comprising:
Generating a geological feature per unit depth and an indication of the predicted drilling mechanics in response to the output signal of the geological features and the output signal of the predicted drilling mechanics. . 23. The method of claim 22, wherein generating the display includes using at least one selected from the group consisting of a) a display monitor, and b) a printer, and geology per unit depth. The method wherein the display of the feature and predicted drilling mechanics includes a printout. 23. The method of claim 21, wherein generating the geological feature includes generating at least one additional feature selected from the group consisting of log data, rock quality, porosity, and shale plasticity. A method characterized by that. 24. The method of claim 21, wherein obtaining the proposed drilling facility input specification is further selected from the group consisting of a downhole motor, a top drive motor, a rotary table motor, a mud system, and a mud pump. Obtaining an additional specification of the at least one proposed drilling facility. The method of claim 21, wherein the operational parameters include at least one selected from the group consisting of weight on bit, bit rpm (revolutions per minute), cost, drilling speed, and torque. And how to. 27. The method of claim 26, wherein the drilling speed further comprises an instantaneous drilling speed (ROP) and an average drilling speed (ROP-AVG). The method of claim 22, wherein displaying the geological feature comprises displaying at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display.
The method of displaying the predicted drilling mechanics includes displaying at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display. 29. The method of claim 28, wherein generating the display includes using at least one selected from the group consisting of a) a display monitor and b) a printer, and geological per unit depth. A method wherein the display of features and predicted drilling mechanics includes a printout. 30. The method of claim 28, further comprising color-coding at least one graphical representation of the geological feature and at least one graphical representation of the predicted drilling mechanics. 29. The method of claim 28, wherein the rock strength is represented in at least one display format selected from the group consisting of a curve display, a percentage graph display, and a band display.
The curve representation of rock strength includes confined rock strength and unconfined rock strength, and the area between each curve of confined rock strength and unconfined rock strength is graphically illustrated, and the rock as a result of confining stress Represents an increase in strength, and
The band representation of rock strength provides a graphical illustration showing a discrete range of rock strength at a given depth, and the band representation of rock strength is coded to represent a soft rock strength range A method comprising: a first code; a second code representing a hard rock strength range; and an additional code representing one or more neutral rock strength ranges. 30. The method of claim 28, wherein generating the geological feature further comprises generating at least one additional feature selected from the group consisting of log data, rock quality, porosity, and shale plasticity. And including
The operating parameter includes at least one selected from the group consisting of weight on bit, bit rpm (revolutions per minute), cost, drilling speed, and torque. The method of claim 32, wherein
Log data is represented in the form of a curvilinear display, and the log data includes any log suite that is sensitive to rock quality and porosity;
The rock quality is expressed in the form of a percentage graph for use in identifying different types of rocks within a given formation, said percentage graph showing the percentage of each type of rock at a given depth;
The porosity is expressed in the form of a curve display, and
Shale plasticity is represented in at least one display format selected from the group consisting of a curve display, a percentage graph display, and a band display;
The curve representation of shale plasticity includes a curve of at least one shale plasticity parameter selected from the group consisting of moisture content, clay type, and clay volume, and the shale plasticity is hydrated according to a defined shale plasticity model. Characterized by rate, clay type, and clay volume, and
The band representation of the shale plastic provides a graphical illustration showing a discrete range of shale plasticity at a given depth, and further, the band representation of the shale plastic is coded to provide low shale plasticity A method comprising: a first code representing a range; a second code representing a high shale plastic range; and an additional code representing one or more neutral shale plastic ranges. 29. The method of claim 28, wherein bit wear is determined as a function of cumulative work done according to a defined bit wear model and in at least one display format selected from the group consisting of a curve display and a percentage graph display. Expressed,
The curve representation of bit wear can include bit work expressed as specific energy level at the bit, cumulative work done by the bit, and voluntary work loss due to polishing, and
The percentage graph display indicates a bit wear condition at a predetermined depth, and the bit wear percentage graph display is encoded, a first code representing an expired bit life, and a second code representing a remaining bit life. A method characterized by including code. 29. The method of claim 28, wherein the bit mechanical efficiency is determined as a function of torque / bit weight signature for a given bit according to a defined mechanical efficiency model and is selected from the group consisting of a curve display and a percentage graph display. Represented in at least one display format,
The curve representation of bit mechanical efficiency includes the total torque and cutting torque at the bit, and
The percentage graph display of bit mechanical efficiency graphically illustrates total torque, the total torque includes cutting torque and friction torque components, and the percentage graph of bit mechanical efficiency is encoded and cut A method comprising: a first code representing torque; a second code representing friction-free torque; and a third code representing friction-limited torque. 36. The method of claim 35, wherein the mechanical efficiency is further expressed in the form of a percentage graph illustrating the drilling system operating constraints that adversely affect the mechanical efficiency, wherein the drilling system operating constraints are a friction limited torque. The percentage graph further illustrates the corresponding percentage impact that each constraint has on the torque component with limited friction of mechanical efficiency at a given depth;
Drilling system operational constraints are: maximum torque on bit (TOB), maximum weight on bit (WOB), minimum and maximum revolutions per minute (RPM), maximum drilling speed (ROP), any of them Combinations, and unrestricted conditions,
A method wherein the percentage graph representations of drilling system operational constraints related to mechanical efficiency are coded and include different codes to identify different constraints. 30. The method of claim 28, wherein the output is represented in at least one display format selected from the group consisting of a curve display and a percentage graph display.
The curve display for output includes an output limit and an operation output level, the output limit corresponds to a maximum output to be applied to a bit, and the operation output level is an operation output level to be limited, a recommended operation Including at least one selected from the group consisting of an output level and a predicted operational output level; and
The percentage graph display of output illustrates drilling system operational constraints that adversely affect the output, the drilling system operational constraints correspond to constraints that result in output loss, and the percentage graph of the output constraint is In addition, each constraint shows the corresponding percentage impact on the dynamic output at a given depth, and the percentage graph display of drilling system operational constraints on output is coded to identify different constraints A method characterized by including different codes. The method of claim 22, further comprising:
In addition to geological features and predicted drilling mechanics, generating a detailed display of the proposed drilling facility, wherein the proposed drilling facility is used to predict the performance of the drilling system Including at least one recommended bit selection. 39. The method of claim 38, wherein first and second bit selections are recommended to be used with the expected performance for drilling holes, and wherein the first and second bit selections are first respectively. The first and second identifiers are displayed with geological features and predicted drilling mechanics, and the positioning of the first and second identifiers on the display Is selected to match the portion of expected performance to which each of the first and second bit selections applies. The method of claim 22, further comprising:
On the display of geological features and predicted drilling mechanics that a change in bit selection from the first recommended bit selection to the second recommended bit selection is required at a given depth A method comprising the steps of: In a computer program stored on a computer readable medium executed by a computer for predicting the performance of a drilling system in drilling a drill hole of a given formation,
Instructions for generating a geological feature of a formation per unit depth according to a defined geological model and outputting a signal representative of the geological feature, wherein the geological feature includes at least rock strength; and ,
Instructions for obtaining a specification of a proposed drilling facility for use in drilling a drill hole, said specification comprising a bit specification of at least one of the recommended drill bits;
According to the drilling mechanics model, the predicted drilling mechanics is determined according to the proposed drilling equipment specifications as a function of the geological features per unit depth, and a signal representing the predicted drilling mechanics Instructions for outputting, wherein the predicted drilling mechanics includes at least one selected from the group consisting of bit wear, mechanical efficiency, output, and operational parameters;
Instructions for controlling control parameters when drilling a drill hole in the drilling system in response to the predicted drilling mechanics output signal, wherein the control parameters include weight on bit, rpm, pump flow rate, and water pressure. An instruction comprising at least one selected from the group consisting of:
Instructions for obtaining measurement parameters in real time while drilling holes;
Instructions for historical verification of the measured parameter with a back-calculated value of the measured parameter, wherein the back-calculated value of the measured parameter is according to at least one selected from the group consisting of a drilling mechanics model and at least one control parameter The function for controlling the control parameter is further a) adjusting the drilling mechanics model according to a defined deviation between the measurement parameter and the back-calculated value of the measurement parameter. And b) modifying the control of the control parameter; and c) performing a warning operation, comprising: an instruction including at least one instruction selected from the group consisting of: Computer program. 42. The computer program of claim 41, further generating a display of geological features and predicted drilling mechanics per unit depth in response to the output signal of geological features and the output signal of predicted drilling mechanics. And a computer program characterized by comprising: 43. The computer program of claim 42, wherein generating the display includes using at least one selected from the group consisting of: a) a display monitor, and b) a printer, and per unit depth. A computer program wherein the display of geological features and predicted drilling mechanics includes a printout. 42. The computer program of claim 41, wherein generating the geological feature comprises generating at least one additional feature selected from the group consisting of log data, rock quality, porosity, and shale plasticity. A computer program characterized by comprising. 42. The computer program of claim 41, wherein obtaining the proposed drilling equipment input specifications further comprises a downhole motor, a top drive motor, a rotary table motor, a mud system, and a mud pump. A computer program comprising obtaining an additional specification of at least one proposed drilling facility selected from: 42. The computer program of claim 41, wherein the operational parameters include at least one selected from the group consisting of weight on bit, bit rpm (revolutions per minute), cost, drilling speed, and torque. A computer program characterized by 47. The computer program according to claim 46, wherein the excavation speed further includes an instantaneous excavation speed (ROP) and an average excavation speed (ROP-AVG). 43. The computer program of claim 42, wherein displaying the geological feature comprises displaying at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display.
A computer program characterized in that displaying the predicted drilling mechanics includes displaying at least one graphical display selected from the group consisting of a curve display, a percentage graph display, and a band display. 49. The computer program of claim 48, wherein generating the display includes using at least one selected from the group consisting of a) a display monitor and b) a printer, and per unit depth. A computer program wherein the display of geological features and predicted drilling mechanics includes a printout. 49. The computer program of claim 48, further characterized in that at least one graphical representation of the geological feature and at least one graphical representation of the predicted drilling mechanics are color coded. Computer program.

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