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ƚƵďŝŶŐ͕ĨŽůůŽǁĞĚďǇ'>DĂƐƐĞŵďůǇηϮǁŝƚŚĚƵŵŵǇǀĂůǀĞ͘Z/,ǁŝƚŚϳƐƚĂŶĚƐŽĨϯͲϭͬϮΗϵ͘ϯη>ͲϴϬ,ǇĚϱϯϯƚƵďŝŶŐ͕ŚĂŶŐ ,ŽĨĨŝŶƐƚĂĐŬ͘^ĞĐƵƌĞǁĞůůĂŶĚůŽĐĂƚŝŽŶĨŽƌĞǀĞŶŝŶŐ͘ϳϯϱďďůƐŽĨϴ͘ϲƉƉŐƉƌŽĚƵĐĞĚǁĂƚĞƌƉƵŵƉĞĚĚƵƌŝŶŐdŽƵƌ͕ ĐƵŵƵůĂƚŝǀĞƚŽƚĂůŽĨϮ͕ϳϴϲďďůƐƚŽǁĞůůďǇZŝŐϰϬϭ͘ ϬϲͬϮϱͬϮϬϮϭͲ&ƌŝĚĂǇ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϲͬϭϯͬϮϮ ϭϮͬϯϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ^ZhϭϯͲϮϳ ϱϬͲϭϯϯͲϮϬϲϬϳͲϬϬͲϬϬ ϮϭϮͲϭϴϭ ϬϲͬϮϴͬϮϬϮϭͲDŽŶĚĂǇ ĞŐŝŶWdƚŽϮ͕ϱϬϬηͲdĞƐƚ'ŽŽĚ͘ Z/,tͬϭ͘ϴϳ'ZƚŽϭϬ͕ϳϰϵΖ<ͲtͬdͲĂŶŶŽƚWĂƐƐͲWKK,͘ Z/,tͬϯͲϭͬϮĂƚĐŚĞƌ^Ƶďtͬ'^Ͳ^ŚĞĂƌWƌĞŵĂƚƵƌĞůǇΛϱ͕ϯϬϬΖ<ͲWKK,͘ Z/,tͬ^ĂŵĞƚŽϭϬ͕ϲϲϳΖ<ͲtͬdͲ^ĞƚͲtͬdͲWKK,ͲĂƚĐŚĞƌ^Ğƚ͘ Z/,tͬϯͲϭͬϮKDͲϭ<KdƚŽϭϬ͕ϲϭϱΖ<ͲtͬdͲ>ŽĐĂƚĞͲ^ŝƚͲ>ĂƚĐŚͲtͬdΘŽŵĞĨƌĞĞͲWKK,ƚŝůůϭϬ͕ϱϱϲΖ<͘ ĂŶĚ,ĂŶŐƵƉͲtͬdͲEŽ^ƉĂŶŐƐͲƚƚĞŵƉƚƚŽ:ĂƌůŝĐŬ&ƌĞĞ͘ĂŶŶŽƚWƵůůĨƌĞĞͲ^ƉĞĐƵůĂƚĞďĂůůŽĨǁŝƌĞ͘ &ƌŽŵůŽǁŶƵƉŚŽůĞͲ^ƚĂŶĚďǇ͘WƵůůŝŶĚΘƌŽƉƵƚƚĞƌďĂƌͲŽŵĞĨƌĞĞΘWKK,ǁŝƚŚŵĂŝŶƚĂŝŶĞĚǆƚƌĂtĞŝŐŚƚ͘ KƵƚŽĨŚŽůĞtͬƵƚƚĞƌďĂƌƌŝĚŝŶŐďĂůůŽĨǁŝƌĞϱΖďŽǀĞZŽƉĞƐŽĐŬĞƚŽĨǁŚŽůĞƚŽŽůƐƚƌŝŶŐΘ<Kd͘ ƵŵŵǇsĂůǀĞĐŽŶĨŝƌŵĞĚƉƵůůĞĚΘƌĞĐŽǀĞƌĞĚͲ>ĂǇĚŽǁŶƵƚϭϬϬΖŽĨǁŝƌĞΘZĞͲŚĞĂĚ͘ 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>ŽĐŬĚŽǁŶƐĐƌĞǁƐ͕ŝŶƐƚĂůůdt͘^/DKW^͗ďĞŐŝŶŵŽǀŝŶŐĞƋƵŝƉŵĞŶƚĂŶĚƉƌĞƉĂƌŝŶŐĨŽƌZ͘^ůŽǁůǇĨŝůůĚŽǁŶďĂĐŬƐŝĚĞŝŶ ƉƌĞƉĂƌĂƚŝŽŶĨŽƌƐĞĐŽŶĚD/dͲĂƐŝŶŐǆ/͘^ƵďŵŝƚϮϰͲŚƌŶŽƚŝĐĞƚŽK'ĨŽƌǁŝƚŶĞƐƐŽĨD/dĂĨƚĞƌůĂŶĚŝŶŐĐŽŵƉůĞƚŝŽŶ͘E KW͘DŽǀĞKW͕EhdƌĞĞ͘dĞƐƚĂŐĂŝŶƐƚƐǁĂďĐĂƉĂŶĚǀŽŝĚƚŽϱŬ͕ŐŽŽĚƚĞƐƚƐ͘WƵůůdt͘&ŝůůĚŽǁŶĂŶŶƵůƵƐǁŚŽůĞƚŝŵĞ͕ ƐƚŽƉƚŽĂůůŽǁƚŽΗďƵƌƉΗ͘ŝƌĐƵůĂƚĞĚĚŽǁŶƚŽƚĂůŽĨϯϰϱďďůƐƚŽĚĂǇĨŽƌĐƵŵƵůĂƚŝǀĞƚŽƚĂůƉƵŵƉĞĚŝŶƚŽǁĞůůϯϰϱϵďďůƐ͘ ϬϲͬϮϳͬϮϬϮϭͲ^ƵŶĚĂǇ W:^DǁŝƚŚĐƌĞǁŽŶŽƉĞŶŝŶŐƵƉƚŽǁĞůů͕ƉƌĞƐƐƵƌĞƚĞƐƚŝŶŐ͕ƌŝŐŐŝŶŐĚŽǁŶ͘KƉĞŶƚŽǁĞůů͕ďƵƌƉŽĨĂŝƌ͕ĐŽŶƚŝŶƵĞƚŽĨŝůůĂŶĚďƵƌƉ ;ŶŽŐĂƐͿ͘^/DKW^͗ůŽĂĚŝŶŐŽƵƚƚƌĂŝůĞƌƐĨŽƌƌŝŐŵŽǀĞ͘&ůƵŝĚƉĂĐŬǁĞůů͘EŽƌĞƐƉŽŶƐĞĨƌŽŵK'͕ůŝŶĞƵƉƚŽĐŽŶĚƵĐƚD/dϳͲ ϱͬϴΗĂƐŝŶŐďǇϯͲϭͬϮΗdƵďŝŶŐ͘WƌĞƐƐƵƌĞƵƉĨŽƌϮϱϬϬƉƐŝD/dŽĨϳͲϱͬϴΗĐĂƐŝŶŐǆϯͲϭͬϮΗƚƵďŝŶŐ͕ƌĞĐŽƌĚĨŽƌϯϬŵŝŶƵƚĞƐ͘>ŽƐƚ ϮϱƉƐŝŝŶϯϬŵŝŶ͕ŐŽŽĚƚĞƐƚ͘ůĞĞĚŽĨĨĂŶĚZĐŝƌĐƵůĂƚŝŽŶůŝŶĞƐ͘ZŝŐĚŽǁŶĂŶĚŵŽďŝůŝǌĞĞƋƵŝƉŵĞŶƚƚŽ^hϰϭͲϴĂŶĚƚŽ ĂŶŶĞƌǇ>ŽŽƉϬϬϱ͘ZĐŽŵƉůĞƚĞĂƚϭϴϯϬŚƌƐ͕ƚƵƌŶŽǀĞƌƚŽKƉĞƌĂƚŝŽŶƐ͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϲͬϭϯͬϮϮ ϭϮͬϯϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ^ZhϭϯͲϮϳ ϱϬͲϭϯϯͲϮϬϲϬϳͲϬϬͲϬϬ ϮϭϮͲϭϴϭ ϬϲͬϮϵͬϮϬϮϭͲdƵĞƐĚĂǇ ƌƌŝǀĞΛϭϯͲϮϳͲĞŐŝŶZͬh͘ Z/,tͬϯϭͬϮ'^ƚŽϭϬϲϲϳΖ<ͲtͬdͲ>ĂƚĐŚͲtͬdͲŽŵĞĨƌĞĞΘWKK,tĂƚĐŚĞƌ^Ƶď͘ Z/,tͬϭ͘ϳϱdd>ĂŝůĞƌƚŽϭϬϳϰϵΖ<ͲtͬdͲĂŶŶŽƚWĂƐƐͲWKK,͘ Z/,tͬϭ͘ϵϭ>/ƚŽϭϬϳϰϵΖ<ͲtͬdͲ&ĂůůƚŚƌŽƵŐŚƚŽϭϬϴϲϬΖ<ͲWKK,tͬ^ŚŽƵůĚĞƌŝŶĚŝĐĂƚŝŽŶŽŶ>/͘ Z/,tͬϭ͘ϳϱdd>ĂŝůĞƌƚŽϭϭϲϱϬΖ<dƵďŝŶŐƚĂŝůůŽĐĂƚĞĚΛϭϬΖϴϮϳΖ<ͲWKK,͘ t>'ŝƐĂƚϭϬ͕ϴϮϮ>DŵĂŬŝŶŐĐŽƌƌĞĐƚĞĚWdсϭϭ͕ϲϰϱΖ>D͘ ZDK͘ ϬϳͬϯϭͬϮϬϮϭͲ^ĂƚƵƌĚĂǇ ^ŝŐŶŝŶ͘DŽďĞƚŽůŽĐĂƚŝŽŶ͘WdtΘ:^͘^ƉŽƚĞƋƵŝƉŵĞŶƚĂŶĚƌŝŐƵƉůƵďƌŝĐĂƚŽƌ͘ƌŵŐƵŶ͘WdƚŽϮϱϬƉƐŝůŽǁĂŶĚϮ͕ϱϬϬƉƐŝ ŚŝŐŚ͘ZĂƚĞĂƉƌŽǆůŝŬĞǇĞƐƚĞƌĚĂǇϴϯϬͲϴϰϱďďůƐ͘ϭϵϬƉƐŝ͘Z/,ǁͬϮͲϭͬϴΗǆϭϵΖ,;,ϭϬͺhƉƉĞƌƐƚƌŝƉŐƵŶ͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞ ĂŶĚƚŝĞŝŶƚŽǇĞƐƚĞƌĚĂǇƉĞƌĨůŽŐ;>ŽŶůǇͿ͘tŽƌŬĞĚŐƵŶƚŚƌƵƐƉŽƚĂƚϭϬ͕ϳϬϯΖdd͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘ 'ĞƚŽŬƚŽƉĞƌĨĨƌŽŵϭϭ͕ϱϱϯΖƚŽϭϭ͕ϱϳϮΖǁͬϭϵϬƉƐŝ͘^ƉŽƚƚĞĚĂŶĚĨŝƌĞĚŐƵŶ͘ĨƚĞƌϱŵŝŶͲϭϵϬƉƐŝ͕ϭϬŵŝŶͲϮϬϬƉƐŝĂŶĚϭϱ ŵŝŶͲϮϬϬƉƐŝ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘Z/,ǁͬϮͲϭͬϴΗǆϳΖΖ,;,ϭϬͺhƉƉĞƌƐƚƌŝƉŐƵŶ͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽƚŽĚĂǇƐ ƉĞƌĨůŽŐ;>ŽŶůǇͿ͘'ƵŶƐĞƚĚŽǁŶĂƚϭϬ͕ϳϬϯΖ;dƵďŝŶŐdĂůůǇ͘tŽƌŬĞĚĨŽƌϰϱŵŝŶǁĞůůĨůŽǁŝŶŐ͘^ŚƵƚǁĞůůŝŶĂŶĚǁŽƌŬĞĚĨŽƌ ϭϱŵŝŶĂŶĚŶŽŐŽ͘WKK,͘'ƵŶŽŬ͘Z/,ǁͬϮͲϭͬϴΗǆϳΖΖ,;,ϱͿƐƚƌŝƉŐƵŶ͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞ;ƉƵƚĚŝĨĨĞƌĞŶƚďŽƚƚŽŵƉƌŽĨŝůĞ ŽŶŐƵŶͿĂŶĚƚŝĞŝŶƚŽƚŽĚĂǇƐƉĞƌĨůŽŐ;>ŽŶůǇͿ͘'ƵŶƐĞƚĚŽǁŶĂƚϭϬ͕ϲϴϬΖdƵďĞdĂůůǇ͘dŚĂƚǁĂƐĂůŝƚƚůĞŚŝŐŚĞƌƚŚĂŶďĞĨŽƌĞ͘ tĞƚƌŝĞĚǁŝƚŚǁĞůůĨůŽǁŝŶŐĂŶĚƐŚƵƚŝŶ͘ŝĚŶΖƚŵĂŬĞĂŶǇĚŝĨĨĞƌĞŶĐĞ͘WKK,ƚŽůŽŽŬĂƚƚŽŽůƐ͘ůŽŽŬŽŬ͘Z/,ǁͬϮͲϭͬϴΗǆϳΖΖ, ;,ϱͿƐƚƌŝƉŐƵŶ͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞ;ŵĂĚĞƵƉĂŶŽƚŚĞƌŐƵŶͿĂŶĚƚŝĞŝŶƚŽƚŽĚĂǇƐƉĞƌĨůŽŐ;>ŽŶůǇͿ͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚ ƐĞŶĚƚŽƚŽǁŶ͘'ĞƚŽŬƚŽƉĞƌĨĨƌŽŵϭϭ͕ϮϯϵΖƚŽϭϭ͕ϮϰϲΖǁͬϮϬϬƉƐŝ͘^ƉŽƚĂŶĚĨŝƌĞĚŐƵŶǁͬϮϬϬƉƐŝ͘ϱ͕ϭϬĂŶĚϭϱŵŝŶǁĂƐϮϬϬ ƉƐŝ͘WKK,ͬůůƐŚŽƚƐĨŝƌĞĚ͘ZŝŐĚŽǁŶůƵďƌŝĐĂƚŽƌĂŶĚĞƋƵŝƉŵĞŶƚ͘ ϬϳͬϯϬͬϮϬϮϭͲ&ƌŝĚĂǇ ^ŝŐŶŝŶ͘DŽďĞƚŽůŽĐĂƚŝŽŶ͘WdtĂŶĚ:^͘^ƉŽƚĞƋƵŝƉŵĞŶƚĂŶĚƌŝŐƵƉůƵďƌŝĐĂƚŽƌ͘WdƚŽϮϱϬƉƐŝůŽǁĂŶĚϮ͕ϱϬϬƉƐŝŚŝŐŚ͘ZĂƚĞ ϴϯϬďďůͬdWͲϭϴϬƉƐŝ͘Z/,ǁͬϮͲϭͬϴΗǆϵΖƐƚƌŝƉŐƵŶ͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽƐĐŚĞŵĂƚŝĐΘ>ϭϱŵĂƌϮϬϭϯ;,^Ϳ͘ 'ƵŶƐĂƚĚŽǁŶϱ͕ϬϱϴΖ;'>DͿ͘ŽƵůĚŶŽƚŐĞƚĚŽǁŶ͘ĂůůĞĚƚŽǁŶ͘ĞĐŝƐŝŽŶŵĂĚĞƚŽƐŚƵƚǁĞůůŝŶĂŶĚƐĞĞŝĨŝƚŐŽĞƐ͘^ŚƵƚǁĞůů ŝŶĂŶĚďŽƵŶĐĞƚŽŽůƐĂŶĚŝƚǁĞŶƚƚŚƌƵ;'>DͿ͘tĞŶƚŽŶĚŽǁŶŚŽůĞƚŽϭϬ͕ϳϬϰΖĂŶĚĐŽƵůĚŶΖƚŐĞƚĚĞĞƉĞƌ͘ƌŽƵŐŚƚǁĞůůďĂĐŬ ŽŶĂŶĚƚƌŝĞĚŝƚďƵƚŶŽŐŽ͘WKK,͘'ƵŶůŽŽŬĞĚŐŽŽĚ͘Z/,ǁͬƚǁŽϭͲϭϭͬϭϲΗǁƚƐĂŶĚ>͘ĂŶĚƚĂŐŐĞĚĂƚϭϭ͕ϲϮϰΖ͘ŽƵůĚŶŽƚ ŐĞƚĂŶǇĚĞĞƉĞƌ͘^ŚƵƚǁĞůůŝŶďƵƚŶŽŐŽŽĚ͘ƌŝŶŐǁĞůůďĂĐŬŽŶĂŶĚƌƵŶĂĐŽƌƌĞůĂƚŝŽŶůŽŐĨƌŽŵϭϭ͕ϲϮϰΖƚŽϭϬ͕͘ϰϱϬΖ͘^ĞŶĚůŽŐ ƚŽƚŽǁŶĂŶĚWKK,͘ƌŝŶŐǁĞůůďĂĐŬŽŶ͘Z/,ǁͬƚǁŽϮΗǆϭϬΖŐƵŶƐ;ϮϬΖͿĂŶĚϭͲϭϭͬϭϲΗǁƚĂŶĚ>ĂŶĚĐŽƌƌĞůĂƚĞĚƚŽ>͘ tĞŶƚŽŶĚŽǁŶƚŽϭϭ͕ϲϮϰΖĂŶĚƚĂŐŐĞĚǁŝƚŚŶŽƉƌŽďůĞŵƐ͘ZƵŶĂŶŽƚŚĞƌ>ůŽŐĨƌŽŵϭϭ͕ϲϮϰΖƚŽϭϬ͕ϰϱϬΖ͘WKK,͘Z/,ǁͬϮͲ ϭͬϴΗǆϭϬΖ;,ϭϬhƉƉĞƌͿ͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽ>>ŽŐ͘dŚĞǇŚĂĚƚŽďŽƵŶĐĞƚŚĞŐƵŶŵŽƌĞƚŽŐĞƚŐƵŶƚŽƐůŝĚĞ ĂŶĚŐĞƚďǇďĂĚƐƉŽƚ͘ZƵŶ>ůŽŐĨƌŽŵϭϭ͕ϱϴϮΖ;ĚŝĚŶΖƚƚĂŐͿƚŽϭϭ͕ϬϬϬΖ͘^ĞŶĚůŽŐƚŽƚŽǁŶ͘'ĞƚŽŬƚŽƉĞƌĨĨƌŽŵϭϭ͕ϱϳϮΖƚŽ ϭϭ͕ϱϴϮΖǁͬǁĞůůĨůŽǁŝŶŐϴϯϬďďůͬƉĞƌĚĂǇͬdWϭϴϬƉƐŝ͘^ƉŽƚĂŶĚĨŝƌĞĚŐƵŶ͘ĨƚĞƌϱŵŝŶͲϭϵϬƉƐŝ͕ϭϬĂŶĚϭϱŵŝŶƐĂŵĞͲϭϵϬ ƉƐŝ͘ůůƐŚŽƚƐĨŝƌĞĚ͘ZŝŐĚŽǁŶůƵďƌŝĐĂƚŽƌĂŶĚƐŚƵƚĚŽǁŶĨŽƌƚŚĞŶŝŐŚƚ͘ĞďĂĐŬĂƚϬϵϬϬŝŶƚŚĞŵŽƌŶŝŶŐ͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϲͬϭϯͬϮϮ ϭϮͬϯϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ^ZhϭϯͲϮϳ ϱϬͲϭϯϯͲϮϬϲϬϳͲϬϬͲϬϬ ϮϭϮͲϭϴϭ W:^DĂŶĚWdt͘,ĞĂĚƚŽůŽĐĂƚŝŽŶĂŶĚƐƉŽƚĞƋƵŝƉŵĞŶƚ͘Zh<ͲůŝŶĞ͘ ^ŚƵƚŝŶǁĞůůǁŝƚŚϮϬϬƉƐŝŽŶƚŚĞƚƵďŝŶŐ͘Dͬh>ƵďƌŝĐĂƚŽƌĂŶĚWdƚŽϮϱϬƉƐŝͬϮϱϬϬƉƐŝ͘ KŶĞŽͲƌŝŶŐǁĂƐƌĞƉůĂĐĞĚ͘ZĞƚĞƐƚůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝͬϮϱϬϬƉƐŝͲdĞƐƚŐŽŽĚ͘DͬhũĂƌƐ͕>ĂŶĚϭϳĨƚϮ͘ϭϮϱΗKƐƚƌŝƉŐƵŶ ϭϱŐ͕ϲƐƉĨ͘;>ƚŽƚŽƉƐŚŽƚϯ͘ϯΖͿ͕Z/,ƚŽϱ͕ϬϳϮΖ͘ĂŶŶŽƚƉĂƐƐ'>D͕ǁŽƌŬƚŽŽůǁŝƚŚŶŽůƵĐŬWKK,͘dŚĞďŽƚƚŽŵŽĨƚŚĞƐƚƌŝƉ ŐƵŶǁĂƐƐůŝŐŚƚůǇďĞŶƚĨƌŽŵŚĂŶŐŝŶŐƵƉ͘ƌĞĂŬŽĨĨďŽƚƚŽŵϳĨƚŽĨƚĂŶĚĞŵŐƵŶ͘DͬhũĂƌƐ͕>ĂŶĚϭϬĨƚϮ͘ϭϮϱΗKƐƚƌŝƉŐƵŶ ϭϱŐ͕ϲƐƉĨ͘;>ƚŽƚŽƉƐŚŽƚϯ͘ϯΖͿ͕Z/,ǁŝƚŚŶŽŝƐƐƵĞƐ͕ƉƵůůĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘^ŚŝĨƚƵƉϭĨƚ͘ WƌŽĚƵĐƚŝŽŶŽƉĞŶĞĚƵƉƚŚĞǁĞůůƚŽĨůŽǁ͘WƵůůŝŶƚŽƉŽƐŝƚŝŽŶĂŶĚƉĞƌĨŽƌĂƚĞdǇŽŶĞŬ'ͲϮĨƌŽŵϭϭ͕ϬϵϵΖͲϭϭ͕ϭϬϵΖ͘WKK,͘KŶůǇ ϮĨƚŽĨϭϬĨƚƐƚƌŝƉŐƵŶĐĂƌƌŝĞƌƉƵůůĞĚŽƵƚŽĨƚŚĞǁĞůů͘dŚĞƌĞŵĂŝŶŝŶŐϴĨƚŝƐŝŶƚŚĞǁĞůů͕ƉƌĞƐƵŵĂďůǇĨƌŽŵǁŚĞŶǁĞĨŝƌĞĚƚŚĞ ŐƵŶ͕ŶŽŽǀĞƌͲƉƵůůǁĂƐƐĞĞŶǁŚŝůĞƉƵůůŝŶŐŽƵƚŽĨŚŽůĞ͘ ^/dWƐƚĞĂĚǇĂƚϭϵϱƉƐŝ͘^ĞĐƵƌĞǁĞůůĂŶĚ^&E͘ WƌŽĚƵĐƚŝŽŶǁŝůůĨůŽǁǁĞůůŽǀĞƌŶŝŐŚƚ͘ ϭϮͬϮϵͬϮϬϮϭͲtĞĚŶĞƐĚĂǇ W:^DĂŶĚWdt͘tĂƌŵͲƵƉĞƋƵŝƉŵĞŶƚ͘ WƌŽĚƵĐƚŝŽŶƐŚƵƚǁĞůůŝŶ͘DͬhũĂƌƐ͕>ĂŶĚϳĨƚϮ͘ϭϮϱΗKƐƚƌŝƉŐƵŶϭϱŐ͕ϲƐƉĨ͘;>ƚŽƚŽƉƐŚŽƚϯ͘ϯΖͿ͕Z/,͕ŚĂǀĞƚŽǁŽƌŬŐƵŶ ƉĂƐƚŽǀĞƌƐŚŽƚĂƚϭϬ͕ϳϲϬΖ͘WƵůůĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ^/dWϭϵϱW^/͘WƵůůŝŶƚŽƉŽƐŝƚŝŽŶĂŶĚƉĞƌĨŽƌĂƚĞ dǇŽŶĞŬ'ͲϮĨƌŽŵϭϭ͕ϬϵϮΖͲϭϭ͕ϬϵϵΖ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘DͬhũĂƌƐ͕>ĂŶĚϭϬĨƚϮ͘ϭϮϱΗKƐƚƌŝƉŐƵŶϭϱŐ͕ϲƐƉĨ͘;>ƚŽƚŽƉ ƐŚŽƚϯ͘ϯΖͿ͕Z/,͘,ĂŶŐƵƉŽŶyƉƌŽĨŝůĞĂƚϭϬ͕ϲϴϭ͕ǁŽƌŬĞĚŐƵŶƚŚƌŽƵŐŚ͘,ĂŶŐƵƉŝŶϮ͘ϯϭϯΗ/yͲŶŝƉƉůĞĂƚϭϬ͕ϲϵϴΖ͘tŽƌŬĞĚ ŐƵŶ͕ĐŽƵůĚŶŽƚŐĞƚƉĂƐƚyͲŶŝƉƉůĞ͘WKK,͘ŶĚŽĨƚŚĞƐƚƌŝƉŐƵŶŝƐďĞŶƚĂůŝƚƚůĞ͕ŶŽŵĂũŽƌĚĂŵĂŐĞƐĞĞŶŽŶƚŚĞŐƵŶ͘>ĂǇĚŽǁŶ ůƵďƌŝĐĂƚŽƌĂŶĚƐĞĐƵƌĞǁĞůů͘^&E͘ WƌŽĚƵĐƚŝŽŶǁŝůůĨůŽǁƚŚĞǁĞůůŽǀĞƌŶŝŐŚƚ͘ ϭϮͬϯϬͬϮϬϮϭͲdŚƵƌƐĚĂǇ W:^DĂŶĚWdt͘tĂƌŵͲƵƉĞƋƵŝƉŵĞŶƚ͘ WƌŽĚƵĐƚŝŽŶƐŚƵƚǁĞůůŝŶ͘DͬhũĂƌƐ͕ƐǁŝǀĞů͕>ĂŶĚϭϬĨƚϮ͘ϭϮϱΗKƐƚƌŝƉŐƵŶϭϱŐ͕ϲƐƉĨ͘ĚĚĞĚĂĚĚŝƚŝŽŶĂůŐƵŶƐƵďƚŽƚŚĞ ďŽƚƚŽŵŽĨƚŚĞƐƚƌŝƉƚŽĂĐƚĂƐĂĐĞŶƚƌĂůŝǌĞƌ͘;>ƚŽƚŽƉƐŚŽƚϯ͘ϯΖͿ͕Z/,͘,ĂĚƚŽǁŽƌŬŐƵŶƚŚƌŽƵŐŚ'>DĂƚϱ͕ϬϳϮ͘EŽŽƚŚĞƌ ŝƐƐƵĞƐ͘WƵůůĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͘WƵůůŝŶƚŽƉŽƐŝƚŝŽŶĂŶĚƉĞƌĨŽƌĂƚĞdǇŽŶĞŬ'ͲϮĨƌŽŵϭϭ͕ϬϳϮΖͲ ϭϭ͕ϬϴϮΖ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘DͬhũĂƌƐ͕ƐǁŝǀĞů͕>͕ĂŶĚϭϬĨƚϮ͘ϭϮϱΗKƐƚƌŝƉŐƵŶϭϱŐ͕ϲƐƉĨ͘ĚĚĞĚĂĚĚŝƚŝŽŶĂůŐƵŶƐƵďƚŽ ƚŚĞďŽƚƚŽŵŽĨƚŚĞƐƚƌŝƉƚŽĂĐƚĂƐĂĐĞŶƚƌĂůŝǌĞƌ͘;>ƚŽƚŽƉƐŚŽƚϯ͘ϯΖͿ͕Z/,͘,ĂĚƚŽǁŽƌŬŐƵŶƚŚƌŽƵŐŚ'>DĂƚϭϬ͕ϱϱϳ͘EŽ ŽƚŚĞƌŝƐƐƵĞƐ͘WƵůůĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͘WƵůůŝŶƚŽƉŽƐŝƚŝŽŶĂŶĚƉĞƌĨŽƌĂƚĞdǇŽŶĞŬ'ͲϮĨƌŽŵϭϭ͕ϬϲϮΖͲ ϭϭ͕ϬϳϮΖ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘>ĂǇĚŽǁŶůƵďƌŝĐĂƚŽƌ͘ŚĂŶŐĞŽƵƚƉĂĐŬŽĨĨ͕ƐĞĐƵƌĞǁĞůůĂŶĚ^&E͘ WƌŽĚƵĐƚŝŽŶǁŝůůĨůŽǁƚŚĞǁĞůůŽǀĞƌŶŝŐŚƚ͘ ϭϮͬϮϴͬϮϬϮϭͲdƵĞƐĚĂǇ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϲͬϭϯͬϮϮ ϭϮͬϯϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ^ZhϭϯͲϮϳ ϱϬͲϭϯϯͲϮϬϲϬϳͲϬϬͲϬϬ ϮϭϮͲϭϴϭ ϭϮͬϯϭͬϮϬϮϭͲ&ƌŝĚĂǇ W:^DĂŶĚWdt͘tĂƌŵͲƵƉĞƋƵŝƉŵĞŶƚ͘ WƌŽĚƵĐƚŝŽŶƐŚƵƚǁĞůůŝŶ͘&ŽƵŶĚŐĂůůĞĚƚŚƌĞĂĚƐŽŶƚŚĞũĂƌ͕ĐŚĂƐĞĚƚŚƌĞĂĚƐĨŝǆĞĚƚŽŽů͘DͬhũĂƌƐ͕ƐǁŝǀĞů͕>ĂŶĚϵĨƚ Ϯ͘ϭϮϱΗKƐƚƌŝƉŐƵŶϭϱŐ͕ϲƐƉĨ͘ĚĚĞĚĂĚĚŝƚŝŽŶĂůŐƵŶƐƵďƚŽƚŚĞďŽƚƚŽŵŽĨƚŚĞƐƚƌŝƉƚŽĂĐƚĂƐĂĐĞŶƚƌĂůŝǌĞƌ͘;>ƚŽƚŽƉ ƐŚŽƚϯ͘ϯΖͿ͕Z/,͘EŽŝƐƐƵĞƐŐĞƚƚŝŶŐĚŽǁŶ͘WƵůůĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͘WƵůůŝŶƚŽƉŽƐŝƚŝŽŶĂŶĚƉĞƌĨŽƌĂƚĞ dǇŽŶĞŬ'ͲϮĨƌŽŵϭϭ͕ϬϱϯΖͲϭϭ͕ϬϲϮΖ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘DͬhũĂƌƐ͕ƐǁŝǀĞů͕>ĂŶĚϵĨƚϮ͘ϭϮϱΗKƐƚƌŝƉŐƵŶϭϱŐ͕ϲƐƉĨ͘ ĚĚĞĚĂĚĚŝƚŝŽŶĂůŐƵŶƐƵďƚŽƚŚĞďŽƚƚŽŵŽĨƚŚĞƐƚƌŝƉƚŽĂĐƚĂƐĂĐĞŶƚƌĂůŝǌĞƌ͘;>ƚŽƚŽƉƐŚŽƚϯ͘ϯΖͿ͕Z/,͘EŽŝƐƐƵĞƐŐĞƚƚŝŶŐ ĚŽǁŶ͘WƵůůĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘KŶĚĞƉƚŚ͘WƵůůŝŶƚŽƉŽƐŝƚŝŽŶĂŶĚƉĞƌĨŽƌĂƚĞdǇŽŶĞŬ'ͲϮĨƌŽŵϭϭ͕ϬϰϰΖͲ ϭϭ͕ϬϱϯΖ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘ZͲůŝŶĞ͘dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ 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returning one copy of this transmittal Received By: Date: DATE: 1/17/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 13-27 (PTD 212-181) Strip Gun 12/31/2021 Please include current contact information if different from above. Received By: 01/20/2022 37' (6HW By Abby Bell at 10:21 am, Jan 20, 2022 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By:Date: DATE: 10/13/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 13-27 (PTD 212-181) Memory Multi-Finger Caliper 06/03/2021 Log Results Summary 06/03/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/13/2021 By Abby Bell at 5:27 pm, Oct 13, 2021 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/30/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: SRU 13-27 (PTD 212-181) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. Received By: 08/31/202 37' (6HW By Abby Bell at 12:53 pm, Aug 31, 2021 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/06/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL SRU 13-27 (PTD 212-181) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW Received By: 08/10/2021 By Abby Bell at 11:06 am, Aug 06, 2021 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/03/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL SRU 13-27 (PTD 212-181) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. Received By: 08/03/2021 37' (6HW By Abby Bell at 10:45 am, Aug 03, 2021 STATE OF ALASKA I( Reviewed By: "� OIL AND GAS CONSERVATION COMMISSION P.I. Supry -7/1 2cD-A BOPE Test Report for: SWANSON RIV UNIT 13-27 - Comm Contractor/RigNo.: Hilcorp 401 PTD#: 2121810 DATE: 6/21/2021 - Inspector Jeff Jones - Insp Source Operator: Hilcorp Alaska, LLC - Operator Rep: Chris Hannevold Rig Rep: Rob O'Neal Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopJJ210628180007 Rams: Annular: Valves: NIASP: Type Test: IN1T - 321-265250/2500 - 250/2500 250/2500- 2250 ' Related Insp No: MISC. INSPECTIONS: H P/F Location Gen.: P Housekeeping: P -" PTD On Location P Standing Order Posted P Well Sign P " Drl. Rig P_ 11 P ' azar PP. Number of Failures: 0 ✓ Test Results Test Time 6 Remarks: The BOPE tests were completed today in a safe manner with no component failures witnessed. The extended test time was due to problems with the chart recorder. Mr. O'Neal indicated he will have this item repaired and the spare recorder calibrated prior to the next test. The gas cFelection and pit volume totalizer alarm systems were tested and operated properly. This rig has recently updated the BOPE control system with a new Koomey/air compressor unit and a new electric remote BOPE control panel at the driller's station with indicator lights for the system components. The new system operated very well and the new equipment is a welcome change from the outdated Koomey control system previously used on this rig. The rig and location appeared clean, orderly and in good condition. Misc NA TEST DATA FLOOR SAFTY VALVES: BOP STACK: MUD SYSTEM: CHOKE MANIFOLD: ACCUMULATOR SYSTEM: Quantity P/F Quantity Size Visual Alarm Quantity Time/Pressure P/F Trip Tank NA _ NA ' System Pressure _2900 - P Pit Level Indicators P P Pressure After Closure 2200- P Flow Indicator NA NA " 200 PSI Attained 24 - P Meth Gas Detector P - P Full Pressure Attained 70 - P H2S Gas Detector P - P Blind Switch Covers: All " P MS Misc NA NA Nitgn. Bottles (avg): 617x, 2250' P NA ACC Misc 0 NA Number of Failures: 0 ✓ Test Results Test Time 6 Remarks: The BOPE tests were completed today in a safe manner with no component failures witnessed. The extended test time was due to problems with the chart recorder. Mr. O'Neal indicated he will have this item repaired and the spare recorder calibrated prior to the next test. The gas cFelection and pit volume totalizer alarm systems were tested and operated properly. This rig has recently updated the BOPE control system with a new Koomey/air compressor unit and a new electric remote BOPE control panel at the driller's station with indicator lights for the system components. The new system operated very well and the new equipment is a welcome change from the outdated Koomey control system previously used on this rig. The rig and location appeared clean, orderly and in good condition. Misc NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 0 _ NA" Stripper 0 __. NA No. Valves 8 _ P__- Lower Kelly 0 _ _ _ NA' Annular Preventer - 1 _ 11" - _ P Manual Chokes 2 P ' Ball Type -_ 2 P - #1 Rams 1 2 7/8 x 5" __P Hydraulic Chokes 0 _ NA - Inside BOP 0 NA- #2 Rams 1 ---Blind _ P CH Misc 0 -_ NA FSV Misc 0 NA #3 Rams 0 NA #4 Rams 0 NA - - #5 Rams 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 - 2 1/16" P, Quantity P/F HCR Valves 1 2 1/16" P_ Inside Reel Valves 0 NA Kill Line Valves 2 - 2 1/16" _' P Check Valve 0 NA BOP Misc 0 NA Number of Failures: 0 ✓ Test Results Test Time 6 Remarks: The BOPE tests were completed today in a safe manner with no component failures witnessed. The extended test time was due to problems with the chart recorder. Mr. O'Neal indicated he will have this item repaired and the spare recorder calibrated prior to the next test. The gas cFelection and pit volume totalizer alarm systems were tested and operated properly. This rig has recently updated the BOPE control system with a new Koomey/air compressor unit and a new electric remote BOPE control panel at the driller's station with indicator lights for the system components. The new system operated very well and the new equipment is a welcome change from the outdated Koomey control system previously used on this rig. The rig and location appeared clean, orderly and in good condition. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 11,835'N/A Casing Collapse Structural Conductor Surface 2,480 psi Intermediate 4,790 psi Production Liner 7,250 psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 11,247'11,751'11,171'~2250psi N/A AS-1X Ret Prod Pkr; N/A 10,786' MD/10,292' TVD; N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: 8,290 psi Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 A028399, A028406 212-181 50-133-20607-00-00 Swanson River Unit (SRU) 13-27 Swanson River Unit / Hemlock Oil Length Size CO 123A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 6.4# / L-80 TVD Burst 10,831' MD 6,890 psi 5,210 psi 80' 2,998' 10,474' 80' 3,002' 16" 10-3/4" 80' 7-5/8"10,986' 3,002' Perforation Depth MD (ft): 10,986' See Attached Schematic 5" Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: June 14, 2021 11,831'1,038' 2-7/8" 11,244' m n P 66 t _ c Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:00 am, Jun 01, 2021 321-265 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.28 13:56:03 -08'00' Taylor Wellman (2143) BOP tests to 2500 psi. DLB 06/01/2021 X XX Provide 24 hrs notice to AOGCC inspectors to witness MITIA after new completion is run. DSR-6/1/21 10-404 BJM 6/14/21 dts 6/14/2021 JLC 6/14/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.14 14:54:24 -08'00' RBDMS HEW 6/16/2021 RWO- Tubing swap Well: SRU 13-27 Date: 5/26/2021 Well Name:SRU 13-27 API Number:50-133-20607-00-00 Current Status:GL Oil Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:212-181 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Todd Sidoti (907) 632-4113 (C) Maximum Expected BHP:~ 3358 psi @ 11,082’ TVD Based on 0.303 psi/ft Swanson gradient to deepest to be perf’d interval Max. Potential Surface Pressure:~ 2250 psi Using Max BHP minus 0.1 psi/ft gas gradient to surface Well’s surface location has been reviewed, and does NOT trigger the need for an SSSV as per AOGCC reg 20AAC 25.265(d) Well Summary SRU 13-27 is a GL oil producer currently online at ~500bfpd making 25bopd, and negligible gas. The well has historically made 900+bfpd, and is likely underperforming currently due to not gas lifting on bottom. Beginning in 2018 PT surveys begun to indicate multiple possible tubing holes in the 2-7/8” above the top GLM from 3900 – 4320’ MD. This likely explains the degradation in total fluid, due to decreased drawdown. The purpose of this work/sundry is to replace the existing 2-7/8” GL completion with a 3-1/2” GL completion Notes Regarding Wellbore Condition x Max deviation: 27 deg at 9893’ MD x All DLS <3deg / 100’ x All GLM’s have live valves in them except the top station which is dummied off x Drifts o 12/22/17: patch set from 4290 – 4312’ MD. No performance improvement o 4/18/18: Patch pulled, SL drifted to 11,550’ MD with a 7’ 2” dummy gun and a 2.30” gauge ring o 4/23/18: Multiple temperature shifts above top GLM o 5/2/21: 2.25" x 4' drive down bailer tagged at 11,643'. Sticky, and bailer returned 1/4 full of sand x MIT History: o 3/11/13: D&C with kill string. Leave well for RWO rig to run completion o 3/16/13: Passed a MIT to 2900psi of 7-5/8” and 5” casing down to PBTD before tubing was run o 5/11/13: Current 2-7/8” tubing /packer run with plug in tubing tail. CMIT-TxIA passed to 3000psi RWO- Tubing swap Well: SRU 13-27 Date: 5/26/2021 Pre-rig (non-sundried steps) 1. MIRU SL 2. Perform a flowing memory GR/CCL/P/T survey from PBTD to surface (obtain a light tag on bottom) 3. Confirm good data, then SI well and turn off GL 4. Obtain a memory caliper from 11,675’ MD to surface 5. Pull lower most GLV and leave open pocket 6. Set TTP in X-nipple at 10,825’ MD 7. Load IA and tubing with produced water (63 bbls tubing + 409 bbls IA = 472bbls WBV) 8. Once full, perform a 30 minute CMIT-TxIA to 2500psi. Does not need to be charted 9. Once pass, pull TTP and RDMO 10. Set BPV Rig 401 Procedure 1. MIRU 401 workover rig 2. Ensure well is fluid packed down the tubing and IA (will be in communication downhole). Use produced water for KWF for duration of RWO (~8.6ppg) 3. ND Tree and THA, NU BOP per attached schematic. 4. Perform BOP Test 250 psi low & 2500 psi high, annular to 250 psi low & 2500 psi high. a. Provide 24hr notice to AOGCC of BOP Test. b. Test with 2-7/8” and 3-1/2” test joint c. Record with chart & submit to AOGCC within 5 days of test. 5. Rigup and release 2-7/8” x 7-5/8” retrievable production packer from 10,786’ MD. a. Tubing was set in 8000lbs of compression. Be careful when backing out LDS, as tubing growth may be a possibility b. Consult Tripoint rep for exact packer release procedure c. May be necessary to release from T-2 on/off tool to get hanger to rig floor, and then reengage packer with working pipe and hanger removed d. Be aware that once packer is released, gas may migrate to surface from below packer / behind tubing tail. CONTINGENCY: If can’t release packer assembly, contact OE. Contingency completion would be to EL cut just above T-2 on/off tool and then complete with a 3-1/2” x 2-7/8” XO and a non-sealing overshot below a new packer to align with the left in hole packer / tubing tail assembly. 5.e Flush gas and oil from below packer into perfs and perform flow check before pulling completion out of hole. 4.d. Pull TWC Install TWC prior to ND tree. - bjm RWO- Tubing swap Well: SRU 13-27 Date: 5/26/2021 6. POOH with 2-7/8” tubing, jewelry and packer laying down sideways 7. MU TCP perf guns per table below (likely 2-7/8” – 3-3/8” guns with 4-6spf). Consult OE for exact perf depths Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) Tyonek G2 11035 11111 10518 10587 76 H3/H4 11158 11221 10631 10686 63 H5 11222 11251 10687 10714 29 H7L 11396 11410 10850 10857 14 H9 11430 11457 10878 10901 27 H10 11549 11585 10985 11018 36 H11 11610 11655 11041 11082 45 8. RIH with TCP guns. 9. PU 3-1/2” completion tubing to be used for TCP conveyance 10. Add additional workstring as necessary to get guns to target depth. 11. RIH to target depth with TCP guns 12. Once on at depth, rigup EL and RIH with GR/CCL for tie-in. 13. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Jeff Nelson- Geo @ 307-760-8065 b. Meredyth Richards - RE @ 907-343-9701 14. Shift perf BHA per geo/RE, then POOH and RD EL 15. Proceed per TCP vendor and fire guns a. Monitor for any pressure increase or flow before and after perf’ing b. Should be well overbalanced before and after shooting c. Ok to POOH while monitoring pressures and flow 16. POOH laying down workstring and racking back 3-1/2” tubing 17. Pickup jewelry and RIH with 3-1/2” gas lift completion per OE 18. Set production packer per vendor rep 19. Perform MIT-IA for 30 charted minutes to 2500psi 20. RDMO rig Notify AOGCC for witness of pressure test. RWO- Tubing swap Well: SRU 13-27 Date: 5/26/2021 Post-rig work (non-Sundried) 1. MIRU SL 2. Pull B&R etc… as necessary 3. D&T to PBTD with 2.70” GR 4. Set live GL design per OE 5. RDMO Post-rig EL perfs:if any of the above perfs are moved to post-rig, see below 1. MIRU E-line and pressure control equipment. PT lubricator to 2,500 psi Hi 250 Low. 2. Perform flowing PT survey from PBTD to surface (want light tag) 3. Rig up perf gun (Likely 2” – 3-3/8” 4-6 spf) 4. RIH and perforate sands listed in the table above, per Geo/RE. Consult with OE for what WHP to use. Some intervals may be shot while flowing Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Jeff Nelson- Geo @ 307-760-8065 ii. Meredyth Richards - RE @ 907-343-9701 5. RD E-Line Unit and turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic 3. Rig 401 BOP schematic 4. RWO change form ___________________________________________________________________________________ Updated by CRR 5-19-21 SCHEMATIC Swanson River Unit Well: SRU 13-27 PTD:212-181 API: 50-133-20607-00 TD = 11,835’ MD - 11,247’ TVD PBTD = 11,751 MD – 11,171’ TVD KB-THF: 18.6’ Note: 5 Holes in tubing from 3900- 4320’ MD confirmed with PT survey 04/23/18 CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth - - - Surf 80' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 3,002’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 7,406’ 7-5/8"Intermediate 29.7 P-110 BTC 6.875”7,406’10,986’ 5"Prod Lnr 15 L-80 DWC/C HT 4.408"10,793’11,831’ TUBING 2-7/8”Production 6.4 L-80 8rd 2.441 Surf 10,831’ 1 5 16” 10-3/4” 3 4 7 8 10 5” JEWELRY DETAIL No.Depth ID OD Item 1 22.85’2.992”4.500”Crossover 2-7/8” 8rd Pin x 3-1/2” 8rd Box 2 4,462’2.441”4.625”GLV #5 BK-2 latch. DGLV as of 11/21/17 (2-7/8” SFO-1 GLM) 3 7,328’2.441”4.625”GLV #4 R-1 GLV, BK-2 latch. 2066 psi (2-7/8” SFO-1 GLM) 4 8,925’2.441”4.625”GLV #3 R-1 GLV, BK-2 latch. 1983 psi (2-7/8” SFO-1 GLM) 5 9,989’2,441”4.625”GLV #2 R-1 GLV, BK-2 latch. 1923 psi (2-7/8” SFO-1 GLM) 6 10,736’2.441”4.625”GLV #1 R-O1 Orifice, BK-2 latch. (2-7/8” SFO-1 GLM) 7 10,784’2.313”6.250”T-2 On/Off tool with X-Profile 8 10,786’2.500”6.672”7-5/8” x 2-7/8” 24-29.7# AS-1X Ret Prod Packer 9 10,793’Flexlock hanger /RS packoff seal nipple / HRD ZXP LTP / PBR 10 10,825’2.313”3.230”2-7/8” X-Nipple 11 10,831’2.500”3.690”2-7/8” Wireline Re-Entry Guide 7-5/8” 6 H11 2 11 Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Comments Date G2 11,044’11,082’10,527’10,561’38’2” HC 07/05/13 H3/H4 11,160’11,219’10,631’10,685’59’3-3/8” HC 05/08/13 H5 11,222’11,227’10,687’10,692’5’2” Connex HC 04/19/18 H9 11,432 11,449 10,878 10,893’17’2-1/8” strip 5/1/13 H10 11,553’11,576’10,988’11,009’23’1-11/16” strip 04/22/13 H10 11,591’11,609’11,023’11,040’18’2-1/8” strip 04/05/13 H11 11,612’11,631’11,042’11,060’19’3-3/8” HC 03/15/13 H3/H4 H10 G2 H5 OPEN HOLE / CEMENT DETAIL 10-3/4"13-1/2” hole. 255bbls 12.0ppg Class A extended lead followed by 80bbls 15.4ppg Class A conventional. No losses, and 159bbls back to surface. 7-5/8” 9.875”hole. 380 bbls 14.1ppg Class G Extended lead followed by 80bbls 15.3ppg Class G Gaslock. No losses.No spacer (50bbls) nor cement to surface. 3/14/13 CBL shows ToC at least up to 2900’ MD (stopped logging there). ToC shouldn’t be any higher than 1260’ MD given no psacer back to surface. ToC likely between 1260’ – 2900’ MD 5”6.75” hole. 46 BBL’s 15.3ppg Class G EasyBlok cement. No losses. All of MudPush and 4 bbls cement circ’d to surface form liner top. 3/15/13 CBL shows ToC at ToL (10,793’ MD) 9 H9 ___________________________________________________________________________________ Updated by CRR 5-19-21 PROPOSED SCHEMATIC Swanson River Unit Well: SRU 13-27 PTD:212-181 API: 50-133-20607-00 TD = 11,835’ MD - 11,247’ TVD PBTD = 11,751 MD – 11,171’ TVD KB-THF: 18.6’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth - - - Surf 80' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 3,002’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 7,406’ 7-5/8"Intermediate 29.7 P-110 BTC 6.875”7,406’10,986’ 5"Prod Lnr 15 L-80 DWC/C HT 4.408"10,793’11,831’ TUBING 3-1/2”Production L-80 2.992”Surface 10,825’ 16” 10-3/4” 1 5” JEWELRY DETAIL No.Depth ID OD Item 1 TBD 3-1/2” GLM(s) depth and quantity to be determined 2 ±10,750’Production packer 3 10,793’Flexlock hanger / RS packoff seal nipple / HRD ZXP LTP / PBR 4 ±10,825’3-1/2” XN nipple 7-5/8” H13 Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Comments Date Perfs and Reperfs per sundry G2 11,044’11,082’10,527’10,561’38’2” HC 07/05/13 H3/H4 11,160’11,219’10,631’10,685’59’3-3/8” HC 05/08/13 H5 11,222’11,227’10,687’10,692’5’2” Connex HC 04/19/18 H9 11,432 11,449 10,878 10,893’17’2-1/8” strip 5/1/13 H10 11,553’11,576’10,988’11,009’23’1-11/16” strip 04/22/13 H10 11,591’11,609’11,023’11,040’18’2-1/8” strip 04/05/13 H11 11,612’11,631’11,042’11,060’19’3-3/8” HC 03/15/13 H3/H4 H10 G2 H5 OPEN HOLE / CEMENT DETAIL 10-3/4"13-1/2” hole. 255bbls 12.0ppg Class A extended lead followed by 80bbls 15.4ppg Class A conventional. No losses, and 159bbls back to surface. 7-5/8” 9.875” hole. 380 bbls 14.1ppg Class G Extended lead followed by 80bbls 15.3ppg Class G Gaslock. No losses.No spacer (50bbls) nor cement to surface. 3/14/13 CBL shows ToC at least up to 2900’ MD (stopped logging there). ToC shouldn’t be any higher than 1260’ MD given no psacer back to surface. ToC likely between 1260’ – 2900’ MD 5”6.75” hole. 46 BBL’s 15.3ppg Class G EasyBlok cement. No losses. All of MudPush and 4 bbls cement circ’d to surface form liner top. 3/15/13 CBL shows ToC at ToL (10,793’ MD) 2 H9 3 4 The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 11" Spherical Annular Height: 42" 11" LWS Double BOP 2-7/8" to 5" Multirams top Blind rams bottom Height:33" 11" Mud Cross W/ 4-1/16" Outlets Dual 2-1/16" Manual Gate Valves W/ DSA to 4-1/16" Width to flange: 34" 2-1/16" Manual Gate Valve & 2-1/16" HCR W/ DSA to 4- 1/16" Full Mud Cross Assy. width w/ valves installed Width: 96" Kill side Choke side BOP Stack Width: 96" @ valves Height Addition for Ring Gaskets: .75" BOP Total Height: 101.75" 11" 5m BOP Package W/ 2-1/16" Valves Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well SRU 13-27 (PTD 212-181)Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.SecPageDateProcedure ChangeNew 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date Swanson River SRU 13-27 05/25/2021 Starting head, Seaboard, 16 ¾ 3M X 16'’ SOW BTM, w/ 2- 2 1/16 5M SSO 16'’ 10 ¾’’ 7 5/8'’ Casing spool, Seaboard-S8, 16 3/4 3M X 11 5M, w/ 2- 2 1/16 5M SSO, 10 3/4 P seal bottom 3 ½’’ or 2 7/8'’ Multi-bowl, Upper, SMB-22, 11 5M x 11 5M w/ 2- 2 1/16 5M SSO Valve, master, WKM-M, 3 1/8 5M FE, HWO, DD trim Valve, master, WKM-M, 3 1/8 5M FE, HWO, DD trim Valve, swab, WKM-M, 3 1/8 5M FE, HWO, DD trim BHTA, Otis, 3 1/8 5M FE X 3'’ Bowen quick union Swanson River SRU 13-27 16 x 10 ¾ x 7 5/8 x 2 7/8 Tubing hanger, Seaboard, SM-E-CCL, 11 x 3 ½ EUE 8rd lift and susp, w/ 3'’ type H BPV profile, 2- ½ npt control line ports, 4 5/8 extended neck, Alloy material SOF T4 • • ywP*\\ I/jy s� THE STATE Alaska Oil and Gas ®f/\ LA s KA Conservation Commission .' ritt _�_ 333 West Seventh Avenue ITh GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 o"PALAS' Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99501 Re: Swanson River Field, Hemlock Oil Pool, SCU 13-27 Permit to Drill Number: 212-181 Sundry Number: 318-143 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this 7 day of April, 2018. cot Rg d a ECEIVED STATE OF ALASKA eAPR 9 2 2018 T, ALASKA OIL AND GAS CONSERVATION COMMISSION 3 I I APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate ❑ Repair Well p 0 Operations shutdown El Suspend 0 Perforate Q • Other Stimulate ❑ Pull Tubing 0 Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing El /0,.,,G�` Oth r: Liz 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number:(gv> �Jrr✓� Hilcorp Alaska, LLC Exploratory 0 Development Q• 212-181 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20607-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Aq- r ❑ Swanson River Unit(SRU)13-27 • Will planned perforations require a spacing exception? Yes El No • 9. Property Designation(Lease Number): 10. Field/Pool(s): A028399,A028406 Swanson River Unit/Hemlock Oil • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 11,835' 11,247' • 11,751' 11,170' 2,633 psi N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi Intermediate 10,986' 7-5/8" 10,986' 10,474' 6,890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250P si Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8" 6.4#/L-80 10,831' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): AS-1X Ret Prod Pkr; N/A 10,786'MD-10,292'TVD;N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development Q • Service 0 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: April 16,2018 OIL ❑r • WINJ 0 WDSPL 0 Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG 0 GSTOR 0 SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramert hilcoro.com > Contact Phone: 777-8420 Authorized Signature: �i�2'C��7 Date:'//Z// COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 513_ 1413 Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No 0 F BDM-14 r n 0 LY 1o. Spacing Exception Required? Yes 0 No d Subsequent Form Required: / 6 __L1or APPROVED BY Approved by: ?"--firj COMMISSIONER THE COMMISSION Date: 4 1 Itl°i Q�n \v ie. zi-3..i,31 [s 1, ,1 AL Submit Form and Form 10-403 Revised 4/201 Approved epplicllli6n��s111 iddd��666r 2444nnndddllh�irom the date of approval. Attachments in Duplicate a' ! yj01/0'‘ z.ip 111 • i Well Prognosis Well: SRU 13-27 Hilcora Alaska,LU Date:4/2/2018 Well Name: SRU 13-27 API Number: 50-133-20607-00 Current Status: Gas-Lifted Oil Well Leg: N/A Estimated Start Date: April 16th, 2018 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-181 First Call Engineer: Ted Kramer (907) 777-8420(0) (985) 867-0665 (M) Second Call Engineer: Taylor Nasse (907) 777-8354(0) (907) 227-5293 M) AFE Number: Current Bottom Hole Pressure: 1,840 psi @ 11,050'TVD Flowing Survey 11-5-17 Maximum Expected BHP: 2,925 psi @ 11,070'TVD Buildup Survey 4-2013 Maximum Potential Surface Pressure: 2,633 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary Well SRU 13-27 is a gas-lifted oil well with a comingled completion in the G and Hemlock zones. In November of 2017 during a gas lift Survey a tubing leak was discovered which was patched in December 2017. The purpose of this work/sundry is to add perforations in the Hemlock H5 bench. Sundry Pre-Work 1.) MIRU Slickline. Pressure test lubricator 3,000 psi. High/250 Low. 2.) RIH with retrieving tool and retri ubing patch from 4,290'to 4,312'. 3.) RD Slickline. Brief Procedure: 1. MIRU e-line unit. Pressure Test lubricator to 3,500 psi Hi 250 Low. 2. SI and bleed tubing pressure down, as directed by Reservoir Engineer. 3. PU and RIH with perf guns. Log on depth and perforate the following intervals. Zone Sands Top (MD) Btm (MD) FT Hemlock H-5 ±11,222' ±11,227' 5' a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Gamma/CCL correlation log. e. Record tubing pressures before and after each perforating run. f. All perforations in table above are located in the Hemlock&Tyonek G Pool based on Conservation Order No. 123B. 4. RD E-line. 5. RU Slickline. Pressure test Lubricator to 3,000 psi. High/250 Low. 6. Re-run Weatherford patch from 4,290 to 4,312'. 7. RDMO Slickline Unit. 8. Turn Well over to Production. Well Prognosis Well: SRU 13-27 Hilcorp Alaska,LLQ Date:4/2/2018 Attachments: 1. Actual Schematic 2. Proposed Schematic • 4110 e Swanson River Unit . ' inWell: SRU 13-27 SCHEMATIC Completion Ran:5/10/13 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL i 1 Size Type Wt Grade Conn. ID Top Btm 16' 2 16„ Conductor—Driven to Surf 80' . Set Depth ie - 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' e 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' TUBING 10-3/4"4 cf" , 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' Patch i I r. ' K 4,290'— w1 ' 4,312' "}, 3 i J/ WLM IP JEWELRY DETAIL No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/r 8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box it 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 4 7,328' 2.441" 4.625" GLV#4 2066 psi 4 i ,: 5 8,925' 2.441" 4.625" GLV#3 1983 psi f., 6 9,989' 2,441" 4.625" GLV#2 1923 psi 7 10,736' 2.441" 4.625" GLV#1 Orifice 'a 5 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile ;4. 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,825' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 I r G2 11,044' - 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 _ "' H3/H4 11,160' . 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 8 f H12 11,553' • 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 is !Atm 1 9 H12 11,591' • 11,609' 11,023' 11,040' 18' 04/05/13 ir s/s„ i 77,1 l ti i t �a G2 -1. 4,t4 ;0, Q H3/H4 4* 41 u .4 -" H12 T . 5g H13 Max deviation 21` ...�f ++++iiii .. w :::, 6-3/4"Hole 5".,r 1 .4 ',9 kmf TD=11,835'MD-11,247'TVD PBTD=11,751 MD—11,171'TVD Downhole Revised:7/12/13 Updated by DMA 01-22-18 YII 0 le Swanson River Unit a S Well: SRU 13-27:51 PROPOSED SCHEMATIC Completion Ran10�13 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL 1 j [ Size Type Wt Grade Conn. ID Top Btm 16' ,a. 2 • 16„ Conductor-Driven to Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' TUBING 10-3/4"4. , 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' Patch —T---÷ yVc 4,290'- 4,312' 3 1 Il WLM JEWELRY DETAIL • No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box ,� 3 4,462' 2.441" 4.625" GLV#5 2212psi ,4 4 1 4 7,328' 2.441" 4.625" GLV#4 2066 psi ++ 5 8,925' 2.441" 4.625" GLV#3 1983 psi 6 9,989' 2,441" 4.625" GLV#2 1923 psi 7 10,736' 2.441" 4.625" GLV#1 Orifice 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 5 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,825' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 6 il • PERFORATIONS • Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 1 , G2 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 8 -- -I H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 i' V H5 ±11,222' ±11,227' ±10,687' ±10,692' 5' Proposed - illH12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 9 H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 I 7-5/$" e, 10 ; • 11 'A4r lir i a, 41 H r0 G2 M - H3/H4 H5 lex: H1 H13 Max deviation 21 ' '4 k"+'. 6-3/4"Hole TD=11,835'M D-11,247'ND PBTD=11,751 MD-11,171'ND Downhole Revised:7/12/13 Updated by DMA 04-02-18 • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION IAN 5 2018 REPORT OF SUNDRY WELL OPERATIONS ', iCC 1.Operations Abandon U Plug Perforations LI Fracture Stimulate U Pull TubingU U Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑Other: Remove Capstring/Install Patch 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ 212-181 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6.API Number: AK 99503 50-133-20607-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: A028399,A028406 Swanson River Unit(SRU)13-27 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Unit/Hemlock Oil 11.Present Well Condition Summary: Total Depth measured 11,835 feet Plugs measured N/A feet true vertical 11,247 feet Junk measured feet Effective Depth measured 11,751 feet Packer measured 10,786 feet true vertical 11,170 feet true vertical 10,292 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi Intermediate 10,986' 7-5/8" 10,986' 10,474' 6,890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.4#/L-80 10,831' 10,333'TVD Packers and SSSV(type,measured and true vertical depth) AS-1X Ret Prod Pkr 10,786'MD 10,292'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A CANNED JAN 3 1, `/01b' 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 106 10 642 1550 240 Subsequent to operation: 81 142 750 1400 175 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations El Exploratory Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil Q Gas 0 WDSPL LI Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-590 Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operationsl/.//71 Manager Contact Email: tkramerat hilcoro.com Authorized Signature: � Jj— Date: /1711i 47 Contact Phone: 777-8420 Form 10-404 Revised 4/2017 de*, /-25---/6' RBDMS Uv JAN ? J 2018 Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SRU 13-27 Capstring/SL 50-133-20607-00-00 212-181 11/4/17 12/22/17 Daily Operations: 11/03/2017 - Friday RU capstring truck and pull capstring OOH, for well maintenance. 12/22/2017 - Friday MIRU Pollard Slick line unit. RIH W/G-stop. Set same @ 4,312'. POOH. PU RIH w/ pack off and 10' spacer pipe to 4,290'. Set and shear off. Continue running patch and bleeding down the back side to observe pressure bleed off. Secure well. Rig down. Depart field. Swanson11 Completion RiverRan751;10/13 :S/Unit 10/13 Well: SRU 13-27 SCHEMATIC PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 1s' 2 r Conductor—Driven to 16" Set Depth - - Surf 80' aY 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' .. 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' TUBING 10- 'L .� 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' Patch * 4,290'— 4,312' : I WLM JEWELRY DETAIL No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 3 4,462' 2.441" 4.625" GLV#5 2212psi z 1 1 4 7,328' 2.441" 4.625" GLV#4 2066 psi 5 8,925' 2.441" 4.625" GLV#3 1983 psi 6 9,989' 2,441" 4.625" GLV#2 1923 psi 7 10,736' 2.441" 4.625" GLV#1 Orifice . 5 1 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,825' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide q 6 I hi PERFORATIONS ' Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 I 4 G2 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 I. ;', H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 8 H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 , t_ n� H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 9 H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 7-5/8" ";Lo' t",,i u ' s) e.'4 L 2 G2 e, H3/H4 Vit' ',*' H12 2 ' H13 Max deviation 21 • r :. 6-3/4"Hole i. TD=11,835'MD-11,247'ND PBTD=11,751 MD—11,171'ND Downhole Revised:7/12/13 Updated by DMA 01-22-18 OF • �w \\I%7y7am sA THE STAT Alaska Oil and Gas OfLASKA Conservation Commission to 333 West Seventh Avenue rh, GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 o1"ALAS ' Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLCNejA Lj 3 `I 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field,Hemlock Oil Pool, SRU 13-27 Permit to Drill Number: 212-181 Sundry Number: 317-590 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster Commissioner DATED this /d day of December, 2017. :i;;C S LLQ 2017 • • RECEIVED STATE OF ALASKA 6TS 12/i , 7 ALASKA OIL AND GAS CONSERVATION COMMISSION DEC Ill 2017 v/ APPLICATION FOR SUNDRY APPROVALS 20 MC 25.280 A� i,p� 1.Type of Request: Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Repair Well 0 . p i s tdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubing 0 Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing ❑ Other: Install Patch 0• 2.Operator Name: 4.Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development Q • 212-181 . 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20607-00 . 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑� Swanson River Unit(SRU)13-27 9.Property Designation(Lease Number): 10. Field/Pool(s): A028399,A028406 Swanson River Unit/Hemlock Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 11,835' • 11,247' • 11,751' 11,170' 2,633 psi N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi Intermediate 10,986' 7-5/8" 10,986' 10,474' 6,890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8" 6.4#/L-80 10,831' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): AS-1X Ret Prod Pkr; N/A 10,786'MD-10,292'TVD;N/A 12.Attachments: Proposal Summary Q Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory 0 Stratigraphic ❑ Development 0 • Service 0 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: December 20,2017 OIL ❑/ WINJ 0 WDSPL ❑ Suspended 0 16.Verbal Approval: Date: GAS 0 WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown 0 Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcoro.com Contact Phone: 777-8420 Authorized Signature: /4"W— ------Date: 6Z/E 3 / 7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31'1 • q 6 Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes 0 No 0 _ ' ',7 Spacing Exception Required? Yes 0 No El/ Subsequent Form Required: / (o -^ LI OLI •&tip 1,t, �� J LL ii ele7 P•-•32.1.44./...... APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ca—ly.i7 �� /�•�s._/ QJ iiLAL� Submit Form and Form 10-403 Revised 4/2017 Approved application is vali o s approval. Attachment in Duplicate /�/ jam//-, � /2, ( /7 Well Prognosis Well: SRU 13-27 Hilcurp Alaska,LLC Date: 12/12/17 Well Name: SRU 13-27 API Number: 50-133-20607-00 Current Status: Gas-Lifted producer Leg: NA Estimated Start Date: December 20, 2017 Rig: Slick-line Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz Permit to Drill Number: 212-181 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 227-5293 M) Current Bottom Hole Pressure: 1,840 psi @ 11,050'TVD Flowing Survey 11-5-17 Maximum Expected BHP: 2,925 psi @ 11,070'TVD Buildup Survey 4-2013 Maximum Potential Surface Pressure: 2,633 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary Well SRU 13-27 is a gas-lifted oil well with a comingled completion in the G and Hemlock zones. During a gas-lift survey on 11/22/17 a hole was located at 4,300'.This project will set a patch to cover the hole(s). Procedure: 1. MIRU Slick-line, PT lubricator to 3,200 psi. 2. RIH with slick-line and set stops and patch over hole at±4,300'. ✓ 3. RD slick-line 4. Place well in test. 5. If well production is still low, re-install through tubing capillary string through patch. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic Swanson River Unit Well: SRU 13-27 II 411/ ACTUAL SCH EMATICCTUAL SCHEMATIC•C Completion Ran:5/10/13 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL 1Size Type Wt Grade Conn. ID Top Btm 16'zi 2 V16„ Conductor Driven to - Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' 4kal it. TUBING 10-3/4"4 u 1, k 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' R1 k ti____ JEWELRY DETAIL i 3 111 i 1 No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd iliI2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box rx' 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 P t 4 7,328' 2.441" 4.625" GLV#4 2066 psi 5 8,925' 2.441" 4.625' GLV#3 1983 psi ! 04 0 6 9,989' 2,441" 4.625" GLV#2 1923 psi 7 10,736' 2.441" 4.625" GLV#1 Orifice 5 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,825' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 0 6 i PERFORATIONS l'il , Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 i G2 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 8 H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 A H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 9` i i _¢ I s, H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 9 it = H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 iii 7-5/8" x •10D 11I Vi - G2 1411 H3/H4 44 H12 H13 "3i Max deviation 21° Le ,..,,,, c„,, 6-3/4"Hole 5"..!.., TD=11,835'MD-11,247'TVD PBTD=11,751 MD—11,171'TVD Downhole Revised:7/12/13 Updated by DMA 12-13-17 Swanson River Unit Well: SRU 13-27 14 • 0 PROPOSED SCHEMATIC Completion Ran: 5/10/13 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL 1 1Size Type Wt Grade Conn. ID Top Btm 16 2 '' Conductor-Driven to 16 Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' 1.4 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' r: 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' TUBING 10-3/4"h , 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' Patch - I ±4,290'- 14 ±4,310' 3 i 1 WLM '€j JEWELRY DETAIL No. Depth ID OD Item ' 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box ' 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 4 7,328' 2.441" 4.625" GLV#4 2066 psi 5 8,925' 2.441" 4.625" GLV#3 1983 psi 6 9,989' 2,441" 4.625" GLV#2 1923 psi 7 10,736' 2.441" 4.625" GLV#1 Orifice 5 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 4 10 10,825' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 6 • i PPERFORATIONS 144 0 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 i1 , G2 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 I H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 9 - H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 7-5/8" A'- i t 10 i♦ *,, `' ilow- Capillary String Installed TBD 3/8" 2205 Stainless Steel 1 Top Bottom - MD 0' 10,775' TVD 0' 10,282' G2 1 r H3/H4 t • 4." H12 T ., T H13 Max deviation 21 r._t ',M'i.� `b 6-3/4"Hole TD=11,835'MD-11,247'ND PBTD=11,751 MD-11,171'ND Downhole Revised:7/12/13 Updated by DMA 12-13-17 Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable b direct inspection of the file. c . 1,1_ I 'I Well History File Identifier Organizing (done) ❑ Two-sided ❑ Rescan Needed RESCAN: OVERSIZED: NOTES: 9/ for Items: vol aps: Gv15 rayscale Items: gs: ❑ Poor Quality Originals: ❑ Other: ❑ Other: r/ p BY: Maria ) Date: i V is 1sl Project Proofing BY: maria ) Date: 1 Ig) /5 /sl IfYIP Scanning Preparation x 30 - 1 6° + I = TOTAL PAGES 1 81 )/87):—.5. (Count does not include cover sheet) BY: Maria Date: I /s/ Production Scanning Stage 1 Page Count from Scanned File: I S (Count does include cov sheet) Page Count Matches Number in Scanning Preparation: 1 YES NO BY: Date:(cia Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Stage 2 Additional Well Reports: iso NO TOTAL PAGES: T— Digital version appended by: Meredith Michal M 1 Date: c h /s/ ��IGJ'��J�� Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: c 3`0 Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked 7/8/2014 Well History File Cover Page_20140708.doc o 9 o o I : rn o o o o y N 9X M o n c Z n E E rn a rn 0 OO I o N o; co1 fn o m a 0 0_ tl c) d - a, el U m am c c ui 6 6 6 M Ili 6 ani Cl. • D U_ N 01 M U M 6:1.0 EE �I r) O W l. 00 co c0 c0 c0 N v% O E U O N N r r .- r r r 7 N N dN. fa 0) ,- el _M MN _MN C7N L'7N _MN MN MN _MN 'C Z 0 O E N 0 D D O D O D O D O Del D c.) D M D M D a.. - a)0 F. 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NN N N N N N N N N N N w N ;N N CO COCO CO CO CO CO CO CO CO CO CO N .N N N N N N N N N N N N N N o W C d C C: E E s' I Z v co Z U O 0 COco a aa v y w 0 U U 0 U 0 0 0 U U 0 U U `o 2 C) p O m 0 D D D 0 0 0 0 0 0 0 0 0 0 o y Z d a 2 w W w LU LU LU W w w w w w w _ 3 ___ - o a• 4 c , N � � o n N d c Z >- >- r E N y CO en D L >. Cn C N c ((�� T ) Qb O d 0Z' ' [i Z t L O aU a m I - 2 Q N 2 1 o `O m U U J J 9 . Z Z 7 it y N U L/V/m IL J yQ IL E O/� 1 Om N Q 0 U '- CO Q W J a LL E y W 0 m ✓ • o E o E Z ,- y Q o O O) N O O c N J a C CL 0 2 U U M c J 'j • g Oa I H O a O � ,, 1 (.„ s„...1 o U � ) ...... c) 4.4 E "'4 Q r- ea c' E O P. I— co 0 H H I— — I— "' 1 1 5� z N co C G N m re> - c a. E Z Mo• T 7 CI) O a) c 0I y 4; Z 0 C C CD p ICCa c , Q a .2 m O 1 j 0 13 o > M_ N_N Z O a N N_ r Q o re 13 N E 0.o OF 3 c%) r cN d O p '1 = O li N N Y W N 1' Q' M H .- U Ow C m Q co c c 2 Z c ca o : ao ) O 0 ° Q o Q c c U .+ U J m a , c C7 n o a a v E a O E a E 2 0 O E N O o o Q a 2 U a 0 U 0 a i U 0 fl Landon Ellison GeoTech II Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 DATA LOGGED Anchorage, AK 99503 442013 Tele: 907 777-8339 2:6 2,C%4t . / . l<BENDER Ildemp %1.14.4_11C Fax: 907 777-8510 E-mail: lellison@hilcorp.com RECEIVED SEP 0 4 2013 DATE 09/04/2013 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTA SCU 13-27 Prints: Gamma Ray Realtime/Memory Log MD 2in Gamma Ray Realtime/Memory Log MD 5in Gamma Ray Realtime/Memory Log TVD 2in Gamma Ray Realtime/Memory Log TVD 5in CD: Final Well Data Hilcorp_SRU13-27_Final Surveys_258-11835 8122/2013 9:37 AM Adobe Acrobat D.. 81 K8 Hitcorp_SRU13-27_MD2RLTMEM_GAM_3022-11835 8,"22,2013 10 25 AM Adobe Acrobat D... 1,039 KB Hilcorp_SRU13-27_MD5RLTMEM_GAM_3022-11835 8122/2013 10:24 AM Adobe Acrobat D.- 2,252 KB Hilcorp_SRU13-27_TVD2RLTMEM_GAM_3022-11835 8/22/2013 9:47 AM Adobe Acrobat D.- 1,358 KB Hilcorp_SRU13-27_TVD5RLTMEM_GAM_3022-11835 8/22/2013 10:34 AM Adobe Acrobat D. 2466 KB • Flitcorp_SRU13-27_MD2RLTIvIEM_GAM 3022-11835 8/22/20138:42 AM CGM File 1,010 KB Hilcorp SRU13-27_MD5RLTMEM_GAM_3022-11835 8/22/2013 8:43 AM CGM File Z611 KB • Hilcorp_SRU13-27 TVD2RLTMEM_GAM 3022-11835 8/22/2013 9:39 AM CGM Fe 1,079 KB • Hilcorp_SRU13-27 TVD5RLTMEM_GAM_3022-11835 8/22/2013 10:33 AM CGM File 1525 KB Hitcorp_SRU13-27_MDRLTMEM_GAM 3022-11835 8/22,2013 7:23 AM LAS File 3583 KB Hitcorp_SRU13-27_Final Surveys_258-11835 8121,2013 5:34 PM Text Document 35 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: P7Date: 9144IkS RECEIVED STATE OF ALASKA ,JUL 2 2 2013 ALASKA OIL AND GAS CONSERVATION COMMIsolON REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U Replace Cap String Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑., Exploratory ❑ 212-181 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 50-133-20607-00 7.Property Designation(Lease Number): 8.Well Name and Number: A028399,A028406 Swanson River Unit(SRU)13-27 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Unit/Hemlock Oil 11.Present Well Condition Summary: Total Depth measured 11,835 feet Plugs measured N/A feet true vertical 11,247 feet Junk measured 11,751 (cement) feet Effective Depth measured 11,751 feet Packer measured 10,786 feet true vertical 11,170 feet true vertical 10,292 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi Intermediate 10,986' 7-5/8" 10,986' 10,474' 6,890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.4#/L-80 10,831' 10,333'TVD Packers and SSSV(type,measured and true vertical depth) AS-1X Ret Prod Pkr 10,786'MD 10,292'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Pnor to well operation: 120 810 403 1650 265 Subsequent to operation: 157 603 496 1420 225 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development❑, Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil Q Gas ❑ WDSPL❑ - GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP El SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-354 Contact Stan Porhola Email sporhola a( hilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature ,....51:7 -fb ' t\. Phone 907-777-8412 Date -7 7�/3 RBDM JUL 2 4 2013* Form 10-404 Revised 10/2012 6 f7V Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00 212-181 7/12/13 7/12/13 Daily Operations: 07/12/2013 - Friday Rig Up Cap String Truck. Rig up lubricator and adapter. Test to 3,000 psi. RIH w/3/8" capillary string. Set capillary string @ 10,775'. RDMO Cap String Truck. • Swanson River Unit II Well: SRU 13-27 ACTUAL SCHEMATIC Completion Ran:5/10/13 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 16" 216EJ , [ L „ Conductor—Driven to - - - Surf 80' 1p ' I Set Depth .. 10-3/4” Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' L 1 / 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' ` TUBING 10-3/4" y. 1 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' 4 I "* JEWELRY JEWELRY DETAIL _ No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box ' 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 4 7,328' 2.441" 4.625" GLV#4 2066 psi 5 8,925' 2.441" 4.625" GLV#3 1983 psi 6 9,989' 2,441" 4.625" GLV#2 1923 psi _ 7 10,736' 2.441" 4.625" GLV#1 Orifice 5 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,825' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 6 IC PERFORATIONS Zone Top(MD) _ Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date z9 7 I11,160 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 H3/H4 11,160 11,219 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 ,, 8 H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 :v .$' I l I H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 9 tdi H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 7-5/8"47 • ir0,' 00,11.0 40 111:111P" 7'. Capillary String Installed on 7/12/2013 * + , 3/8" 2205 Stainless Steel " ' Top Bottom 0 e» MD 0' 10,775' 4:0 "! TVD 0' 10,282' 1 G2 tdd-4 i'4 d a T H3/H4 t't y H12 ,1; H13 ,, 1,:, 97 Max deviation 2T 7 �t• y4 X41 "j 6-3/4"Hole 5,, a . r. t.. TD=11,835'MD-11,247'ND PBTD=11,751 MD—11,171'ND Downhole Revised:7/12/13 Updated by STP 07/15/13 RECEIVED STATE OF ALASKA ` AL,-......A OIL AND GAS CONSERVATION COMMIoION JUL 19 2013 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development D Exploratory ❑ 212-181 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 50-133-20607-00 7.Property Designation(Lease Number): 8.Well Name and Number: A028399,A028406 Swanson River Unit(SRU)13-27 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Unit/Hemlock Oil 11.Present Well Condition Summary: Total Depth measured 11,835 feet Plugs measured N/A feet true vertical 11,247 feet Junk measured 11,751 (cement) feet Effective Depth measured 11,751 feet Packer measured 10,786 feet true vertical 11,170 feet true vertical 10,292 feet Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi Intermediate 10,986' 7-5/8" 10,986' 10,474' 6,890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.4#/L-80 10,831' 10,333'ND Packers and SSSV(type,measured and true vertical depth) AS-1X Ret Prod Pkr 10,786'MD 10,292'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 123 1728 437 1600 250 Subsequent to operation: 120 2036 403 1650 265 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development❑✓ Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil ❑✓ Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-341 Contact Stan Porhola Email sporhola@hilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature +._polis Phone 907-777-8412 Date 1 f'1 /3 RBDM J 2 4 Z01,4 A7 7V71, Form 10-404 Revised 10/2012 Submit Original Only -2/1 • 1111 Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00 212-181 7/5/13 7/5/13 Daily Operations: 07/05/2013 - Friday MIRU Pollard E-Line Unit and Mast truck, MU GR/CCL/20' Gun. RIH, logged from 11,160' up to 10,900', correlated logs and dropped down to dersired depth. Perforated from 11,062' -11,082'. POOH, MU GR/CCL/ 18' gun, RIH, logged from 11,300' up to 10,700'. Correlated logs and dropped down to desired depth. Perforated 2nd set of holes from 11,044'-11,06.2'. POOH, RDMO E-Line Unit and equipment. Turned well back over to production. i Swanson River Unit Well: SRU 13-27 ACTUAL SCHEMATIC Actual Completion:5/10/2013 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL a 1 Size Type Wt Grade Conn. ID Top Btm 16'412 * 16" Conductor—Divento - - Surf 80' Depth A w 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' ,. 4 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 1 DWC/C HT 4.283" 10,793' 11,831' wa TUBING 10-3/4" ""' 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' X I i1/21r 4 JEWELRY DETAIL :i;i No. Depth ID OD Item kil 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd b 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 1 CP 3 4,462' 2.441" 4.625" GLV#5 2212psi 1 4 7,328' 2.441" 4.625" GLV#4 2066 psi 4 m i 5 8,925' 2.441" 4.625" GLV#3 1983 psi y4._ s:' 6 9,989' 2,441" 4.625" GLV#2 1923 psi V ` 7 10,736' 2.441" 4.625" GLV#1 Orifice ti 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 5 It I ",, 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer �f 10 _ 10,825' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 6 III i 11 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 i G2 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 c H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 — 8 a. 1 H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip _ 04/22/13 H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 9H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 7-5/8" • L0 W to 11-- ir 64 Li 41 1,� p G2 /Gr �) 4 ice, H3/H4 4 41* H12 H13 ' o Max deviation 21° '131,,,,y 6-3/4"Hole 5; Alio TD=11,835'MD-11,247'ND PBTD=11,751 MD-11,171'ND Downhole Revised:07/05/2013 Updated by STP 07/08/13 ib pF Tk yw'\�\\I%%ids, THE STATE Alaska Oil and Gas �� "'A °f LVKA ,cilse vat1on Commission Witt *ti GOVERNOR SEAN PARNELL 333 West Seventh Avenue OFS:N Anchorage, Alaska 99501-3572 ALAMain- 907.279.1433 Fax: 907.276.7542 Stan Porhola Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, Swanson River Unit 13-27 Sundry Number: 313-354 Dear Mr. Porhola: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, P;Xv) Cathy P Foerster Chair DATED this Z day of July, 2013. Encl. s R �`� ,�� RECEIVED STATE OF ALASKA �v ALASKA OIL AND GAS CONSERVATION COMMISSION JUL 0 8 2013 APPLICATION FOR SUNDRY APPROVALS �� 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrii ❑ Perforate New Pod ❑ Repair Well] Change Approved Program❑ Suspend❑ Plug Perforations ❑ Perforate❑ Pull Tubin(] Time Extension❑ Operations Shutdowi❑ Re-enter Susp.Wel ❑ Stimulate❑ Alter CasinEl Other. Install Capillary String E 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development ❑✓ • 212-181 ' 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20607-00 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO123A El River Unit(SRU)13-27 • Will planned perforations require a spacing exception? Yes 1:1 No 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399,A028406 Swanson River Unit/Hemlock Oil - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 11,835 ' 11,247 11,751 11,170 WA N/A Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi Intermediate 10,986' 7-5/8" 10,986' 10,474' 6.890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(R): See Attached Schematic See Attached Schematic 2-7/8" 6.4#/L-80 10,831' Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): AS-1X Ret Prod Pkr;N/A 10,786'MD-10,292'ND;N/A 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program n BOP Sketch n Exploratory n Stratigraphies Development n Service n 14.Estimated Date for 15.Well Status after proiosed work: 07/10/13 Commencing Operations: Oil ❑✓ . Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email sporholaathilcorD.corn Printed Name Stan Porhola Title Operations Engineer c Signature44-.---_pcat, Phone 907-777-8412 Date -0(F /3 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 31 ,36) El Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance Other: RBDMS JUL 13 2 Spacing Exception Required? Yes ❑ No o' Subsequent Form Required: /0 — / APPROVED BY /3 2 Approved by: 212(.44efi7COMMISSIONER THE COMMISSION Date: 7 .../1--LJ �a /3 Submit Form and Form 10-403(Revised 10/2012) Uefp( jIiJI Id or 12 months from the date of proval. Attachments' plicate " I-3 • 11 Well Prognosis Well: SRU 13-27 Hilcorp Alaska,Lb Date:7/08/2013 Well Name: SRU 13-27 API Number: 50-133-20607-00 Current Status: Cased Oil Producer Leg: N/A Estimated Start Date: July 10th, 2013 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-181 First Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228(M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: 1321814 Current Bottom Hole Pressure: 4,150 psi @ 11,057' ND Based on reservoir pressure samples Collected in open hole with formation testing tools in the H-13. Maximum Expected BHP: 4,150 psi @ 11,057' ND Based on reservoir pressure samples Collected in open hole with formation testing tools in the H-13. Max. Allowable Surface Pressure: —0 psi (Based on actual reservoir conditions and min water cut of 50% (0.385psi/ft) will balance reservoir pressure at 278 ft. ND. Brief Well Summary This well was drilled with the Doyon Arctic Fox,January—March 2013. The well was completed with the Williams 405 rig in March of 2013. The new completion did not allow for the perforation of one of the zones . and a new completion was ran in May 2013. The well is currently producing approximately 150 bbls of oil and 290 bbls of water per day on gas lift completion. The G-zone was perforated in early July 2013. Notes Regarding Wellbore Condition New completion ran in May 2013. Completion procedure: 1. MIRU Cap String Truck, PT lubricator to 3,000 psi Hi 250 Low. 2. PU 3/8"capillary string. RIH and set at+/-10,900'. 3. Set spool of remaining line near well. 4. Rig down Cap String Truck. 5. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic Swanson River Unit Well: SRU 13-27 ACTUAL SCHEMATIC Actual Completion:5/10/2013 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL ) 1 A tSize Type Wt Grade- Conn. ID- Top Btm 16" 2 '07 16„ Conductor—Driven to Surf 80' Set Depth y u 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' ii';j4' 'i 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' of P 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' TUBING 10-3/4" 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' .4 X ) 3 Mr i 4 l4 JEWELRY DETAIL ' No. Depth ID OD Item ; 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd Fi 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box ., -_ 3 4,462' 2.441" 4.625" GLV#5 2212psi 1'M i 4 7,328' 2.441" 4.625" GLV#4 2066 psi N 4 t! I 5 8,925' 2.441" 4.625" GLV#3 1983 psi �' 6 9,989' 2,441" 4.625" GLV#2 1923 psi ' �' 7 10,736' 2.441" 4.625" GLV#1 Orifice k' y i 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile o^, ka. 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 1 1 10 10,825' 2.313" 3.230" X-Nipple 4 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide PERFORATIONS � Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 11111 i G2 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 • 8 H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 . I I H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 9 ,k 0 H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 r ifx d 7-5/8" j, 1.1 11 'Lo o ,11--- 71 3 61 4 4 , 3d G2 ;-_, tti V' oit .or St to, H3/H4 lt "j H12 itt * H13 V v1R Max deviation 21' — 611410 *it 6-3/4"Hole 5" r 41 IS TD=11,835'MD-11,247'TVD PBTD=11,751 MD—11,171'ND Downhole Revised:07/05/2013 Updated by STP 07/08/13 Swanson River Unit Well: SRU 13-27 PROPOSED SCHEMATIC Proposed Completion PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 16' 2 16" Conductor-Driven to - - Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress _ 9.875" _ Surf 3,002' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' TUBING 10-3/4" 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' "J 3 le i sf JEWELRY DETAIL No. Depth ID OD Item s+ 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" _ Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 7,328' 2.441" 4.625" GLV#4 2066 psi 4 le 1 p. 5 8,925' 2.441" 4.625" GLV#3 1983 psi 6 _ 9,989' 2,441" 4.625" GLV#2 1923 psi `° 7 10,736' 2.441" . 4.625" GLV#1 Orifice t. "!+ 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 5 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer ' 10 _ 10,825' 2.313" 3.230" X-Nipple 4 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 441 6 1111 i 1.4 10 I PERFORATIONS .A ,21 Zone Top(MD) . Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date ` 7 801 i / G2 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC 07/05/13 H3/H4 11,160 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 44 8 H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 I I 1 H12 11,591' 11,609' . 11,023' 11040' 18' 04/05/13 9 ' H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 1 7-5/8" +� .10 td. it Capillary String Proposed InstallUP"— A! .41-m 3/8" 2205 Stainless Steel I'd Top Bottom '#°i MD 0' 10,850' 4$ ta TVD 0' 10,350' 041 411, ':4-41 , G2 4G2 VA 4 0444iri t' H3/H4 g 44* H12 4 H13 x' Max deviation 21° ak14'llt 7r":14 6-3/4"Hole TD=11,835'MD-11,247'ND PBTD=11,751 MD-11,171'ND Proposed Downhole Updated by STP 07/08/13 OF T�� \ \\ s THE STATE a OilandGas mw � /7, �'�'►' ALASKA Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Stan Porhola Operations Engineer Hilcorp Alaska, LLC a_ C3f 3800 Centerpoint Drive, Suite 100 3,f Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SRU 13-27 Sundry Number: 313-341 Dear Mr. Porhola: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 4 4n o •Si:04 sioner DATED this qday of July, 2013. Encl. „, c.,i, 5Sk 1‘)\("b ..... , 4,cv vi OF ALASKA ,, 1\ ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ;.'<C)("1:f ;t 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair Wel❑ Change Approved Program E Suspend❑ Plug Perforations❑ Perforate❑� Pull Tubin] Time Extension❑ Operations Shutdowt❑ Re-enter Susp.Wel ❑ Stimulate❑ Alter Cosine Other. ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development ❑� , 212-181 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20607-00 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO123A Swanson River Unit(SRU)13-27 Will planned perforations require a spacing exception? Yes ❑ No 0❑ 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399,A028406 Swanson River Unit/Hemlock Oil ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 11,835 - 11,247 . 11,751 - 11,170 - N/A N/A Casing Length Size MD TYD Burst Collapse Structural Conductor 80' 16” 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi Intermediate 10,986' 7-5/8" 10,986' 10,474' 6,890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(It): See Attached Schematic See Attached Schematic 2-7/8" 6.4#/L-80 10,831' Packers and SSSV Type: Packers and SSSV MD(t)and TVD(ft): AS-1X Ret Prod Pkr;N/A 10,786'MD-10,292'TVD;N/A 12.Attachments: Description Summary of Proposal 2 13.Well Class after proposed work: Detailed Operations Program n BOP Sketch n Exploratory n Stratigraphies Development[f Service n 14.Estimated Date for 15.Well Status after proposed work: 07/04/13 Commencing Operations: Oil Q Gas ❑ WDSPL ❑ Suspended E 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Pothole Email sDorholat hilcoro.corn Printed Name an Por ola Title Operations Engineer / Signature ` (iv6\.- Phone 907-777-8412 Date 1-7/1 3 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 313 _56// Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS JUL - 3 10' Spacing Exception Required? Yes ❑ No Fl ub•equent Form Required: I'6 -(to 41 APPROVED BY 2 Approved by: 11/ COMMISSIONER THE COMMISSION Date: 27.2 . /3^^ /'� A -2P Submit Form andIF /1Form 10-403(Revised 10/2012) Appr�lle�l RI 1 iNd(�_months from th date of approval. Attachme is !mate 0 .11 Well Prognosis Well: SRU 13-27 Hilcorp Alaska,LL, Date:6/27/2013 Well Name: SRU 13-27 API Number: 50-133-20607-00 Current Status: Cased Oil Producer Leg: N/A Estimated Start Date: July 4th, 2013 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-181 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907)331-8228 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907)229-4824 (M) AFE Number: Current Bottom Hole Pressure: 4,150 psi @ 11,057' TVD Based on reservoir pressure samples Collected in open hole with formation testing tools in the H-13. Maximum Expected BHP: 4,150 psi @ 11,057' ND Based on reservoir pressure samples Collected in open hole with formation testing tools in the H-13. Max. Allowable Surface Pressure: —0 psi (Based on actual reservoir conditions and min water cut of 50% (0.385psi/ft) will balance reservoir pressure at 278 ft. ND. Brief Well Summary �,�. This well was drilled with the Doyon Arctic Fox,January—March 2013. The well was completed with the �y Williams 405 rig in March of 2013. The new completion did not allow for the perforation of one of the zones ev 6 M84 and a new completion was ran in May 2013. The well is currently producing approximately 150 bbls of oil and re's' 290 bbls of water per day on gas li completion. Notes Regarding Wellbore Condition New completion ran in May 2013. Completion procedure: 1. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. 2. PU 2" 6 spf HC Wireline guns. • 3. RIH and perforate the following intervals. a. G-2: 11,044'—11,082' (38') b. Proposed perfs shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. 4. POOH and rig down E-line. 5. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic ii Swanson River Unit ' Well: SRU 13-27 ACTUAL SCHEMATIC Actual Completion:5/11/2013 PTD: 212-181 'Licari)Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL a ;-'1.4 � 1 — r L Size Type Wt Grade Conn. ID Top Btm 16" 2 r 16„ Conductor—Driven to - - - Surf 80' Set Depth � � 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' 'r li 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' TUBING 10-3/4" > r' 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' M 14 h 3 1 4 Jo JEWELRY DETAIL ' '0'4 No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box I` oaf 3 4,462' 2.441" 4.625" GLV#5 2212psi j / 4 At4 7,328' 2.441" 4.625" GLV#4 2066 psi 5 8,925' 2.441" 4.625" GLV#3 1983 psi 6 9,989' 2,441" 4.625" GLV#2 1923 psi 1' v 7 10,736' 2.441" 4.625" GLV#1 Orifice }' 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile ±! 5 Ult i a 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,825' 2.313" 3.230" X-Nipple 4 i4 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide ui PERFORATIONS P„ Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 1 7 MA i H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 oil H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip 04/22/13 `ti 8A' H12 11,591' _ 11,609' 11,023' 11,040' 18' 04/05/13 ", I I I ''' H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 9 ; i 7-5/8" 4. ! fe I „L0 tel. eiA ? 11' tJ a v. kn 74 11 Vi.t1 44 *41 H3/H4 • "I it Iv H12 at 4 H13 ?V 4' Max deviation 21' 6-3/4"Hole 5" A,., 'k i. TD=11,835'MD-11,247'ND PBTD=11,751 MD—11,171'ND Updated by STP 06/27/13 ii Swanson River Unit '' ' Well: SRU 13-27 PROPOSED SCHEMATIC Proposed Completion PTD: 212-181 Ililcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 16" 2 16" Conductor—Driven to - - Surf 80' Set Depth 10 3/4" Surf.Csg 45.5 L-80Buttress 9.875" Surf 3,002' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' a TUBING 10-3/4" 1 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' 3 JEWELRY DETAIL No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 8 4 7,328' 2.441" 4.625" GLV#4 2066 psi 5 8,925' 2.441" 4.625" GLV#3 1983 psi 6 9,989' 2,441" 4.625" GLV#2 1923 psi 7 10,736' 2.441" 4.625" GLV#1 Orifice 5 ( 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,825' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 6 • PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 G2 11,044' 11,082' 10,527' 10,561' 38' 6 2"HC Proposed I I H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 8 '` \ H12 11,553' 11,576' 10,988' 11,009' 23' _ 6 1-11/16"strip 04/22/13 L 1H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 9 11 H AA MiA {. H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 7-5/8"21177. • LO ,r;:44 11 G2 ' H3/H4 H12 H13 Max deviation 21° { 6-3/4"Hole 5„Q ' TD=11,835'MD-11,247'ND PBTD=11,751 MD—11,171'ND Updated by STP 06/27/13 w STATE OF ALASKA RECEIVED AL .,,KA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS ,,,iv 2 4 2013 .244.9.13 1.Operations Abandon Lf Repair Well Li/ Plug Perforations U Perforate U Other LJ A C'3 C C Performed: Alter Casing ❑ Pull Tubing 2 Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC • Development ❑., • Exploratory ❑ 212-181 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 50-133-20607-00 • 7.Property Designation(Lease Number): 8.Well Name and Number: A028399,A028406 Swanson River Unit(SRU)13-27 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Unit/Hemlock Oil • 11.Present Well Condition Summary: Total Depth measured 11,835 feet Plugs measured N/A feet true vertical 11,247 feet Junk measured 11,751 (cement) feet Effective Depth measured 11,751 feet Packer measured 10,786 feet true vertical 11,170 feet true vertical 10,292 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi Intermediate 10,986' 7-5/8" 10,986' 10,474' 6,890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.4#/L-80 10,831' 10,333'TVD Packers and SSSV(type,measured and true vertical depth) AS-1X Ret Prod Pkr 10,786'MD 10,292'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 236 0 230 1100 220 Subsequent to operation: 252 2159 285 1410 250 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development D • Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil E. Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-217 Contact Chad Helgeson Email chelgeson@hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature G /%y Phone 907-777-8405 Date S/7 j Form 10-404 Revised 10/2012 76- 5-g/13 RBDMSMAY 2 9 2013 Submit Original Only 4 Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00 212-181 5/5/13 5/11/13 Daily Operations: 05/05/2013 -Sunday MIRU Williams 405 WOR, set tank, pump, accumulator and associated equipment on herculite, bermed up around all equipment. Blew tubing and casing down to gas buster. 05/06/2013 - Monday Finished final RU. Set BPV, ND tree/NU BOP stack. Pulled BPV. Witness waived by Jim Regg, AOGCC 05/05/13 (250 low/3,000 psi high on BOPE and 250/1500 psi on the annular). Tested BOPE per BLM and AOGCC regs. 05/07/2013 -Tuesday Back lock pins and released hanged and packer. SOOH w/168 stands, 2 singles, 5 glv and 1 pup jnt with a x-nipple and reentry guide. SDFN. 05/08/2013 -Wednesday MIRU EL. RIH w/31' gun to 11,400' elm. Made a correlation pass to 11,000'. Placed guns on depth @ 11,188' to 11,219'. Fired guns and POOH. PU a 28' gun and RIH. Made a correlation pass from 11,320' to 11,050'. Placed gun on depth at 11,160'.to 14188'. Fired gun and POOH. RDMO EL. Prep rig to run completion. TIH w/168 stands, 2 singles, 5 glv, on-off tool/packer, x- nipple (RHCP set plug in X-nipple) and WLG. Hung tbg off and SDFN. 05/09/2013 -Thursday Set packer with 9,000# in compression down. Landed tbg in hanger. Prep to test TBG and CSG, dropped RHCP prong. Pumped 205 bbls down CSG. Circulated the air out and pressured up to 2,000 psi and leaked off. Pumped 12 bbls down the tbg and pressured up to 2,000 psi and leaked off. MIRU SL. RIH w/2"JDC and latched prong at 10,771' wlm. POOH w/prong. RIH w/2" GS and tag 10,773' wlm. Could not latch RHCP. POOH. PU a knuckle joint and 2" GS, RIH and tag @ 10,773'. Could not latch plug. POOH. RIH w/2.25" LIB and tag at 10,773'. POOH. Impression show bottom off plug (plug set in tubing upside down when run). SDFN. 05/10/2013 - Friday SOOH 168 stands and 2 singles. LD packer. PU a new packer and TIH. Started 10' above target depth. Worked free and set packer at 10,786'. Landed tbg hanger with 8,000 psi of compression. MIRU SL. RIH w/ px plug and set in x nipple at 10,825' wlm. PU a px prong and RIH an set in plug at 10,825'. RU pump and tested jug tested well to 3,000 psi for 30 mins. RIH and pulled plug and prong. RDMO SL. 05/11/2013 -Saturday Set BPV. ND BOP stack and NU PT. Tested tree to 5,000 psi. RDMO Williams WOR. ' Swanson River Unit SCHEMATIC Well: SRU 13-27 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL 1 k Size Type Wt Grade Conn. ID Top Btm 16" 2 16" Conductor—Driven to - - - Surf 80' y Set Depth w, 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' I eti 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,986' Y. 0 5" Prod Lnr 15 , L-80 DWC/C HT 4.283" 10,793' , 11,831' TUBING 10-3/4" x 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' t hal ,4` 1 3 .!i JEWELRY DETAIL '0 r No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box iu 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 i! 4 7,328' 2.441" 4.625" GLV#4 2066 psi 5 8,925' 2.441" 4.625" GLV#3 1983 psi 105 I A 9,989' 2,441" 4.625" GLV#2 1923 psi .) ! 7 10,736' 2.441" 4.625" GLV#1 Orifice 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 5 In i :f 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer )L 1 10 10,825' 2.313" 3.230" X-Nipple iri 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide % 6 i e PERFORATIONS I, Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 MRs 1 H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC 05/08/13 H12 11,553' 11,576' 10,988' 11,009' 23' 6 1-11/16"strip _ 04/22/13 8 H12 11,591' 11,609' 11,023' 11,040' 18' 04/05/13 i I ' I I H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 03/15/13 9 - f i 7-5/8" 4, II l:1.0 ► ,p'11 iiR LI Iii H3/H4 44 ' H12 it I H13 Vr Max deviation 21 '441 k Vii 5 6-3/4"Hole 5" r TD=11,835'MD-11,247'ND PBTD=11,751 MD-11,171'ND Updated by DMA 05/24/13 2\2—t%1 11 Lar, , Ellison Hilcorp Alaska, LLC Z2��0 GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8339 If aeons Ali ka_1.91.t: Fax: 907 777-8510 E-mail: lellison@hilcorp.com 04/15/13 91 To: AOGCC Cal C ` ' t Makana Bender f 333 W. 7th Ave. Ste#100eR,.: Anchorage, AK 99501 gat _ ! DATA TRANSMITTA SRU 13-27 Prints Dual Spaced Neutron Spectral Density Array comp Res 04-Mar-13 Dual Spaced Neutron Spectral Density Array comp Res 24-Feb-13 Circumferential Acoustic Scanning Tool Monocable SFT Sonic Porosity 04-Mar-13 Sonic Porosity 24-Mar-13 BHV 04-Mar-13 BHV 24-Mar-13 Acoustic Cement Bond Log CD: Final Well Data Log Data: See CD Final Survey data Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: (_,(1...) Date: 2 /\S ' AP '7 („,<OF \��I�i�,sT THE STATE Alaska Oil and Gas \ ----_;41-7.,k4 ofALA I�:A - Corkser vati©n Commission ' .„ GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF 4LASgP Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Chad Helgeson Operations Manager Hilcorp Alaska, LLC n U 1 ' 1 3800 Centerpoint Drive, Suite 100 O� Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SRU 13-27 Sundry Number: 313-217 Dear Mr. Helgeson: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, A Daniel T. Seamount, Jr. Commissioner 3rd DATED this day of May, 2013. Encl. RECEIVED STATE OF ALASKA MAY 0 2 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair WeG Change Approved Pray ram❑ Suspend❑ Plug Perforations❑ Perforate❑✓ • Pull Tubin] Time Extension❑ Operations Shutdowl❑ Re-enter Susp.Wel ❑ Stimulate❑ After Casing Other. ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development • 212-181 • 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service El6.API Number Anchorage,Alaska 99503 50-133-20607-00• 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C0123A ❑ Swanson River Unit(SRU)13-27• Will planned perforations require a spacing exception? Yes CI No 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399,A028406• Swanson River Unit/Hemlock Oil• 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): • 11,835 _ • 11,247 • 11,751 • 11,170 N/A Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,002' 10-3/4" 3,002' 2,998' 5,210 psi 2,480 psi - Intermediate 10,986' 7-5/8" 10,986' 10,474' 6,890 psi 4,790 psi Production Liner 1,038' 5" 11,831' 11,244' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size. Tubing Grade: Tubing MD(It): •See Attached Schematic See Attached Schematic 2-7/8" 6.4#/L-80 10,831' Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): AS-1X Ret Prod Pkr;N/A • 10,786'MD-10,292'ND;N/A 12.Attachments: Description Summary of Proposal Q• 13.Well Class after proprsed work: Detailed Operations Program n BOP Sketch n• Exploratory n Stratigraphies Development n• Service n 14.Estimated Date for 15 Well Status after proposed work: Commencing Operations: 05/06/13 Oil Q • Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: Mg" 3r z-c)/3 WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: q```) Y.,(tw..e-f•t- GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true arid correct to the best of my knowledge. Contact Chad Helgeson Phone: 907-777-8405 Email chelgesonchilcorp.com Printed Name Chad HelgesonlggeTitle Operations Manager Signature ��r 6s Phone 907-777-8405 Date 5-7q1)'J1 2 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3i" -2/ 7 Plug Integrity ❑ BOP Test 137 Mechanical Integrity Test ❑ Location Clearance ❑ Other: X 3000 /s:. eo P cs1- il` 1500 ia5c, Ann- �/ RBDMS MAY -6 201 Spacing Exception Required? Yes ❑ No17( Subsequent Form Required: 0 "'(101-1 APPROVED BY �/ Approved by. ( /� COMMISSIONER THE COMMISSION Date: .....5/3 �e slA A � �- •x'3 ��%7� SubmRFormand �� \.�Form 10-403(Revised 10/2012) Approtali�f t rlonth�From the date of approvaaaa��__ �/llttachments in Duplicate P� HL ; Well Prognosis Well: SRU 13-27 Hilcorp Alaska,LL. Date:5/1/2013 Well Name: SRU 13-27 API Number: 50-133-20607-00 Current Status: Cased Oil Producer Leg: N/A Estimated Start Date: May 6th, 2013 Rig: Williams 405 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-181 First Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824 (M) Second Call Engineer: Jason Ewing (907)777-8441 (0) (979)-777-4710(M) AFE Number: Maximum Expected BHP: 4,150 psi @ 11,057' TVD Based on reservoir pressure samples Collected in open hole with formation testing tools in the H-13. Max. Allowable Surface Pressure: 0 psi Field PW will be maintained at surface. fluid level will be maintained at surface for a static fluid gradient of 4,887 psi at bottom. Brief Well Summary This well was drilled with the Doyon Arctic Fox,January—March 2013. The well was completed with the Williams 405 rig in March of 2013. The new completion did not allow for the perforation of one of the zones. The well is currently producing approximately 120 bbls of oil and 126 bbls of water per day on gas lift completion. Notes Regarding Wellbore Condition Producing well that has a restriction in the tubing that does not allow perforating guns to run through tubing. resfr%Gf- �. Completion procedure: 1. RU slickline pressure test lubricator to 1,500 psi. 2. RIH and pull orifice valve from bottom GL Mandrel. 3. RD slickline 4. MIRU Williams 405 workover rig. 5. Circulate field PW through well. 6. Set BPV in tubing hanger, ND tree, NU 11" BOPE and test to 250psi low/3,000psi high, annular to 250psi low/1,500psi high (hold each valve and test for 10-min). Record accumulator pre-charge pressures. a. Notify AOGCC 24hrs in advance to witness test. b. Notify BLM 48 hrs in advance of BOP test. 7. Pull tubing hanger,1-latch and release packer. 8. POOH, rack back tubing string. After 300 joints, monitor and inspect tubing to troubleshoot tubing damage. 9. LD packer(send in for rebuild). 10. RU E-line, PU 3-3/8" HC guns, 6 spf. 11. RIH and perforate the following intervals. Well Prognosis Well: SRU 13-27 'Licari)Alaska,LL Date:5/1/2013 a. H-12: 11,555'—11,578' (23') b. H-10: 11,432'—11,449' (17') c. H-3/4: 11,160-11,219(59') d. Total of 99ft of perfs. 12. POH and rig down e-line. 13. RIH w/completion on 2-7/8" 8rd EUE tubing(mechanical packer and gas lift valves)as shown on proposed schematic, set packer at approx. 10,785 ft. a. Land tubing in hanger. Close the lockdown pins. Minimize compression to 2 ft(5,000#) by using the on/off tools as necessary. 14. Drop RHCP plug in well and test casing to 3,000 psi and tubing to 3,000 psi, chart for 30 min ea. 15. Set BPV, ND BOPS, NU Tree,test tree to 5,000 psi. 16. Pull BPV. RDMO workover rig and equipment. 17. Turn well over to production. 18. NU piping and flowlines. 19. Gas lift well, unloading fluid from well, SI well leaving gas lift pressure on well. 20. RU slickline, PT lubricator to 3,000 psi Hi 250 low. 21. RIH and pull RHCP prong and plug. 22. RD Slickline. 23. Start production Attachments: 1. Existing Well Schematic 2. Proposed Schematic 3. Williams BOP Schematic Swanson River Unit II SCHEMATIC Well: SRU13-27 PTD: 212-181 Ililcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL ;r 1 I Size Type Wt Grade Conn.BT L-80 ID Top Btm i� ; 2 16" Conductor—Driven to Surf 80' Set Depth _ _ 10-3/4" Surf.Csg 45.5 L-80 Buttress _ 9.875" Surf 3,002' 7-5/8" Intermediate 29.7 L-80 C _ 6.75" _ Surf 10,986' 5" Prod Lnr 15 DWC/C HT 4.283" 10,793' 11,831' TUBING 1O-3/4"G 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' JEWELRY DETAIL No. Depth ID OD Item L1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 17, 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box us 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 4 7,328' 2.441" 4.625" GLV#4 2066 psi 5 8,925' 2.441" 4.625" GLV#3 1983 psi i 6 9,989 2,441" 4.625" GLV#2 1923 psi ?•' 7 10,736' 2.441" 4.625" GLV#1 Orifice s� 5 iX 8 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile ,I al 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,826' 2.313" 3.230" X-Nipple `P i4 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 6 sio PERFORATIONS li ,, Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date Wil 7 H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 3/15/13 9 .V I I ;' I 7-5/8" ,, I $fir Lo ;42 ��11� V ,,, oil 2 44 Iv S 5.44 * 44 no 4 H13 yoll ' Max deviation 21' ` .�", " ' ••'1,4 6-3/4"Hole 5„f` .P ,” i r TD=11,835'MD-11,247'ND PBTD=11,751 MD—11,171'ND Updated by TDF 4/17/2013 Swanson River Unit ri I I PROPOSED Well: SRU 13-27 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL J i i Size Type Wt Grade Conn. ID Top Btm 16'Q 2 16" Conductor—Driven to - - Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,002' 7-5/8" Intermediate 29.7 L-80 Bit 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' TUBING 10-3/4" 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' 3 JEWELRY DETAIL No. Depth ID OD Item 1` 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 3 4,462' 2.441" 4.625" GLV#5 4 B 4 7,328' 2.441" 4.625" GLV#4 5 8,925' 2.441" 4.625" GLV#3 6 9,989' 2,441" 4.625" GLV#2 7 10,736' 2.441" 4.625" GLV#1 Orifice 5 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile 9 10,786' 2.500" 6.672" AS-1X Ret Prod Packer LI 10 10,826' 2.313" 3.230" X-Nipple I11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 6 • 01 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 H3/H4 11,160' 11,219' 10,631' 10,685' 59' 6 3-3/8"HC May 2013 H10 11,431' 11,449' 10,877' 10,894' 17' 6 3-3/8"HC May 2013 8 H12 11,555' 11,578' 10,990' 11,011' 23' 6 3-3/8"NC 4/22/13 I fl I t, H12 11,555' 11,578' 10,990' 11,011' 23' 6 3-3/8"HC May 2013 9 } H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 3/15/13 � '_ In 7-5/8" ly 10 4 •5, 11 ;. 1 rA •'1 6 ft H3/H4 H10 • H12 H13 Max deviation 21 ' 6-3/4"Hole 5"'�w Vg TD=11,835'MD-11,247'ND PBTD=11,751 MD—11,171'TVD Updated by DMA 05/02/2013 • II + Swanson River SRU 13-27 04/30/2013 Ilih,.rlt %Liam 1.1.1. Swanson River SRU 13-27 WlIliams BOP 2013 IYIrit in rrti rrtiIttr Vf ,- 3. 6' Shaffer 11' 5M f171(11Ifjirt-tilt 0 0 Shaffer LWS 0 — 2.75' 11"SM i / 2 1/16 10M Choke and Kill e • a — Valves I 1191PAP1 ISI -----,4- •� 2.00' 1 0 _ riot m 11"5M — •• 1. Jf'I}f 1 O ■1u1.1111.111. i1 c a o = nl•—I.I _ ii—UI O. I r 757, ! ' '1 i _ rft) ' It.:$3,.. : ! * r — — , c,,,,„ -i, , .„ ; a3t'i! �i �ii■_ ii iiii 1 ill : i pi i 6 II MI 1 _" r 1 rilliq44:"14411.11.1411'-' J Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Friday, May 03, 2013 9:08 AM To: 'Chad Helgeson' Cc: Donna Ambruz Subject: RE: SRU 13-27 10-403 - PTD#212-181 Chad, You have verbal approval to move onto well SRU 13-27 with the Williams WO rig and perform the operation as outlined in the sundry application you forwarded yesterday. Additional perforations (H-10 H-12)that you proposed are also approved and be covered in the same 10-404 report for the RWO. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Chad Helgeson [rra�ito;cheigeson«h icorp.coorn] Sent: Thursday, May 02, 2013 1:08 PM To: Schwartz, Guy L (DOA) Cc: Donna Ambruz Subject: SRU 13-27 10-403 - PTD#212-181 Guy, Attached is the procedure that we discussed earlier about pulling the tubing to re-perforate and replace what we expect is some corkscrewed tubing. If possible we would like to start this work this weekend and if we could get a verbal approval to do this work as we discussed, it would be greatly appreciated. Last week we added some perfs in the H12 zone with 1-11/16" strip guns. Can I cover those perf adds in the Hemlock with the 404 that will be necessary for this work,or do we need to submit a 404 for the perf adds through tubing and then the completion of this work with the rig? We will be reperfing with the bigger guns during this work in the same interval. Thanks a bunch. Chad Helgeson Operations Manager North Kenai Asset Team Hilcorp Alaska, LLC Office: 907-777-8405 Mobile: 907-229-4824 1 STATE OF ALASKA ALA_ .,OIL AND GAS CONSERVATION COMI‘..._JION I WELL COMPLETION OR RECOMPLETION-REPORT AND LOG la.Well Status: Oil ❑� Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20MC 25 10520MC 25.110 Development EExploratory El GINJ ❑ WINJ ❑ WAG ❑ , WDSPL ❑ No.of Completions: Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5.Date Comp.,Susp.t or ../ 12. Permit to Drill Number: IHilcorp Alaska,LLC Abend.: 3618/2013 212-181 r3.Address. 6.Date Spudded: " r; 13 API Number: kZS' 3800 Centerpoint Drive,Anchorage,AK 99501 1/27/2013 50-133-20607-00 4a. Location of Well(Governmental Section): 7. Date TD Reached: 14.Well Name andNumber: l[ 2rt5�'7C tC�-! Surface: 780'FNL,651'FEL,Sec 33,T8N, R9W,SM 3/4/2013 ..� oldetna Crook Unit(SRU)13-27 Top of Productive Horizon: 8. KB(ft above MSL): 182.6 15. Field/Pool(s): /0 c•21• i '3 172Z FSL,415'FWL,Sec 27,T8N, R9W,SM,AK GL(ft above MSL): 164 Total Depth: 9. Plug Back Depth(MD+TVD): Swanson River Field/Hemlock Oil 1977'FSL,602'FWL,Sec 27,T8N, R9W,SM,AK 11,751'MD; 11,171'TVD 4b. Location of Well(State Base Plane Coordinates, NAD 27): 10.Total Depth(MD+TVD): 16. Property Designation: Surface: x- 347031 y- 2465662 Zone- 4 11,835'MD, 11,247'TVD A028399,A028406 TPI: x- 348125.7 h y- 2468158.74 Zone- 4 11.SSSV Depth(MD+TVD): 17. Land Use Permit: Total Depte:' fx- .OA y- 2468411.38 Zone- 4 N/A N/A 18. Directional Survey: Yes E No ❑ 19.Water Depth, if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) N/A 21. Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071). 22.Re-drill/Lateral Top Window MDITVD: Please see attached list of logs obtained during operations. N/A 23. CASING,LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT :CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED I16" 109 X-56 Surf 80' Surf 80' N/A None 1 10-3/4" 45.5 L-80 Surf 3,002' Surf 2,996' 13-1/2" 954 sx 7-5/8" 29.7 - L-80 Surf 10,986' Surf 10,474' 9-7/8" 1683 sx 5" 15 L-80 10,793' 11,831' 10,298' 11,243' 6-3/4" 191 sx i I 24.Open to production or injection? Yes ❑✓ No ❑ 25. TUBING RECORD If Yes, list each interval open(MD+TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 2-7/8" 10,831' 10,333' H-13: 3-3/8"@ 6spf 11,612'(MD)to 11,631'(MD)/11,042'(TVD)to 11,060'(TVD) 26. ACID,FRACTURE,CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes❑ No Q ''„�.'' LliKLi RECEIVED DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED ' APR 19 2013 v i a _. - . AOGCC 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 3/20/2013 Gas Lift jDate of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 11 3/22/2013 6 Test Period . ..0. 68.5 77.5 0 0 1131 +Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): +Press. 175 910 24-Hour Rate 274 310 0 25.2 128. CORE DATA Conventional Core(s)Acquired? Yes ❑ No E Sidewall Cores Acquired? Yes ❑ No❑✓ . I If Yes to either question,list formations anJ intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. i 1 R BDMS APR 2 2 zpi \1 Form 10-407 Revised 10/2012 CONTINUED ON REVERSE 572./3 Submit original only 51.6 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? -'1 Yes ❑ No If yes, list intervals and formations tested, • I briefly summarizing test results.Attach separate sheets to this form,if needed, I Permafrost-Top and submit detailed test information per 20 AAC 25.071. Ir'ermafrost-Base Sterling 86 3,204'-3,348' 3,200'-3,343' Water Tyonek D1 Coal 5,792'-5,819' 5,664'-5,690' Water,Gas Tyonek 64-5 Sand 6,563'-6,590' 6,391 -6,416' Gas,Water Tyonek G2 Sand 11,026'-11,107' 10,511'-10,583' Water,Oil Top Hemlock 11,117'-11,136' 10,592'-10,610' Oil ✓ Hemlock H3 Sand 11,159'-11,209' 10,630'-10,676' Oil Hemlock H10 Sand 11,433-11,515' 10,879'-10,954' Water,Oil Formation at total depth: 1;21. List of Attachments: 1:=.2. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Luke Keller 907-777-8395 Email: Ikeller(c�hilcorp.com Printed Name: Luke Keller Title: Drilling Engineer 1 Signature: Phone: 907-777-8369 Date: 4/18/2013 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1 b: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval) Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23. Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed tor separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25 071. Form 10-407 Revised 10/2012 14 SRU 13-27 LOG SUMMARY Swanson River UnitWell: SRU 13-27 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 1. Formation Log MD 2" & 5" 2. Formation Log TVD 2" 3. LWD Combo Log MD 2" 4. LWD Combo Log TVD 2" 5. Drilling Dynamics MD 2" 6. Drilling Dynamics TVD 2" 7. Gas Ratio Log MD 2" 8. Gas Ratio Log TVD 2" 9. Dual Spaced Neutron Spectral Density Array comp Res 04-Mar-13 10. Dual Spaced Neutron Spectral Density Array comp Res 24-Feb-13 11.Circumferential Acoustic Scanning Tool Monocable 12.SFT 13.Sonic Porosity 04-Mar-13 14.Sonic Porosity 24-Mar-13 15. BHV 04-Mar-13 16. BHV 24-Mar-13 17.Acoustic Cement Bond Log Updated by TDF 4/18/2013 Swanson River Unit II SCHEMATIC Well: SRU 1327 PTD: 212-181 Hilcorp Alaska,LLC API: 50-133-20607-00 KB-THF: 18.6' CASING DETAIL t, 1 Size Type Wt Grade Conn. ID Top Btm 16' 2 16„ Conductor—Driven to Surf 80' Set Depth 10-3/4" Surf.Csg - 45.5 - L-80 - L-80 Buttress 9.875" Surf 3,002' 7-5/8" Intermediate 29.7 BTC 6.75" Surf 10,986' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,831' t : +. TUBING 10-3/4"41 fi 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,831' 1° 3 it u JEWELRY DETAIL i No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 22.85' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 3 4,462' 2.441" 4.625" GLV#5 2212psi 4 7,328' 2.441" 4.625" GLV#4 2066 psi 4 4 5 8,925' 2.441" 4.625" GLV#3 1983 psi t" 6 9,989' 2,441" 4.625" GLV#2 1923 psi 7 10,736' 2.441" 4.625" GLV#1 Orifice 8 10,784' 2.313" 6.250" T-2 On/Off tool with X-Profile i. 5 IS I '' 9 10,786' 2.500" 6.672" 7-5/8"24-29.7#AS-1X Ret Prod Packer 10 10,826' 2.313" 3.230" X-Nipple 11 10,831' 2.500" 3.690" Wireline Re-Entry Guide 3 6 PERFORATIONS '9 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 a 1 of H13 11,612' 11,631' 11,042' 11,060' 19' 6 3-3/8"HC 3/15/13 10, 8 , ,# 9 I I; 1 J' II r° 7-5/8" 4$' 3' .1/ ot,� a rr` . H13 4'111, Ittti l' Max deviation 21 • 6-3/4"Hole 5" gi, ' TD=11,835'MD-11,247'TVD PBTD=11,751 MD-11,171'TVD Updated by TDF 4/17/2013 Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00-00 212-181 1/22/13 Daily Operations: '41140'i44' ',d,�� ,iii111411111111Iii 1/23/2013 Wednesday Mobilizing and rigging up. 1/24/2013-Thursday Mobilizing and rigging up. 1/25/2013-Friday Mobilizing and rigging up. 1/26/2013-Saturday PJSM at crew change. Cont to mix spud mud. Start loading pipeshed w/BHA tools. Weld 2" nipple on riser for stand pipe bleeder,weld eyes on riser for chain binders, cut out grating for mousehole and install. Load 25 jnts HWDP in shed and strap same. Install wear ring (14" ID). Turn kelly hose on top drive, PU and rack back 70 jnts 5" using 2.35" drift on skate. PU 25 jnts HWDP and jars, rack back in derrick. Held PJSM/spud meeting with rig crew, DD and MWD, loggers. Install KatchKan and 4"valves on conductor, install bleeder hose, prep handling equipment to PU BHA. Stage heaters at cuttings box and water tank for spud. PU rack back flex DC's, PU motor w/1.10 deg bend, MU NM stab, pony DC, MU 13.5" MXL-1X bit jetted w/1x14 and 3 x 16 f/0.7394 TFA, 9' bit to bend, MU MWD and scribe/orient same. Fill conductor with spud mud and check for leaks. Drill F/78'to 136'with 400 gpm,40 rotary rpm and 2k to 4k torque. Circulate hole clean, pull 1 stand HWDP and rack back, Lay down XO and run 1 stand of 8" NM flex drill collars.Wash down to 101. ; Drill F/136'to 280' at 860 psi,400 gpm,40 rotary rpm. 1/27/2013-Sunday POOH 1 stnd, MU jars, RIH. Cont drilling f/280't/555', 7K wob, 31 rpm at 8,307 ft/lbs on bott torque, 575 gpm at 1550 psi. Cont drilling f/555't/822', 7K wob, 60 rpm at 1,500 ft/lbs on bott torque, 607 gpm at 1802 psi, off loaded 76 jnts of 10-3/4" casing, rack and tally same. Cont. drilling f/822't/986', 7K wob, 60 rpm at 2,100 ft/lbs on bottom torque, 621 gpm at 1,954 psi. CBU x 2, rotate and reciprocate f/short trip. Monitor Well POOH wet F/985'to 861'. Blow down Topdrive. Continue trip out to 681'. Proper hole fill and no over pull, monitor well. Trip back in T/925', Kelly up and wash and ream to Btm @ 985' No Fill on BTM. Drill F/985'to 1,307' MD, Running 5k to 6k wt, 610 gpm, 1,950 psi, 2,500 ft/lb Tq. Drilled a total of 1,027' in 16.5 on btm hrs= 68'/hr. Average ROP for the full 24 hrs=42'/hr. 1/28/2013- Monday Cont. drilling 13.5" surface f/1,301'to 1,489', 8K wob,80 rpm at 2,200 ft/lbs, 600 gpm at 1,850 psi, up wt 80K, dwn wt 78K, rot wt 80K. CBU twice at 600 gpm - 1,740 psi until clean returns at shakers. Blow dwn topdrive, POOH f/1,489'to 988'w/no hole issues. RIH f/988'to 1,489'. Cont drilling f/1,489'to 1,994', 8K wob, 80 rpm at 2,800 ft/lbs, 625 gpm-1,990 psi. CBU twice at 613 gpm-2,098 psi until clean returns at shakers. PJSM for trip. Trip out wet F/1,995'to 1,683', blow down topdrive. Continue short trip out to 1,490' hole took proper fill with no overpull. Monitor well. Trip in F/1,490'to 1,935', Kelly up and wash and ream to btm @ 1,995, No fill. Drill F/1,995'to 2,439' with 10k wt, 3,800 ft/Ib, pumping 220 stks @ 2,120 psi. This assembly drilled 1,132' in 13.1 on btm drilling hrs for an average ROP of 86'/hr. Drilling 1,132' in a full 24hrs is 47'/hr. 1/29/2013-Tuesday Cont. drilling 13.5" surface f/2,443'to 2,501', 10K wob, 615 gpm at 2,160 psi, 80 rpm at 3,600 ft/lbs torque on bottom, up wt 106K, dwn wt 99K, rot wt 109K. CBU at 615 gpm-2,080 psi, check for flow, blow dwn top drive f/short trip. POOH f/2,501'to 1,996', check for flow, RIH f/1,996'to 2,501', no issues or fill. Cont. drilling f/2,501'to 2,655', 10K wob, 615 gpm at 2,150 psi, 80 rpm at 3,500 ft/lbs on bott torque. Drill F/2,655'T/3,014'wob 10/12, p/u 119k, s/o 115, rot wt 109k,torq 3.9 on bottom, 3.6 off bottom, 2,300 psi on bott, 615 gpm, motor hrs 59.2,jar hrs 40.8 ADT 15.4 hrs, CBU X 2 @ 615 gpm,w/2,200 psi. POH F/3,014'T/2,693', pump dry job, blow down TD, continue trip out t/257'. Trip in hole F/257'T/3,014'. Circulate and condution mud injected 584 bbls drilling fluds Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00-00 212-181 1/22/13 Daily Operations: 1/30/2013-Wednesday Continue CBU increasing pump rate to 650 gpm-2,450 psi rotate and reciprocate. Pumped 32 bbl hi-vis nut plug sweep with no increase in cuttings. LD 15' pup jnt, POOH f/3,009'to 2,756'. Pump 20 bbl dry job. Blow down topdrive. Continue POOH f/2,756'. L/D BHA#1, bit graded at 1/1 (worn teeth). Clean and clear rig floor. BOLD's and pull wear bushing. Dummy run 10.75" hanger. C/O bails on topdrive, R/U casing tools, R/U fill up hose, stage centralizers, prep XO/floor valve. M/U shoe track, check floats (good) and install 2 bowsprings on shoe track. Continue P/U. RIH w/10 3/4"45.5#L- 80 BTC casing to 3,001', installing 1 bowspring every other joint up to 300'. Ran total 73 jnts w/shoe set at 3,001'top of float collar at 2,914'.Top filled casing every 10 jnts. CBU at 1,432' and 2,463'. G&I injected 540 bbls of slurry and flushed w/70bbls water. 1/31/2013-Thursday M/U circ swedge and circ hose. Start circ at 182 gpm-340 psi, recip casing up wt 155K, dwn wt 112K. Prep pump unit, load plugs in head, pull mousehole. Remove swedge and hose. M/U plug launcher, cont circ casing. M/U plug launcher and hardline. Loaded lines with 5 bbls water and checked for leaks. Pressure tested lines at 1,000 low 3,500 high for 3 minutes each. Rig pumped 69 bbls 10ppg MudPush II at 4.3 bpm and shut down. Dropped bottom plug and pumped 255 bbls (585 sx) 12ppg Class A lead cement at 5 bpm, followed by 80 bbls (369 sx) 15.4ppg tail cement at 3.3 bpm. Dropped top plug, RIG displaced with 272 bbls 10.4 ppg Spud Mud at 6.9 bpm, slowing to 2 bpm with 10 bbl to go. Bumped plug and held 1,300 psi (FCP of 1146 psi)for 3 minutes, bled off and floats held. Had 69 bbls MudPush. MudPush II returns to surface and 159 bbls 12ppg lead cement to surface. Took all cement returns to cellar box, obtained 2 samples of cement returns prior to bumping plug and 2 samples from mixing tub. Mix water temp 76 deg. Pumped 70%excess on both lead and tail. Had full returns throughout the job. Reciprocated string 2 x per minute throughout the job. Up wt 155K,dwn wt 95K at time of landing hanger. Rig down. CIP at 14:30 hrs, 1-31-13. Flush surface lines and equipment, clean cement out of cellar, remove plug launcher. Pull landing jnt, M/U packoff tool, install packoff in csg head. L/D landing jnt, cont cleaning ✓ cellar box, C/O bails, load BHA in pipeshed. Continue cleaning pits and cuttings box and ship to G&I. N/D riser. N/D drlg T, remove drip pan, bell nipple, remove riser, remove ODS,sub beam.Set well head. N/U head, inject plastic packing in pack off,test void @ 250 lo/3,000 hi for 10 min each. Install test plug, n/u bop's. Injected 552 bbls driling fluid and 70 bbls water. 2/1/2013-Friday Continue N/U 11" 5K BOP'sillow riser and flow line. Continue cleaning pits and mix mud. Have two BLM reps and two AOGCC reps on location to witness BOP testing. M/U test jnt,TIW and dart valves, attempt to shell test stack. Gland nut leak.Tighten all gland nuts, install test jnt and attempt low psi tests on annular,VBR's and lower 5" rams, connection leaking on test jnt. Pull jnt, re-torque connections, install test jnt.Test lower rams and dart valve,test annular,attempt test on VBR's. No test, pull test jnt, open doors, inspect VBR'S, no visable sign of damage, change out upper seals, retest, no test. Open ram doors, change out VBR packing, retest,test no good, change out wear plate and seals in upper ram cavity,test no good, change out 2-7/8"X 5"VBR's w/5" rams, re test upper rams-test no good. Injected 1862 bbls drilling fluid, and 70 bbls water. 2/2/2013-Saturday Continue to change out BOP ram wear plate and o-rings. Close doors and tested rams,TIW and choke valves at 250/4,000 psi at 10 min each. BOP test complete had 2 F/P. R/D test equip,set wear bushing and RILD's. Blow dwn lines, drain degasser. P/U RIH 5" DP from pipeshed to 2,205'. CBU to condition 10.5 ppg spud mud in hole. POOH rack back stands DP in derrick. Repair clutch handle on drillers console. Continue POOH rack back stands DP in derrick. M/U BHA#2 (drill out assembly), PU single in hole 66 jnts 5" DP f/pipeshed.Tagged cement @ 2,913', p/u 105k, dwn 90k. Circulate bottoms up, mud wt in and out 9.7,40 visc. Rig up and test casing @ 1,500 psi f/30 min,test good, rig dwn test_eq,u.ip Drill shoe track F/2,913' 2/3/2013 -Sunday Drill wiper plugs,float collar,shoe track,shoe, make 20' new hole to 3,034'. CBU to clean hole,swap hole over to 11.5ppg 6% KCL PH/PA mud. Pull bit into casing. R/U Doyon injection pump, perform FIT to 315 psi (13.5 emw) on chart f/10 min. Wash dwn to 3,034',drill f/3,034'to 3,124', 12K wob, 500 gpm-1200 psi, 90 rpm at 2700 ft/lbs torque on bottom, up wt 107K, dwn wt 100K, rot wt 105K,ADT 2.6 hrs. CBU at 500 gpm-1200 psi, check for flow. Trip out of hole, lay down drill out assembly. Pick up BHA#3, dirictional assembly, shallow test MWD.Trip in hole T/2,914', rotate through float collar, continue tripping in hole to 3,123' rotate and ream last stand down. Drill F/3,123'T/3,160'-475 gpm, 1700 psi, p/u 110, s/o 100, rt wt 105 wob 2/5k. Injected 401 bbls drilling fluid, 75 bbls water. 2/4/2013-Monday Continue drilling 9-7/8" intermediate hole section f/3,160'to 3,688', 10K wob,495;gpm-1620 psi, max gas 268. CBU to clean hole for wiper trip. Wipe hole from 3,688'to 3,130',flow check, RIH f/3,130'to 3,688'. Great cond. Continue drilling f/3,688'to 3,980',500 gpm, 2,100 psi, 8k torq on bott, 3.8 off,3.8k off, 5k wob, p/u 129k, s/o 117k, rt wr 124k,ADT 4.1, AST 2.4.ART 1.7. Rotate and slide F/3,980'T/4,260', p/u 139k, 121k, psi on bott 2,550 psi off bott 2,000, 531 gpm,total motor hrs,22,total bit hrs 22,total hrs on jars 56. Injected 712 bbls drill fluids, 70 bbls water, processed 100 bbls cuttings from cell. 2/5/2013-Tuesday Continue drilling 9-7/8" hole section f/4,260'to 4,576', 10K wob, 496 gpm at 2116 psi; 80 rpm at 8900 ft/lbs on bott torque, +/- 100 ft/hr ROP.ADT 4.4 hrs,AST.4 hr, ART 4 hrs, 20.5 hrs on bit, 64.3 hrs on jars. Continue drilling F/4,576'T/ 4881',wob 8/18k,gpm 492, psi on 2200, off 2140;80 rpm,trq on 6.2k, off 5.5k, p/u 147,s/o 128k, rt wt 137k,ADT 3.9, AST.9. Continue drilling F/4,727'T/4,881',508 gpm, 2200 psi on bott, 2120 off, 80 rpm,trq on bott. 4.8,trq off 3.7,wpb 10/15k, p/u 148k,s/o 130k, rt wt 140k;ADT 5.3,ART 5.3,AST 0, hrs on jars 73.5, circ hrs on motor 40.5. Continue drilling F/4,881'T/5,010',gpm 512, on bott psi 2280,wob 10k,trq on bott; 3.6,80 rpm, p/u 150,s/o 135, rt wt 140,total bit hrs 36.2, motor hrs 46.0;jar hrs 66.8. 7501/24 hrs=31.25 Ave ROP. Injected 583 bbls drilling fluids and 72 bbls water. P Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00-00 212-181 1/22/13 Daily Operations: 2/6/2013-Wednesday Drill 9-7/8" Intermediate Hole section from 5,010'to 5,202'. CBU @ 12.6 bpm, 2550 psi. Pump up survey. Flow check well, (good). POOH (5) stands. Pump slug. Blow Down Top Drive. UP 155k, DN 148, R 135k. Continue POOH f/4,887'. Pulled 20k over @ 4,458' &4,090'. 30k @ 4,015' & 3,960',3,926' 3,896'-3,880'. Pulled 45k @ 3,836' &3,778'. MU TD and attempt to pump past 3,778'. Establish rotation. Back Ream f/3,786't/3,750'. Stabilizer wiped obstruction @ 3,749'. Straight pull f/3,750'to Casing Shoe @ 3,001'. 40k overpulls @ 3,720' @ 3,647'. Hole in good condition f/3,550'to Shoe. 15k over pulls encountered as Stab& Bit entered Casing Shoe, indicating Clay Packed from Trip out of hole. Worked all tight spots as necessary to pass freely. Well took 15.1 bbls over Calc. Displacement on trip to Shoe. MU TD and CBU to clear Well Bore. Reciprocate bit slowly outside of casing. Service Rig. Change Saver Sub on TD. Change DWKS Engine Oil. Finish changing Liners in Pumps f/6"to 5". TIH from Casing Shoe @ 3,001', wash and clean out tight spot, @ 4,598'. Continue trip in hole to 5,202'. Drill F/5,202'T/5,253', 500 gpm, 2,320 psi, 70 rpm, 4/8k trq, 2/5 wob, p/u 155k s/o 140k, rt wt 143k, ADT 1,ART 1 AST 0 totoal hrs on jars 73.7. Continue drilling F/5,253'T/5,485', 530 gpm, 7 wob, 2,600 psi,torq off bott 4.7, 70 rpm, p/u 160,s/o 140, rot wt 145, Adt 4.8,total ADT 16.5 hrs;total hrs on bit 47.9, hrs on jars 78.5. 2/7/2013-Thursday Drill 9-7/8" Intermediate Hole section f/5,482't/5,804'. Penetrated D1CT Coal @ 5,792' UP 168k, DN 145k, R 156k, 12.2 bpm, 2,450 psi, 60 RPM,4700 tq. CBU @ 5,804'to clear cuttings f/Annulus prior to drilling coal. Reduce pump rate to 10.5 bpm, 1,950 psi. Control drill D1 Coal &56-9 Gas Sand ;f/5,804't/5,898'. Top of 56-9 Sand drilled @ 5,824', bottom @ 5,872' 380 units max gas. Increase Pump rate t/12.2 bpm. Continue drilling f/5,898't/6,085',gpm 510, 2,700 psi on bott. 2,600 off, 60 rpm,trq on 8.8,trq off 7.0,wob 8k, p/u 178k, s/o 149k, rt wt 163k,ADT 4.5,AST 0.0. Continue Drilling F/6,085'T/6,212', wob 7/8k, 60 rpm, 2,650 psi, 519 gpm, p/u 178k, s/o 160k,ADT 2.8 hrs. Circulate bottoms up@ 6,212'. Shoe trip F 6,212'T/ 5,202', p/u 180k,s/o 140k, no over pull on trip out. Injected 607 bbls drilling fluid, 72 bbls water, 1 load cutting f/cell. 2/8/2013 - Friday TIH from Short Trip to 6,213'. MU Top Drive and break circulation. Drill 9-7/8" Hole from 6,213'to 6,419'. 34.3 ft/hr ave ROP. Drill 9-7/8" Hole f/6,419't/6,660'. 40.1 ft/hr ave ROP. Short slides as necessary to maintain course. Drilled Gas Sand @ 6,550'to 6,592' MD, 6,380'to 6,418'TVD. Drill 9-7/8" Hole from 6,660'to 6,760', 500 gpm, 2,900 psi, 65 rpm,torq 4,7. p/u 190k,s/o 160k,tt wt 169k,total hrs on jars 10.8, bit hrs 76.5,ADT 8.3 hrs,AST 3.6 hrs. Continue drilling F/6,760'T/6,873', gpm 500,wob 12k, psi 2,940,torq on bott 7.5k,trq off bott 6.5, p/u 192k,s/o 163k, rot wt 170k. Injected 1,173 bbls drilling fluid, 73 bbls water. 2/9/2013-Saturday Drill 9-7/8" hole f/6,873't/7,000'. UP 197k, DN 165k, R 175k, 12 bpm =2,750 psi. 65 RPM, 7,500 TQ, 10-18 WOB. (127 ft @ 21.1 ft/hr). Drill 9-7/8" hole f/7,000't/7,224'. (224 @ 34.5 ft/hr)ADT 4.5 hrs, AST 0.0 hrs jar hrs 115.1, Bit hrs 92.1 CBU. Flow check Well (good). Stand back(5) stands. Pump Slug. ; Short Trip f/7224 t/Casing Shoe @ 3001. pull 10/40 over f/6740 T/5840' ;work through tight spots, p/u 197k,s/o 163k. Service top drive, blocks, crown sheaves,draw works, inspect brakes, cut drilling line. Trip in hole F/3,001' p/u 94 jts f/pipe house,trip in to bottom F/derrick. Injected 809bbls drilling fluid, & 72 bbls water, G & I down F/11:00 am T/00:01. 2/10/2013-Sunday TIH from Short Trip picking up singles to 5,963'. Continue TIH w/stands f/5,963'. Set down @ 7,143'. MU TD and Brk Circ. Wash and Ream f/7,120'to 7,224' (TD). Lower hole appeared to be swelling. Minimal fill on bottom. Load pipe w/High Vis Sweep. Make Connection. Drill 9-7/8" hole f/7,224't/7,286'. Hole unloaded a good deal of cuttings prior t/BU. Minimal increase in cuttings/cavings when sweep returned. Hole taking 2-3 bph. Continune drilling f/7,286't/7,565'. Top of HP Gas Sand (no sand ) gpm 500, psi 3,080 on bott, 2,800 off, 70 rpm, 9.5k trq on bott,7.4k off, p/u 214k, s/o 170k, rt wt 185k. CBU @ 505 gpm, 2,875 psi, check chlorides 27,000. Continue drilling F/7,565'T/7,641', 500 gpm, 2,950 psi on bott, 2,780 psi off, 65 rpm,trq on bott 7k,trq off 5k, p/u 205k,s/o 170, rt wt 185k,ADT 11.5,AST 0.0, HRS on bit 103.6, HRS on jars 126.6, HRS on motor 132.7. Continue drilling F/7,641'T/7,854',gpm 503,wob 15k, SPP 3175,trq on bott 8k, rpm 70, p/u 215k, s/o 170, rt wt 190k ADT 16.4 hrs,Total bit hrs 108.5,total hrs on motor 138.3,total hrs on jars 131.5 G&I injected 0 fluids. 2/11/2013- Monday Drill 9-7/8" hole from 7,854'to 7,991'. UP 222k, DN 175k, R 195k, 12 bpm =3000 psi, 8,700 tq @ 60 RPM off Btm. Continue drlg.f/7,991'to 8,233'. Intermittent Coal stringers w/max gas of 969 unit CBU. Pump up Survey. Record SPRs. Flow check Well. Short Trip from 8,233'to 6,784', work through tight spots @ 7,620', 7,060', 7,038', 678, RIH F/6,784'T/7,340', ream thru tigh hole @ 7,340', continue TIH t/8,236', 900 units gas on bottoms up f/short trip. Drill F/8,236'T/8,247',gpm 500, trq on bottom 10.3,trq off 8.4, SPP 2960, RPM 60, p/u 226k, s/o 180k, rt wt 196k,ADT 6.2,ART 5.3,AST 0.9,Jar hrs 141.8, Bit hrs 119.7. Continue drilling F/8,247'T/8,315', 514 gpm, 3,180 spp,trq 9k, 60 rpm, p/u 230k, rt wt 200k,ADT 3.9 hrs,AST 1.2, Bit hrs 123.5, mtr hrs 158.7,jar hrs 144.2. Injected 720 bbls drilling fluids &72 bbls water. 2/12/2013-Tuesday Drill 9-7/8" hole from 8,315'to 8,433' pumping 507 gpm @ 3108 psi,WOB 18k,Tq 10.5 ; Drill F/8,433'to 8,460' with 475 gpm @ 3,320 psi,WOB=20k,Tq=10.3,; Drill F/8,460'to 8,675'with 490 gpm @ 3,050 psi,WOB=25k,Tq= 12.3.This assembly drilled 385' in 17.7 hrs for an average ROP of 21.7 ft/hr with 45%sliding time.4' low and . 61' left of the well plan. ci Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00 212-181 1/22/13 Daily Operations: 2/13/2013-Wednesday Slide Drill 9-7/8" hole f/8,675't/8,698'to maintain Directional Plan. (9.2 ft/hr) Rotary Drill from 8,675'to 8,735'. (30 ft/hr) UP 236k, DN 162k, R 210k, 11.5 bpm = 2950 psi. 10,500 ft/lb Tq @ 60 RPM, 15-20k WOB. Slide Drill f/8,735't/8,761'to begin build &turn per plan. (26' @ 5.7 ft/hr) Rotary Drill from 8,761'to 8,799'. (38', 15.2 ft/hr) Slide Drill f/8,799't/8,819'. Trouble with pipe laying into wall and not getting consistent Wt. transfer to the bit. CBU. UP 238k, DN 192k, R 207k, 11.5 bpm =2,980 psi. 9,600 ft/lb tq @ 60 rpm. Flow check Well (good). Pump Slug. Blow down TD. POOH f/8,819't/3,550' standing 105 stds back stands in derrick. Hole is in very good condition. No tight spots to work. Max overpull was 25k. At 3,550' lay down singles to pipe shed. Current depth @ 1,200 ft. In the last 24 hrs this assembly drilled 144' in 11.4 on btm hrs, ROP= 12'/hr with 66%sliding time.The well bore is 4.5' low and 4' right of plan ; For the total run this assembly drilled a total of 5696' in 152.6 drilling hrs;for an average ROP of 37.3 ft/hrUp-230k do-180k Rot-200k; Notified AOGCC& BLM of intent to test BOP.Jim Regg of AOGCC waived to witness;test @ 12:32.Justin Miller waived witness of test @ 13:40 2/14/2013-Thursday POOF- laying down Dp singles from 1,200'to BHA @ 637. Rack back HWDP and Jars. Lay down Directional tools and grade Bit. Bii:Grade: 2,3,CT,T,X,1,PN,PR. Clear rig floor of excess tools and slip/trip hazards. Pull Wear Bushing. Rig up to test BOPE. Test BOP and related equipment to 250L/4,000H for 10 min ea. test. Chart record all tests. Test H2S and LEL gas alarm system. Perform Accumulator precharge test. R/D Test Equipment and install Wear Bushing. M/U BHA#4: PDC, 1.10 deg Motor, Pony Clr, Stab, Pony Clr, MWD w/GR, Pulser NM Filter, (2) NM Comp Dp, (4) HWDP,Jar, (21) HWDP=925.19. Surface test BHA. Pick up 66 jts from pipe shed and single in hole with BHA#4 to the 10-3/4" casing shoe @ 3,001'. Break circulation and fill the drill pipe before entering open hole. Calculated returns to trip tank and filling pipe. Continue tripping in with 20 more singles from the pipe shed before running stands from the derrick. Break circulation and fill pipe every 30 stds. Set down on obstruction @ 3,820', but able to pass without Pump. 5,500' @ 06:00. 2/15/2013- Friday TIH from 5,500'to TD @ 8,686'. Break circulation and ream to btm. Worked thru obstructions @ 6,518' & 6,556'. Bottom 40' of hole slight under gauged. Pump sweep on final stand. Gas to surface @ 180 bbls pumped. Max gas 2,638'. Drill F/8,822' to 8,825', @ 450 gpm with 2,700psi,and 70 rpm in the rotary. Continue drilling F/8,825'to 8,915' @ 500 gpm with 3,230 psi. DRill F/8,915'to 9,190' @ 500 gpm and 3,200 psi, upwt=246k SO= 198 RT-214. Hole in good condition w/minimal losses, but difficult sliding. 1% NXS Lube added with good results. G&I injected 461 bbls in last 24 hrs. 2/16/2013-Saturday Drill 9-7/82/16/2013-Saturday Tangent Section from 9,190'to 9,255' (65' @ 10.8 ft/hr). UP 250k, DN 200k, R 215k, 12 bpm, 2,920 psi, 10,500 ft/lb tq @ 60 RPM w/15k WOB. Continue drilling Tangent section f/9,255't/9,330'. (75' @ 12.5 ft/hr) Drill f/9,330't/9,545' running 15k to 23k with 70 rpm on the rotary,Tq=11.5 (215', 18 ft/hr Ave ROP)Top of Tyonek HP sand @ 9,525'. 2/17/2013-Sunday Drill 9-7/8" hole from 9,560'to 9,714'. (154', 25.6 ft/hr) Chlorides consistent. UP 263k, DN 200k, R 225k, 12 bpm, 3,150 psi, 12,800 ft/lb tq @ 70 rpm, 12-20k WOB. Continue drilling f/9,714't/9,823'. (109', 20 ft/hr) 13' slide to correct direction. Circ & Cond for Short Trip. Pump up survey. Record SPRs. Flow check Well (good)Short Trip out f/9,822't/8,720' on elevators, correct hole fill, no issue. Observe well,trip in to 9,791' encountering a tight spot 31' off bottom. Break circulation and wash to bottom @ 9,820'. On bottom continue drilling F/9,825'T/9,855' Up-263k Dn- 228k Rot-200k. At 9,855'trip gas increased to 3,440 units. Shut well in and circulate through choke circulating out the gas. Continue drilling F/9,855'to 9,868'. Drill F/9,868'to 9,950'with 500 GPM, 60 rotary. 2/18/2013-Monday Drill 9-7/8"Tangent section from 9,950'to 10,046', 530gpm, 3280psi, 14.4tq. Drill F/10,046'to 10,122'. Up-263k Dn-204k Rot-228k. Drill F/10,112'to 10,185',495 GPM, 3280 Psi, 12.2 Tq, Up 269k, Dn 205k, Rot 228. Drill F/10,185'to 10,264',with 18k wt and 3,000 psi, 100 rpm @ 12k tq. This assembly drilled a total of 314' in 17.4 on bottom drilling hrs. ROP=18'/hr. 2/19/2013-Tuesday Drill 9-7/8" hole f/10,264'to 10,456'. 20K wob,483 gpm at 3,323 psi, 80 rpm at 14,700 ft/lbs on bott torque, 73 units gas, ROP 12 to 25 ft/hr. Cont drilling f/10,455'to 10,531'with 20k wt, 80rpm,490 gpm and 14k tq. Drilling F/10,531'to 10,595' with 15k to 23k,490 gpm, 3,300 psi. Through out this assembly we have attempted different drilling parameters. In some sections it worked, but through some of the harder streaks it didnt matter. In the last 24 hrs this assembly drilled 331' in 14.9 hr. Average ROP is 22 ft/hr with 16%sliding time. This assembly has drilled a total of 1,773' with 48 on bottom drilling hrs. Average ROP is 37 ft/hr with 10%sliding time so far. • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00 212-181 1/22/13 D"ily Operations: ' 101JIi4,00 �. 2/20/2013-Wednesday Cont. drilling 9-7/8" hole f/10,595'to 10,650', 17K wob, 480 gpm at 3220 psi, 80 rpm at 16K ft/lbs, ROP 12 ft/hr. Up wt 282K, dwn wt 220K, rot wt 240K. Pump 30 bbl hi-vis sweep w/nut plug, increase rotation to 90 rpm-13K ft/lbs, had no increase in cuttings at shakers w/sweep to surface. Cont drilling 9-7/8" hole f/10,650'to 10,709' running 18k to 20k on the bit and 70 rpm. Pumping 475 gpm @ 3,350 on bottom pressure. Monitor well and pump dry job. Short trip pulling pipe F/10,709'to the top of the turn section @ 8,622'. At 10,588', 10,454',and 10,334' pulled tight with 25k to 35k over. Monitor the well bore before tripping back to bottom @ 10,709'. Trip in F/8,622'tagging up on tight spot at 10,049'. Break circulation and wash and ream through the trouble area. Cont.trip in and kelly up at 10,647'. Wash and ream F/10,647'to bottom @ 10,709'. Drill F/10,709'to 10,711' @ 465 gpm and 3,250 psi, 20k bit wt. and 70 rpm. While drilling we circulated up a gas bubble peaking out at 3,406 units. Strokes indecate the main peak is coming from the water zone at 9,500'. Plus the gas bubble migraded up hole+/-2,000' peaking out early. Also getting some gas from bottom. Drilling break from 10,696'to 10,709'. We got 200 units of gas for 1,000 strokes past B/U @ 16,000 stks. Drilling F/10,711'to 10,760'with 18k wt and 70 rpm.465 gpm and 3250 psi. 2/21/2013-Thursday Cont drilling 9-7/8"hole f/10,760'to 10,870', 20K wob, 72 rpm at 13K ft/lbs on btm torque, 500 gpm at 3,319 psi. Rig team held kick while drilling drill at 09:39 hrs at 10,791'with good response from entire team. Cont drilling 9-7/8" hole f/10,870' to 11,000', 16K wob, 75 rpm at 13K ft/lbs on bottom torque,475 gpm at 3,032 psi. ADT= 19 hrs. Drilled 240'. Circulate a bottoms up pumping 465 gpm with 2,950 psi, 80 rpm, 12k Tq. Flow check,survey at 11,000' Inc 24.78 deg Azi 34.16 deg 10,486'tvd, dry job. Start short trip f/11,000'to 10,010'. 2/22/2013 Friday Cont POOH f/10,010'to 8,625'w/no problems. Pulled 38 stnds. Monitor well f/30 minutes. Fluid level dropped 6" in 30 min in well bore. RIH f/8,625'to 10,730' and encountered obstruction. MU topdrive and wash/ream through tight spot. Cont RIH f/10,730'to 11,000' w/no problem. CBU at 463 gpm-2,965 psi, max gas at bottoms up 1,213 units. Drop carbide bomb followed with 26 bbl hi-vis sweep, circ surf to surf 500 gpm, 3,320 psi, 80 rpm at 15K ft/lbs. 2,1857 calcualted strokes, carbide back at 23,000 strokes. 9-7/8" hole gauge calculated at 10.36". POOH 5 stnds, up wt 280K with no problem coming off bottom. Monitor well for 30 minutes. Fluid level dropped approx 5' in well bore. Pumped 20 bbl dry job, blew dwn topdrive and mud line. Cont POOH f/10,675'for logging run. The trip out went well up to the short trip depth @ 8,822'. The well bore started getting ratty with 30k to 50k over pull from 8,000' up to the 10-3/4" casing shoe at 3,001'. The depths with the higher overpulls collate with coal stringers throughout the well bore. PJSM,Slip and cut 165' of drilling line.The line on the drum had some bad spots, cut and slip additional 95'for a total of 260'. Service rig and topdrive, calibrate block hight before tripping back in. Monitor the well during the cut and slip and rig service. Slight drop in fluid. Trip in wiping any spots taking weight. 2/23/2013-Saturday Cont RIH f/6,235'to 11,000'filling pipe every 20 stnds. MU topdrive wash last stnd dwn, had 15'fill, rot/recip 80 rpm-12K off bott torq 245K rot wt, CBU at 500 gpm-3,221 psi, max gas at bott up= 682 units. POOH 5 stnds, monitor well 15 min,fluid loss at 1/2 bbl per hour, pump dry job. POOH f/10,697'to 4,522' standing drill pipe back in derrick, up wt 285K. PJSM-Lay down drill pipe F/4,522'to 2,895' inside the 10-3/4" casing shoe. Monitor the well for 15 min. Slight drop, no tight hole or hole issues on tripout. Continue tripping out with drill pipe to the BHA @ 925'. Stand back HWDP. Stand back drill collars and L/D motor, bit and stab. Bit used up,4-4-CT. Clear rig floor and prep for wire line. PJSM-Rig up Halliburton wire line, M/U Gama, Nutron, Density, Flex jt. Wave Sonic and ACRT tools. Run in on wire line with logging tools. 2/24/2013-Sunday Halliburton E-Line made it to bottom (11,000'), log OOH at 1,800' per hour. Lay down logging tools and rig down wire line and sheves, clear rigfloor. MU Smith Mill Tooth (bit#2 RR2)sn:PX5266+bit sub+NM Stab+NM flex DC's+;4jnts HWDP+jars+21 jnts HWDP. Pick up singles from pipe shed to 4,891'. Continue trip in with stands from derrick to 10,955'. Kelly up and wash and ream to bottom @ 11,000'. The trip in went well, no hole issues. Circulate pumping a bottoms up, at 14,000 stks the gas peaked at 733 units. The gas peaked 2,400 stks before bottoms up. At bottoms up the gas dropped to 150 units and kept dropping. Pump a 20 bbl hi/vis sweep pumping 500 gpm with 80 rpm on the topdrive. 2/25/2013- Monday Cont circ out sweep at 500 gpm-3050 psi, had no increase in cuttings at shakers. POOH 5 stnds, monitor slight drop in fluid level, pump dry job, blw dwn lines. POOH f/10,765'to 7,671' racking back DP on off drillers side. Cont POOH f/7,671' laying down all remaining 5" DP and cleanout BHA. Clear and clean rigfloor, lay down mouse hole\PJSM-Pick up running tool and pull wear bushing, lay down same. PJSM-Change upper rams F/5"to 7-5/8"for casing run. Pick up 7-5/8"test jt and test plug, place in stack and rig up to test. Test the 7-5/8" rams and door seal to 250 psi low and 4,000 psi high. Lay down the 7- 5/8"test jt and test plug. Rig up the rigfloor to run 7-5/8", change out elevators and bails. Hang weatherford casing tongs, moblize slips and centralizers to the rigfloor. Dry run hanger and mark langing jt. Change out casing tongs due to bad valve in controls. P/U shoe track, baker lock connections and fill with mud checking float, OK. Run 7-5/8" casing filling on the fly with a fill up hose. Ensure casing is full every fifth one. 2/26/2013-Tuesday PU RIH with 7-5/8" 29.7# L-80 BTC casing to 2,126'filling on the fly+every 10. Service rig,topdrive and catwalk. Cont PU RIH w/casing f/2,126'to 2,993'. MU topdrive and circ surf to surf just inside surface shoe. Cont PU RIH w/casing f/2,993'to 4,375'. Repair back stop on lay down machine. Continue running casing f/4,375'to 6,559'. ; Circulate bottoms up. Continue running casing f/6,559'to 10,985' and MU landing jnt/hanger assembly. • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00 212-181 1/22/13 Daily Operations: , 2/27/2013-Wednesday Land hanger(20.55' RKB) 210K dwn wt, break circ at 65 spm-125 gpm-456 psi. Max gas at bottoms up 1,055 units. Increased pump rate to 76 spm-147 gpm-452 psi,then up to 88 spm-169 gpm-525 psi for full circ. Shut dwn rig pump. Load plugs and MU plug launcher on casing. Held PJSM with SLB and rig team. SLB pumped 5 bbls water to load lines and tested lines at 250 low/4,000 high f/3 minutes each. Rig pumped 52 bbls 13.5ppg MudPush II at 4 bpm and shut dwn. SLB dropped bottom plug and pumped 382 bbls (1350 sx) 14.1ppg Class G lead cement at 5bpm at 600psi,followed by 80 bbls (333 sx) 15.3ppg tail cement at 3.5 bpm at 200 psi. SLB dropped top plug, RIG displaced with 496bb1s 13.1ppg PHPA 6% KCL Mud at 7 bpm-1,300 psi,slowing to 3 bpm at 1,080 psi with 10 bbl to go. Bumped plug and held 1,500psi (FCP of 1,080psi)for 3 minutes, bled off and floats held. TOC at approximately 4,000'. Obtained 2 samples cement from mixing tub. Mix water temp 71 deg. Pumped 40% excess on both lead and tail. Had full returns throughout the job. Did not reciprocate string due to excessive string wt. Down wt 210K at time of landing hanger. RD and released Schlumberger. CIP at 16:00 hrs, 2-27-13. Drained and flushed BOP stack, backed out landing jnt, made up packoff assembly, and installed same. RILD's. Tested packoff to 250/3,000 f/15 minutes. Change out 7-5/8" casing rams to 2-7/8" x 5" variables. PJSM, Change out bails, hang tongs, rig up spinner hawks, install wear ring. Lay down remaining 5" drill pipe out of derrick. Clear rig floor of 5"tools, clean rig floor, bring 4"tools to floor. Pull wear ring, install test plug, prep test jnts, RU BOP test equipment. Will test annular and variable rams with 4" and 5"test jnts, lower rams will be tested with 4". INJECTED 548 BBLS DRILLING FLUID, 100 BBLS WATER. 2/28/2013-Thursday Install 4"test jnt and test plug,fill stack w/water. Test all BOPE at 250/4,000 psi f/10 minutes each,tested annular at 250/2,500psi at 10 minutes each, also tested annular and variable rams w/5"test jnt. Tested TIW, dart valves, upper and lower IBOP's, 2 HCR valves, manual choke and kill line valves, choke manifold, lower pipe rams, blinds and performed koomey drawdown test. Electrician tested gas alarms/lights. Had one fail/pass on upper rams. Changed out operator piston mud seal, re-tested with no problems. Witness of BOP test was waived by AOGCC Rep Jim Regg on 2-27-13 at 15:45 hrs. Change out saver sub to 4" HT-38, blow dwn choke and kill lines, swap to 4" elev. Install wear ring, PU RIH w/38 jnts 4" DP. POOH rack back 19 stnds in derrick(for drilling production section). Clean rig floor, bring 6-3/4"tools to floor. PJSM, pick up 6-3/4" BHA,shallow test MWD on 1st joint hwdp, continue PU HWDP. Continue tripping in hole PU 4" drill pipe from pipe shed, at 2,900'. We have 940 bbls 9.5ppg mud built for drilling production section. G&I injected 646 bbls drilling fluids, 70 bbls cmt rinsate, 100 bbls water. 3/1/2013 -Friday Cont PU single in hole w/6-3/4" directional assembly from 2,900'to 5,555',top filling 4" drill string every 2,000', rig crew held kick while trip drill at 5,555'. Re-load pipe shed w/169 jnts 4" DP,strap same, perform derrick inspection SIMOPS. Cont PU single in hole 4" HT-38 DP from 5,555'to 10,898'. Night crew held BOP drill at 10,335' and top filled drill pipe. Canrig calibrated gas equipment. Continue tripping in hole,tag top of cement @ 10,898'. PJSM on displacing, displace with 9.5 mud. Rig up and test casing @ 3,000 psi F/30 min. Test good. Drill cement F/10,898'T/10,902', drill out Shoe track, Float @ 10,902',shoe @10,992'. Drill F 11,000'T/11,020', circulate F/FIT test. Perform FIT test, PSI up @ 1,361 psi, 12.0 EMW. Drill 6-3/4 production hole F/11,020'T/11,060',gpm 250, ssp 1,740,trq 8.4 off bo p/u 200k, s/o 155k, rot wt 172k,ADT 2.7,AST 1.2,total HRS on bit 2.7 hrs on jars 1.5. Injected 276 bbls drilling fluid, 100 bbl water. 3/2/2013-Saturday Cont drilling 6-3/4" production hole f/11,060'to 11,373', 5K wob, 9K on bottom torque, 60 rpm, 300 gpm at 2,051 psi, ROP 8 to 60 fph. Cont drilling 6-3/4" production hole f/11,373'T/ 11,538',gpm 306,spp 2,420 psi 5/7k wob, 70 rpm, p/u 206k,s/o 150k, rot wt 173k,trq on 9.6,trq off 9.0 ADT 9 hrs. Total bit hrs 15.6, motor hrs 26.1,jar hrs 10.8. Cont drilling 6-3/4" production hole f/ 11,538'T/11,686', GPM 300, rpm 70,spp 2,585,trq on bott 9.5k, p/u 209k,s/o 150k, rot wt 173k,ADT 4 hrs,AST 1.4 total hrs on bit 20 hrs, hrs on motor 31.5, hrs on jars 17.0. Rig sense PVT system down, circulate and attempt to get PVT system going. Injected 722 bbls drilling fluid, & 100 bbls water. 3/3/2013 -Sunday Cont CBU while troubleshooting MD Totco failure. Pulled OOH f/11,686'to casing shoe at 11,000'to troubleshoot MD Totco. Cut and slip drill line, change grabber dies,grease rig,wait on Totco rep. Cont troubleshoot Rig Sense App Server,wait on MD Totco Rep. TIH slow f/11,000'to 11,686' and break circ while MD Totco Rep installed new Rig Sense App Server. CBU 1 time. Cont drilling 6-3/4" production interval f/11,686'to 11,835' (TD). 7K wob, 65 rpm at 10K on bott torque, 314 gpm at 2,669 psi, ROP 29 to 56 ft/hr. CBU at 313 gpm-2,365 psi. 9.6ppg in/out,viss 44 in/out. Trip out of hole to shoe, monitor well, Trip in hole to 11,835'. Pump 42 bbl high vis sweep, circulate and condition mud for logs. Trip out of hole to shoe, monitor well,OK, pump dry job. Trip out of hole F/10,985'T/5,330'. Injected 912 bbls drilling fluids, 100 bbls water. 3/4/2013- Monday Cont POOH w/6-3/4" assembly f/5,330'to BHA (745')for logging. Cont POOH,flushing tools and LD BHA. Bit grade at 2/1. RU Halliburton Logging unit,sheaves and tools. RIH w/quad comb tools. Monitor well on trip tank. Clean rockwasher pit. Log OOH, pull to surface and LD quad combo assembly. Rig up STF4 tools and run in hole &take pressures @ 11,624'- 11,239'- 11,237'- 11,211' - 11,203'- 11,174'- 11,086' - 11,090',trip out w/wire line & Rig down. PJSM, clear rig floor of E- Line equip. PJSM, make up clean out assembly, run in hole with heavy weight DP,trip in hole to 2,502'fill pipe, p/u 65k,s/o 65k, 210 psi on pump. Continue tripping in hole F/2,502'T/6,031'. Injected 595 bbls drilling fluid, 125 bbls water. 3/5/2013 -Tuesday Cont TIH f/6,031'to 11,835'with 6-3/4" cleanout assembly. 22'fill on btm. CBU x 1,then pump 30 bbls hi-vis sweep around. POOH to shoe, monitor well F, pump dry job, blow dwn topdrive, drop 2" drift POOH rack back 4" DP and HWDP. LD jars, & BHA. P/u casing tools and equipment and rig up same. Pick up 26 jts 5" 15#DWC/C HT casing make up XO, Flex lock liner hanger,xo, RS packoff sealhnipple jt, HRD zxp packer, PBR, running tool, Xo. Rig down casing running tools. RIH with 1 stand hwdp and circulate casing volume. Trip in hole with 5" liner on 4" drill pipe @ 1 min per stand. Injected 595 bbls drilling mud and 125 bbls water. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00 212-181 1/22/13 Daily Operations: 3/6/2013-Wednesday Trip in with 5" liner on 4" drill pipe to the casing shoe @ 10,985' Break circ. and fill the drill string every 3,000'. Circulate a bottoms up with 7,300 stks @ 250 gpm and 930 psi. Trip in open hole with 5" liner to 11,815'. Rig up circulate head and break circulation. Wash to bottom tagging up as planned at 11,835'. Circulate at 3 pm with 540psi staging up to 5 bpm with 1,020 psi. Continue circulating @ 6bpm with 1,250 psi, p/u 215k, s/o 154k, rotating torq 9.8k, 56 units gas @ bottoms up. PJSm with cementers, pump 5 bbls water,test surface equip. @ 1,000 psi lo/5000. Test no good, check valve alignment on stand pipe& retest,test good. Pump 30 bbls of 12.0ppg mud push II, @ 4bbl/min, pump 46 bbls class G easyblok cement, drop drill pipe dart, pump 5 bbls water, displace with 127 mud, bump plug FICP 1,000, psi up T/2,100 psi CIP @ 22:05. Pressure up T/3,150,set hanger, bleed off Psi &check floats,floats holding,slack off 60k to set PKR, pressure up T/4,500 psi, bleed off and p/u 5', rotate pipe,shut annular, psi up on annulas T/1,100 psi, unsting F/liner top @ 10,731 pressure dropped. Circulate out cement,30 bbls mud push and 4 bbls cement to surface. Rig down cement head, blow down lines. Trip out of hole standing back in derrick injected 265 bbls waste slurry, 255 bbls drilling fluids and 100 bbls water. 3/7/2013-Thursday Trip out standing back 172 stands of 4" drill pipe in the derrick. Pick up cement head and finish breaking down valves. Continue tripping out laying down 16 jts of 4" drill pipe and 18 jts HWDP lay down running tool, all checked out on running tool. Rig down 4" handling equipment, clear and clean rigfloor same in pipe shed. Strap pipe and get work string ready while waiting on casing crew. PJSM Rig up power tongs,get tools ready for trip. Pick up the 2-7/8"work string and scraper assembly. Rig down Weatherford casing equipment and prep for tripping. Trip in with 4"from derrick tagged top of liner @ 10,801 drill pipe meas. Continue tripping in hole F/10,801 to top of landing collar @ 11,756' DP meas. P/U 195k,S/0150k. Circulate surface to surface @ 6 bbl/min, 1,500 psi. Test casing @ 3,000 psi F/30 min. Displace 9.8 mud with fresh water and circulat untill clean. Short trip assembly F/11,830 T/10,786, P/u 210k,S/0 150K. Cut drilling line. Injected 217 bbls drilling fluid, 193 bbls cement rinsate, 125 bbls water. 3/8/2013- Friday Continue tripping out to the top scraper, clean magnet, 1 lbs metal. Trip in T/11,756'filling every 3,000'. Pump 150 bbls water F/pits, 500 bbls water f/rain for rent tank, 11.000 stks @ 5 bbl/min, 1090 psi. PJSM with all party,s involved, pump 50 bbl caustic pill, 50 bbl Barakleen pill, 50 bbl Hi Vis sweep,followed with 490 bbls 6% KCL @ 5 bbl/min, 1,040 psi. Flush mud pumps, mud lines w/fresh water. Trip out of hole laying down drill pipe, p/u 192k, s/o 150k. Injected 818 bbl drilling fluids, 100 bbl water. 3/9/2013 -Saturday POOH with Scraper Clean out assembly, laying down Dp f/8,400'. Clean and inspect 7-5/8"Scraper. Recovered+/-5 lbs of fine metal shavings. Rig up Weatherford Power tongs and handling equipment. POOH laying down 2-7/8" SLH-90 Work String. Clean and L/D 5"Scraper assembly. Remove Wear Bushing. Stage (41)joints of 2-7/8" EUE Kill String in Pipe Shed. M/U and RIH with (41)jts of 2-7/8" EUE, 6.5# L-80. Make up hanger w/2 way check& landing jt, land hanger, RKB 19.3, RILDS. Rig down weatherford tools and clear rig floor. Clean out cellar, blow down lines. Remove flow line, drilling nipple, choke & kill lines,start nippling down BOP'S. Injected 1,592 bbls waste slurry, 100 bbls water. 3/10/2013-Sunday Nipple Down BOP and related equipment. Break loose Cap on Annular Preventer,so element can be changed while drilling on Diverter System. Make up Dead Well Tree (Adaptor& Master Valve) Pressure test Void &Valve to 250psi Low/5,000psi High for 15 min ea.test. Remove TWC& install BPV. Rig down & prep loads for transport to SRU 24-15: Clear rig floor of tools, prep. Mud Pits t/scope down tops,finish blowing down systems& pump fluids from tanks. R/D electrical, crane Mud Shack&centrifuge House to trailers, haul Rock Washer tank&cuttings tank to staging area. Stage (3) loads of 5" Dp on next Well Pad, Prep Pipe Shed f/move, crane windwalls & DWKs roof off&spot TD Cradle on floor. R/D TD and remove lower section of Torque Tube, remove topdrive F/floor. Injected 881 bbls waste slurry, 125 bbls water. Rig released F/SRU 13-27 @ 24:00 hrs 3/10/2013. 3/11/2013- Monday No operations to report. 3/12/2013-Tuesday No operations to report. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 13-27 50-133-20607-00 212-181 1/22/13 Daily Operations: 03/13/2013 -Wednesday MIRU Williams 405 WOR and associated equipment, install winterization package. NU Bop's &tested Bops, 250 low/3000 high, annular 250 low/ 1500 high. Witness Waived by Jim Regg, AOGCC. 03/14/2013 -Thursday Finished Accum. test and made rig ready to POOH W/2-7/8" Kill string. Pulled Lock pins on hanger, Pulled hanger and LD. LD 40jts of 2-7/8" 8 Rd, kill string. MIRU Halliburton E-Line Unit, MU 3.7" GR, RIH,tagged top of liner hanger, Attempted to work down thru liner top, could not get GR down. POOH w/GR, MU FASTCAST tool, RIH, logged from ,790'-3,000_—_MU 61;,k" GR, RIH,tagged top of liner. POOH. C13 L, -r 03/15/2013 - Friday MU 3-3/8" Dummy gun, RIH, made through liner top,tagged bottom @ 11,841' Elm. POOH.,,-MLCBL/Gamma ray, log from 11,751'-10,790' in 5" casing. Send logs to Halliburton to engineers to send to Hilcorp to determine where perforations will be placed and if further well work will need to be done. NU shooting flange and MU E-Line BOP, Lubricator and pressure control. MU 13' 3-3/8" HC 6 spf gun,fill and test lubricator to 3,000 psi. RIH W/gun, and ccl,tag bottom and log up short pass to correlate depths w/logs, dropped down to desired depth,fired guns. Perforated from 11,612'-11,631'. 03/16/2013 -Saturday POOH W/Gun, ensured all charges went off, LD spent gun, RDMO all equip. MU Wire-line Re-entry guide, 6' pup, X-nipple, 1 jt of 2-7/8" 8 Rd tbg, Packer, Packer w/ono tool, 1 jt of tbg and first gas lift mandrel. PU remaing 2-7/8" and gas lift mandrels and tripped to bottom. 03/17/2013 -Sunday Finish Rigging down WOR and Equip. Test hanger void/Well head to 4500 psi, MIRU Pollard Slickline Unit, RU Swab , equipment. Start swabbing. Made total of 26 runs, recovered total of 18 Bbls of fluid, FL holding @ 360'. 03/18/2013 - Monday No rig activity. Turned over to production. 03/19/2013 -Tuesday No activity to report. • T T W n C w *S` *N T T D O m N N _, ..... •9 n 0 d a 5 9 m N O (2) O O N'O O O cCpp W W W W A W N CO CD W W V V W W W A A W N a_ n n .0. _ _ a y JCA W�O. 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W _W j (73 CD N 0 p � O p (71 O) n. O () m 0 C 3 ( V 3 ra_ 0 O °° m Q 0 N D. (p O W D- 0 O N SRU 13-27 Days Vs Depth 0 2000 -SRU 13-27 Actual -SRU 14B-27 Actual 4000 6000 1.7s v v 8000 10000 12000 14000 16000 0 10 20 30 40 50 60 Days SRU 13-27 MW Vs Depth o 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 \ MWvs Depth Y 5500 s ami 6000 0 -a v 6500 co co a) 7000 7500 8000 8500 -� 9000 9500 10000 10500 11000 11500 ' 1\ 12000 12500 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) r: . nCASING RUN IN TALLY WELL NAME: SCU 13-27 DATE: 01/30/13 CASING SIZE 10.750 WEIGHT 45.50 CASING ID 9.950 GRADE L-80 THREA[ BTC CAPACITY 0.0962 bbls/ft TORQUE - MAXIMUM= MIN= 10,750 DISPLACEMENT 0.0166 bbls/ft SHOE DEPTH 3001.7 feet Coupling OD=11,750 HOLE TD 3014.0 feet Pin ID=9.95 MUD WT 10.10 ppg Joint Running Joint Depth BOUY FACTOR 0.85 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacity Displmt on Rack in hole feet feet feet feet weight bbls bbls '`ff R.,tt,,.,, '' -,r Block Weight = 25,000 Patherford Bulk 1.90 1.90 3001.74 2999.84 Float Shoe 25,073 0.2 0.0 BakerLocked Joint 'entrilizer#1 wlstop ring 76 43.15 45.05 2999.84 2956.69 10'above shoe 26,736 4.3 0.7 BakerLocked Joint 'entrilizer#2 w/stop ring 75 40.90 85.95 2956.69 2915.79 coupler 28,312 8.3 1.4 1.45 87.40 2915.79 2914.34 veatherford Float Collar 28,368 8.4 1.4 74 3 42.33 129.73 2914.34 2872.01 Baker Locked Joint 30,000 12.5 2.1 73 4 41.25 170.98 2872.01 2830.76 Centralizer#3 31,589 16.4 2.8 72 5 41.58 212.56 2830.76 2789.18 33,192 20.4 3.5 71 6 40.77 253.33 2789.18 2748.41 Centralizer#4 34,763 24.4 4.2 70 7 40.53 293.86 2748.41 2707.88 36,325 28.3 4.9 69 8 39.87 333.73 2707.88 2668.01 Centralizer#5 37,861 32.1 5.5 68 9 40.60 374.33 2668.01 2627.41 39,426 36.0 6.2 67 10 40.07 414.40 2627.41 2587.34 Centralizer#6 40,970 39.9 6.9 66 11 40.38 454.78 2587.34 2546.96 42,527 43.7 7.5 65 12 40.27 495.05 2546.96 2506.69 Centralizer#7 44,078 47.6 8.2 64 13 40.50 535.55 2506.69 2466.19 45,639 51.5 8.9 63 14 41.06 576.61 2466.19 2425.13 Centralizer#8 47,222 55.5 9.5 62 15 40.35 616.96 2425.13 2384.78 48,777 59.3 10.2 61 16 40.89 657.85 2384.78 2343.89 Centralizer#9 50,353 63.3 10.9 60 17 41.41 699.26 2343.89 2302.48 51,948 67.2 11.6 59 18 41.00 740.26 2302.48 2261.48 Centralizer#10 53,529 71.2 12.3 58 19 40.43 780.69 2261.48 2221.05 55,087 75.1 12.9 57 20 41.15 821.84 2221.05 2179.90 Centralizer#I 1 56,672 79.0 13.6 56 21 39.02 860.86 2179.90 2140.88 58,176 82.8 14.2 55 22 41.32 902.18 2140.88 2099.56 Centralizer#12 59,769 86.8 14.9 54 23 40.36 942.54 2099.56 2059.20 61,324 90.6 15.6 53 24 40.59 983.13 2059.20 2018.61 Centralizer#13 62,888 94.5 16.3 52 25 41.42 1024.55 2018.61 1977.19 64,485 98.5 17.0 51 26 40.79 1065.34 1977.19 1936.40 Centralizer#14 66,057 102.5 17.6 50 27 41.20 1106.54 1936.40 1895.20 67,644 106.4 18.3 49 28 40.19 1146.73 1895.20 1855.01 Centralizer#15 69,193 110.3 19.0 48 29 41.24 1187.97 1855.01 1813.77 70,783 114.2 19.7 47 30 39.01 1226.98 1813.77 1774.76 Centralizer#16 72,286 118.0 20.3 46 31 40.67 1267.65 1774.76 1734.09 73,853 121.9 21.0 45 32 41.45 1309.10 1734.09 1692.64 Centralizer#17 75,451 125.9 21.7 44 33 41.67 1350.77 1692.64 1650.97 77,057 129.9 22.4 43 34 40.90 1391.67 1650.97 1610.07 Centralizer#18 78,633 133.8 23.0 42 35 41.20 1432.87 1610.07 1568.87 80,221 137.8 23.7 41 36 40.86 1473.73 1568.87 1528.01 Centralizer#19 81,795 141.7 24.4 40 37 40.81 1514.54 1528.01 1487.20 83,368 145.7 25.1 39 38 41.27 1555.81 1487.20 1445.93 Centralizer#20 84,959 149.6 25.7 38 39 41.20 1597.01 1445.93 1404.73 86,546 153.6 26.4 37 40 41.40 1638.41 1404.73 1363.33 Centralizer#21 88,142 157.6 27.1 36 41 41.24 1679.65 1363.33 1322.09 89,731 161.5 27.8 35 42 41.29 1720.94 1322.09 1280.80 Centralizer#22 91,322 165.5 28.5 34 43 40.03 1760.97 1280.80 1240.77 92,865 169.4 29.1 33 44 40.29 1801.26 1240.77 1200.48 Centralizer#23 94,418 173.2 29.8 Joint Rut Joint Depth BOl ACTOR 0.85 A Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacity Displmt on Rack in hole feet feet feet feet weight bbls bbls 32 45 41.26 1842.52 1200.48 1159.22 96,008 177.2 30.5 31 46 40.92 1883.44 1159.22 1118.30 Centralizer#24 97,585 181.1 31.2 30 47 40.71 1924.15 1118.30 1077.59 99,154 185.0 31.8 29 48 40.03 1964.18 1077.59 1037.56 Centralizer#25 100,697 188.9 32.5 28 49 40.39 2004.57 1037.56 997.17 102,253 192.8 33.2 27 50 41.04 2045.61 997.17 956.13 Centralizer#26 103.835 196.7 33.9 26 51 41.22 2086.83 956.13 914.91 105,423 200.7 34.5 25 52 41.23 2128.06 914.91 873.68 Centralizer#27 107,012 204.7 35.2 24 53 37.61 2165.67 873.68 836.07 108,462 208.3 35.8 23 54 38.05 2203.72 836.07 798.02 Centralizer#28 109,928 211.9 36.5 22 55 41.34 2245.06 798.02 756.68 111,521 215.9 37.2 21 56 37.92 2282.98 756.68 718.76 Centralizer#29 112,983 219.6 37.8 20 57 41.43 2324.41 718.76 677.33 114,579 223.5 38.5 19 58 40.32 2364.73 677.33 637.01 Centralizer#30 116,133 227.4 39.1 18 59 40.92 2405.65 637.01 596.09 117,710 231.4 39.8 17 60 40.95 2446.60 596.09 555.14 Centralizer#31 119,288 235.3 40.5 16 61 39.96 2486.56 555.14 515.18 120,828 239.1 41.2 15 62 39.81 2526.37 515.18 475.37 Centralizer#32 122.363 243.0 41.8 14 63 41.01 2567.38 475.37 434.36 123.943 246.9 42.5 13 64 41.18 2608.56 434.36 393.18 Centralizer#33 125,530 250.9 43.2 12 65 41.33 2649.89 393.18 351.85 127,123 254.8 43.9 11 66 38.34 2688.23 351.85 313.51 Centralizer#34 128,600 258.5 44.5 10 67 40.69 2728.92 313.51 272.82 130,168 262.4 45.2 9 68 41.17 2770.09 272.82 231.65 131,755 266.4 45.8 8 69 40.72 2810.81 231.65 190.93 133,324 270.3 46.5 7 70 41.32 2852.13 190.93 149.61 134,917 274.3 47.2 6 71 41.14 2893.27 149.61 108.47 136,502 278.2 47.9 5 72 39.67 2932.94 108.47 68.80 138,031 282.1 48.5 4 73 39.61 2972.55 68.80 29.19 139,558 285.9 49.2 Pup 5.22 2977.77 29.19 23.97 139,759 286.4 49.3 Hanger 0.83 2978.60 23.97 23.14 139.791 286.5 49.3 RKB 23.14 3001.74 23.14 0.00 140,683 288.7 49.7 3 74 40.92 2 75 40.97 Left Out 1 76 39.87 i CASING RUN IN TALLY WELL NAME: SRU 13-27 DATE: 02/27/13 CASING SIZE 7.625 inches WEIGHT 29.70 ppf CASING ID 6.875 inches GRADE L - 80 P-110 THREAD BTC CAPACITY 0.0459 bbls/ft TORQUE - OPTIMUM = MIN= 7800 DISPLACEMENT 0.0108 bbls/ft SHOE DEPTH 10985.90 feet HOLE TD 11000.00 feet Foremen: Pederson/Leslie/Greco/ Grubb MUD WT 13.10 ppg Joint Running Joint Depth BOUY FACTOR 0.80 Joint# Joint# Length Total Bottom Top REMARKS: Bouyant CapacityDisplmt on rack in hole feet feet feet feet Run 66 centralizers weight bbls bbls I ( Off Bottom=> 14.10 Block Weight => 25,000 A Shoe 1.63 1.63 10985.90 10984.27 Weatherford 25,039 0.1 0.0 281 1 41 .52 43.15 10984.27 10942.75 P-110 BTC(centra 2) 26,025 2.0 0.5 280 2 39.17 82.32 10942.75 10903.58 P-110 BTC(centra 3) 26,956 3.8 0.9 B Flt Clr 1.32 83.64 10903.58 10902.26 Weatherford 26,987 3.8 0.9 279 3 41 .26 124.90 10902.26 10861.00 P-110 BTC(centra 4) 27,968 5.7 1.4 278 4 39.201 164.10 10861.00 10821.80 P-110 BTC 28,899 7.5 1.8 277 5 38.57 202.67 10821.80 10783.23 P-110 BTC(centra 5) 29,815 9.3 2.2 276 6 39.31 241.98 10783.23 10743.92 P-110 BTC 30,749 11.1 2.6 275 7 42.71 284.69 10743.92 10701.21 P-110 BTC(centra 6) 31,764 13.1 3.1 274 8 42.20 326.89 10701.21 10659.01 P-110 BTC 32,767 15.0 3.5 273 9 42.86 369.75 10659.01 10616.15 P-110 BTC(centra 7) 33,785 17.0 4.0 272 . 10 42.69 412.44 10616.15 10573.46 P-110 BTC 34,800 18.9 4.5 271 11 41 .15 453.59 10573.46 10532.31 P-110 BTC(centra 8) 35,777 20.8 4.9 270 12 39.39 492.98 10532.31 10492.92 P-110 BTC 36,713 22.6 5.3 269 13 _ 39.88 532.86 10492.92 10453.04 P-110 BTC(centra 9) 37,661 24.5 5.8 268 14 39.41 572.27 10453.04 10413.63 P-110 BTC 38,597 26.3 6.2 267 15 41 .48 613.75 10413.63 10372.15 P-110 BTC(centra 10) 39,583 28.2 6.6 266 16 34.69 648.44 10372.15 10337.46 P-110 BTC 40,407 29.8 7.0 265 17 40.11 688.55 10337.46 10297.35 P-110 BTC(centra 11) 41,360 31.6 7.4 264 18 39.36 727.91 10297.35 10257.99 P-110 BTC 42,295 33.4 7.9 263 19 38.76 766.67 10257.99 10219.23 P-110 BTC(centra 12) 43,216 35.2 8.3 262 20 41 .66 808.33 10219.23 10177.57 P-110 BTC 44,206 37.1 8.7 261 21 41 .30 849.63 10177.57 10136.27 P-110 BTC(centra 13) 45,187 39.0 9.2 260 22 38.74 888.37 10136.27 10097.53 P-110 BTC 46,108 40.8 9.6 259 23 38.09 926.46 10097.53 10059.44 P-110 BTC(centra 14) 47,013 42.5 10.0 258 _ 24 41 .93 968.39 10059.44 10017.51 P-110 BTC 48,009 44.5 10.5 257 _ 25 39.39 1007.78 10017.51 9978.12 P-110 BTC(centra 15) 48,945 46.3 10.9 256 26 _ 41 .28 1049.06 9978.12 9936.84 P-110 BTC 49,926 48.2 11.3 I 255 27 39.02 1088.08 9936.84 9897.82 P-110 BTC(centra 16) 50,853 50.0 11.8 254 28 40.30 1128.38 9897.82 9857.52 P-110 BTC 51,810 51.8 12.2 253 29 39.82 1168.20 9857.52 9817.70 P-110 BTC(centra 17) 52,756 53.6 12.6 252 30 38.87 1207.07 9817.70 9778.83 P-110 BTC 53,680 55.4 13.0 251 31 39.52 1246.59 9778.83 9739.31 P-110 BTC(centra 18) 54,619 57.2 13.5 250 32 39.64 1286.23 9739.31 9699.67 P-110 BTC 55,561 59.1 13.9 249 33 40.89 1327.12 9699.67 9658.78 P-110 BTC(centra 19) 56,532 60.9 14.3 248 34 40.00 1367.12 9658.78 9618.78 P-110 BTC 57,483 62.8 14.8 247 35 41 .88 1409.00 9618.78 9576.90 P-110 BTC(centra 20) 58,478 64.7 15.2 • Joint Running Joint Depth BOUY FACTOR 0.80 I Joint# Joint# Length Total Bottom Top REMARKS: Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 66 centralizers weight bbls bbls 246 36 40.94 1449.94 9576.90 9535.96 P-110 BTC 59,451 66.6 15.7 245 37 41 .34 1491.28 9535.96 9494.62 - P-110 BTC(centra 21) 60,433 68.5 16.1 244 38 41 .31 1532.59 9494.62 9453.31 P-110 BTC 61,414 70.4 16.6 243 39 40.47 1573.06 9453.31 9412.84 P-110 BTC(centra 22) 62,376 72.2 17.0 242 40 40.09 1613.15 9412.84 9372.75 P-110 BTC 63,328 74.1 17.4 241 41 39.65 1652.80 9372.75 9333.10 P-110 BTC(centra 23) 64,271 75.9 17.9 240 42 41 .37 1694.17 9333.10 9291.73 P-110 BTC 65,253 77.8 18.3 239 43 40.09 1734.26 _ 9291.73 9251.64 P-110 BTC(centra 24) 66,206 79.6 18.7 238 44 41 .31 1775.57 _ 9251.64 9210.33 P-110 BTC 67,188 81.5 19.2 237 45 41 .76 1817.33 9210.33 9168.57 P-110 BTC(centra 25) 68,180 83.5 19.6 236 46 36.07 1853.40 9168.57 9132.50 P-110 BTC 69,037 85.1 20.0 235 47 41 .05 1894.45 9132.50 9091.45 P-110 BTC(centra 26) 70,012 87.0 20.5 234 48 33.86 1928.31 9091.45 9057.59 P-110 BTC 70,817 88.5 20.8 233 49 38.91 1967.22 9057.59 9018.68 P-110 BTC(centra 27) 71,741 90.3 21.3 232 50 39.56 2006.78 9018.68 8979.12 P-110 BTC 72,681 92.2 21.7 231 51 41 .60 2048.38 8979.12 8937.52 P-110 BTC(centra 28) 73,670 94.1 22.1 230 52 38.00 2086.38 8937.52 8899.52 P-110 BTC 74,572 95.8 22.6 229 53 39.81 2126.19 8899.52 8859.71 P-110 BTC(centra 29) 75,518 97.6 23.0 228 54 37.34 2163.53 8859.71 8822.37 P-110 BTC 76,405 99.3 23.4 227 55 37.35 2200.88 8822.37 8785.02 P-110 BTC(centra 30) 77,293 101.1 23.8 226 56 38.59 2239.47 8785.02 _ 8746.43 P-110 BTC 78,210 102.8 24.2 225 57 34.25 2273.72 8746.43 8712.18 P-110 BTC(centra 31) 79,024 104.4 24.6 224 58 38.35 2312.07 8712.18 8673.83 P-110 BTC 79,935 106.2 25.0 223 59 41 .32 2353.39 _ 8673.83 _ 8632.51 P-110 BTC(centra 32) 80,917 108.1 25.4 222 60 41 .09 2394.48 8632.51 8591.42 P-110 BTC 81,893 110.0 25.9 221 61 41 .41 2435.89 8591.42 8550.01 P-110 BTC(centra 33) 82,877 111.9 26.3 220 62 37.79 2473.68 8550.01 8512.22 P-110 BTC 83,775 113.6 26.7 219 63 39.38 2513.06 8512.22 8472.84 P-110 BTC(centra 34) 84,710 115.4 27.2 218 64 39.20 2552.26 _ 8472.84 8433.64 P-110 BTC 85,642 117.2 27.6 217 65 40.03 2592.29 8433.64 _ 8393.61 P-110 BTC(centra 35) 86,593 119.0 28.0 216 66 39.78 2632.07 8393.61 8353.83 P-110 BTC 87,538 120.9 28.5 215 67 40.02 2672.09 8353.83 8313.81 P-110 BTC(centra 36) 88,489 122.7 28.9 214 68 41 .77 2713.86 8313.81 8272.04 P-110 BTC 89,481 124.6 29.3 213 69 38.18 2752.04 8272.04 8233.86 P-110 BTC(centra 37) 90,388 126.4 29.7 212 70 37.84 2789.88 8233.86 8196.02 P-110 BTC 91,288 128.1 30.2 211 71 41 .33 2831.21 8196.02 8154.69 P-110 BTC(centra 38) 92,270 130.0 30.6 210 72 40.35 2871.56 8154.69 8114.34 P-110 BTC 93,228 131.9 31.0 209 73 39.68 2911.24 8114.34 8074.66 P-110 BTC(centra 39) 94,171 133.7 31.5 208 74 39.92 2951.16 8074.66 8034.74 P-110 BTC 95,120 135.5 31.9 207 75 42.48 2993.64 8034.74 7992.26 P-110 BTC(centra 40) 96,129 137.5 32.4 206 76 42.26 3035.90 7992.26 7950.00 P-110 BTC 97,133 139.4 32.8 205 77 41 .24 3077.14 7950.00 7908.76 P-110 BTC(centra 41) 98,113 141.3 33.3 204 78 43.10 3120.24 7908.76 7865.66 P-110 BTC 99,137 143.3 33.7 203 79 41 .10 3161.34 7865.66 7824.56 P-110 BTC(centra 42) 100,113 145.2 34.2 202 80 41 .88 3203.22 7824.56 7782.68 P-110 BTC 101,109 147.1 34.6 201 81 41 .14 3244.36 7782.68 _ 7741.54 P-110 BTC(centra 43) 102,086 149.0 35.1 200 82 42.74 3287.10 7741.54 7698.80 P-110 BTC 103,101 150.9 35.5 199 83 43.39 3330.49 7698.80 7655.41 P-110 BTC(centra 44) 104,132 152.9 36.0 198 84 43.66 3374.15 7655.41 7611.75 P-110 BTC 105,170 154.9 36.5 Joint Running Joint Depth BOUY FACTOR 0.80 Joint# Joint# Length Total Bottom Top REMARKS: Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 66 centralizers weight bbls bbls 197 85 43.42 3417.57 7611.75 7568.33 P-110 BTC(centra 45) 106,201 156.9 36.9 196 86 39.52 3457.09 7568.33 7528.81 P-110 BTC 107,140 158.7 37.4 195 87 42.20 3499.29 7528.81 7486.61 P-110 BTC(centra 46) 108,143 160.7 37.8 194 88 40.59 3539.88 7486.61 7446.02 P-110 BTC 109,108 162.6 38.3 193 89 39.59 3579.47 7446.02 7406.43 P-110 BTC(centra 47) 110,048 164.4 38.7 192 90 41 .34 3620.81 7406.43 7365.09 L-80 BTC 111,030 166.3 39.1 191 91 41 .23 3662.04 7365.09 7323.86 L-80 BTC(centra 48) 112,010 168.2 39.6 190 92 41 .85 3703.89 7323.86 7282.01 L-80 BTC 113,004 170.1 40.0 189 93 39.07 3742.96 7282.01 7242.94 L-80 BTC 113,933 171.9 40.5 188 94 41 .56 3784.52 7242.94 7201.38 L-80 BTC 114,920 173.8 40.9 187 95 41 .09 3825.61 7201.38 7160.29 L-80 BTC(centra 49) 115,896 175.7 41.4 186 96 41 .68 3867.29 7160.29 7118.61 L-80 BTC 116,887 177.6 41.8 185 97 41 .36 3908.65 7118.61 7077.25 L-80 BTC 117,870 179.5 42.3 184 98 42.12 3950.77 7077.25 7035.13 L-80 BTC 118,870 181.4 42.7 183 99 41 .03 3991.80 7035.13 6994.10 L-80 BTC(centra 50) 119,845 183.3 43.2 182 100 38.53 4030.33 6994.10 6955.57 L-80 BTC 120,761 185.1 43.6 181 101 41 .96 4072.29 6955.57 6913.61 L-80 BTC 121,758 187.0 44.0 180 102 41 .78 4114.07 6913.61 6871.83 L-80 BTC 122,750 188.9 44.5 179 103 40.19 4154.26 6871.83 6831.64 L-80 BTC(centra 51) 123,705 190.8 44.9 178 104 41 .24 4195.50 6831.64 6790.40 L-80 BTC 124,685 192.7 45.4 177 105 40.83 4236.33 6790.40 6749.57 L-80 BTC 125,655 194.5 45.8 176 106 41 .02 4277.35 6749.57 6708.55 L-80 BTC 126,630 196.4 46.2 175 107 39.55 4316.90 6708.55 6669.00 L-80 BTC(centra 52) 127,570 198.2 46.7 174 108 38.69 4355.59 6669.00 6630.31 L-80 BTC 128,489 200.0 47.1 173 109 40.60 4396.19 6630.31 6589.71 L-80 BTC 129,453 201.9 47.5 172 110 39.78 4435.97 6589.71 6549.93 L-80 BTC 130,399 203.7 48.0 171 111 37.46 4473.43 6549.93 6512.47 . L-80 BTC(centra 53) 131,289 205.4 48.4 170 112 39.97 4513.40 6512.47 6472.50 L-80 BTC 132,238 207.3 48.8 169 113 40.08 4553.48 6472.50 6432.42 L-80 BTC 133,191 209.1 49.2 168 114 39.61 4593.09 6432.42 6392.81 L-80 BTC 134,132 210.9 49.7 167 115 39.95 4633.04 6392.81 6352.86 L-80 BTC(centra 54) 135,081 212.7 50.1 166 116 40.01 4673.05 6352.86 6312.85 L-80 BTC 136,032 214.6 50.5 165 117 39.18 4712.23 6312.85 6273.67 L-80 BTC 136,963 216.4 50.9 164 118 40.40 4752.63 6273.67 6233.27 L-80 BTC 137,922 218.2 51.4 163 119 41 .26 4793.89 6233.27 6192.01 L-80 BTC(centra 55) 138,903 220.1 51.8 162, 120 41 .36 4835.25 6192.01 6150.65 L-80 BTC 139,886 222.0 52.3 161 121 40.18 4875.43 6150.65 6110.47 L-80 BTC 140,840 223.9 52.7 160 122 41 .75 4917.18 6110.47 6068.72 L-80 BTC 141,832 225.8 53.2 159 123 41 .86 4959.04 6068.72 6026.86 L-80 BTC(centra 56) 142,827 227.7 53.6 158 124 39.20 4998.24 6026.86 5987.66 L-80 BTC 143,758 229.5 54.0 157 125 38.90 5037.14 5987.66 5948.76 L-80 BTC 144,682 231.3 54.5 156 126 41 .64 5078.78 5948.76 5907.12 L-80 BTC 145,672 233.2 54.9 155 127 41 .89 5120.67 5907.12 5865.23 L-80 BTC(centra 57) 146,667 235.1 55.4 154 128 39.22 5159.89 5865.23 5826.01 L-80 BTC 147,599 236.9 55.8 153 129 41 .88 5201.77 5826.01 5784.13 L-80 BTC 148,594 238.9 56.2 152 130 41 .26 5243.03 5784.13 5742.87 L-80 BTC 149,574 240.8 56.7 151 131 40.80 5283.83 5742.87 5702.07 L-80 BTC(centra 58) 150,544 242.6 57.1 150 132 38.51 5322.34 5702.07 5663.56 L-80 BTC 151,459 244.4 57.5 149 133 38.21 5360.55 5663.56 5625.35 L-80 BTC 152,367 246.2 57.9 • Joint Running Joint Depth BOUY FACTOR 0.80 I Joint# Joint# Length Total Bottom Top REMARKS: Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 66 centralizers weight bbls bbls 148 134 38.86 5399.41 5625.35 5586.49 L-80 BTC 153,290 247.9 58.4 147 135 41 .71 5441.12 5586.49 5544.78 L-80 BTC(centra 59) 154,281 249.9 58.8 146 136 41 .23 5482.35 5544.78 5503.55 L-80 BTC 155,261 251.7 59.3 145 137 40.18 5522.53 5503.55 5463.37 L-80 BTC 156,215 253.6 59.7 144 138 40.96 5563.49 5463.37 5422.41 L-80 BTC 157,189 255.5 60.1 143 139 39.80 5603.29 5422.41 5382.61 L-80 BTC(centra 60) 158,134 257.3 60.6 142 140 39.76 5643.05 5382.61 5342.85 L-80 BTC 159,079 259.1 61.0 141 141 40.72 5683.77 5342.85 5302.13 L-80 BTC 160,046 261.0 61.4 140 142 39.25 5723.02 5302.13 5262.88 L-80 BTC 160,979 262.8 61.9 139 143 41 .03 5764.05 5262.88 5221.85 L-80 BTC(centra 61) 161,954 264.7 62.3 138 144 40.59 5804.64 5221.85 5181.26 L-80 BTC 162,918 266.5 62.7 137 145 38.32 5842.96 5181.26 5142.94 L-80 BTC 163,829 268.3 63.2 136 146 41 .47 5884.43 5142.94 5101.47 L-80 BTC 164,814 270.2 63.6 135 147 38.36 5922.79 5101.47 5063.11 L-80 BTC(centra 62) 165,725 272.0 64.0 134 148 40.00 5962.79 5063.11 5023.11 L-80 BTC 166,676 273.8 64.5 133 149 38.52 6001.31 5023.11 4984.59 L-80 BTC 167,591 275.6 64.9 132 150 39.36 6040.67 4984.59 4945.23 L-80 BTC 168,526 277.4 65.3 131 151 40.95 6081.62 4945.23 4904.28 L-80 BTC(centra 63) 169,499 279.3 65.7 130 152 38.51 6120.13 4904.28 4865.77 L-80 BTC 170,414 281.0 66.2 129 153 39.68 6159.81 4865.77 4826.09 L-80 BTC 171,357 282.9 66.6 128 154 40.55 6200.36 4826.09 4785.54 L-80 BTC 172,321 284.7 67.0 127 155 41 .01 6241.37 4785.54 4744.53 L-80 BTC(centra 64) 173,295 286.6 67.5 126 156 39.65 6281.02 4744.53 4704.88 L-80 BTC 174,237 288.4 67.9 125 157 38.88 6319.90 4704.88 4666.00 L-80 BTC 175,161 290.2 68.3 124 158 41 .02 6360.92 4666.00 4624.98 L-80 BTC 176,135 292.1 68.8 123 159 38.74 6399.66 4624.98 4586.24 L-80 BTC(centra 65) 177,056 293.9 69.2 122 160 38.95 6438.61 4586.24 4547.29 L-80 BTC 177,981 295.7 69.6 121 161 39.80 6478.41 4547.29 4507.49 L-80 BTC 178,927 297.5 70.0 120 162 39.55 6517.96 4507.49 4467.94 L-80 BTC 179,867 299.3 70.5 119 163 40.57 6558.53 4467.94 4427.37 L-80 BTC(centra 66) 180,831 301.2 70.9 118 164 39.54 6598.07 4427.37 4387.83 L-80 BTC 181,770 303.0 71.3 117 165 39.94 6638.01 4387.83 4347.89 L-80 BTC 182,719 304.8 71.8 116 166 39.88 6677.89 4347.89 4308.01 L-80 BTC 183,667 306.6 72.2 115 167 38.80 6716.69 4308.01 4269.21 L-80 BTC 184,589 308.4 72.6 114 168 41 .79 6758.48 4269.21 4227.42 L-80 BTC 185,581 310.3 73.1 113 169 39.99 6798.47 4227.42 4187.43 L-80 BTC 186,532 312.2 73.5 112 170 39.89 6838.36 4187.43 4147.54 L-80 BTC 187,479 314.0 73.9 111 171 39.72 6878.08 4147.54 4107.82 L-80 BTC 188,423 315.8 74.4 110 172 38.93 6917.01 4107.82 4068.89 L-80 BTC 189,348 317.6 74.8 109 173 39.36 6956.37 4068.89 4029.53 L-80 BTC 190,283 319.4 75.2 108 174 40.09 6996.46 4029.53 3989.44 L-80 BTC 191,236 321.3 75.6 107 175 39.60 7036.06 3989.44 3949.84 L-80 BTC 192,177 323.1 76.1 106 176 39.85 7075.91 3949.84 3909.99 L-80 BTC 193,124 324.9 76.5 105 177 38.78 7114.69 3909.99 3871.21 L-80 BTC 194,045 326.7 76.9 104 178 39.64 7154.33 3871.21 3831.57 L-80 BTC 194,987 328.5 77.3 103 179 38.22 7192.55 3831.57 3793.35 L-80 BTC 195,895 330.3 77.8 102 180 41 .25 7233.80 3793.35 3752.10 L-80 BTC 196,875 332.2 78.2 101 181 40.92 7274.72 3752.10 3711.18 L-80 BTC 197,847 334.1 78.6 100 182 39.38 7314.10 3711.18 3671.80 L-80 BTC 198,783 335.9 79.1 • Joint Running Joint Depth BOUY FACTOR 0.80 I Joint# Joint# Length Total Bottom Top REMARKS: Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 66 centralizers weight bbls bbls 99 183 39.84 7353.94 3671.80 3631.96 L-80 BTC 199,730 337.7 79.5 98 184 38.53 7392.47 3631.96 3593.43 L-80 BTC 200,645 339.5 79.9 97 185 38.88 7431.35 3593.43 3554.55 L-80 BTC 201,569 341.2 80.3 96 186 40.18 7471.53 3554.55 3514.37 L-80 BTC 202,524 343.1 80.8 95 187 39.20 7510.73 3514.37 3475.17 L-80 BTC 203,455 344.9 81.2 94 188 40.48 7551.21 3475.17 3434.69 L-80 BTC 204,417 346.8 81.6 93 189 41 .23 7592.44 3434.69 3393.46 L-80 BTC 205,396 348.6 82.1 92 190 39.73 7632.17 3393.46 3353.73 L-80 BTC 206,340 350.5 82.5 91 191 40.10 7672.27 3353.73 3313.63 L-80 BTC 207,293 352.3 82.9 90 192 38.59 7710.86 3313.63 3275.04 L-80 BTC 208,210 354.1 83.4 89 193 40.46 7751.32 3275.04 3234.58 L-80 BTC 209,171 355.9 83.8 88 194 40.67 7791.99 3234.58 3193.91 L-80 BTC 210,138 357.8 84.2 87 195 41 .39 7833.38 3193.91 3152.52 L-80 BTC 211,121 359.7 84.7 86 196 40.88 7874.26 3152.52 3111.64 L-80 BTC 212,092 361.6 85.1 85 197 41 .10 7915.36 3111.64 3070.54 L-80 BTC 213,069 363.5 85.6 84 198 41 .73 7957.09 3070.54 3028.81 L-80 BTC 214,060 365.4 86.0 83 199 41 .16 7998.25 3028.81 2987.65 L-80 BTC 215,038 367.3 86.5 82 200 41 .62 8039.87 2987.65 2946.03 L-80 BTC 216,027 369.2 86.9 81 201 41 .76 8081.63 2946.03 2904.27 L-80 BTC 217,020 371.1 87.4 80 202 41 .89 8123.52 2904.27 2862.38 L-80 BTC 218,015 373.0 87.8 79 203 38.99 8162.51 2862.38 2823.39 L-80 BTC 218,941 374.8 88.2 78 204 41 .63 8204.14 2823.39 2781.76 L-80 BTC 219,930 376.7 88.7 77 205 40.88 8245.02 2781.76 2740.88 L-80 BTC 220,902 378.6 89.1 76 206 41 .32 8286.34 2740.88 2699.56 L-80 BTC 221,883 380.5 89.6 75 207 40.53 8326.87 2699.56 2659.03 L-80 BTC 222,846 382.4 90.0 74 208 41 .16 8368.03 2659.03 2617.87 L-80 BTC 223,824 384.3 90.5 73 209 41 .37 8409.40 2617.87 2576.50 L-80 BTC 224,807 386.2 90.9 72 210 39.83 8449.23 2576.50 2536.67 L-80 BTC 225,754 388.0 91.3 71 211 40.93 8490.16 2536.67 2495.74 L-80 BTC 226,726 389.9 91.8 70 212 40.76 8530.92 2495.74 2454.98 L-80 BTC 227,695 391.7 92.2 69 213 41 .06 8571.98 2454.98 2413.92 L-80 BTC 228,670 393.6 92.7 68 214 41 .64 8613.62 2413.92 2372.28 L-80 BTC 229,660 395.5 93.1 67 215 41 .11 8654.73 2372.28 2331.17 L-80 BTC 230,636 397.4 93.6 66 216 40.26 8694.99 2331.17 2290.91 L-80 BTC 231,593 399.3 94.0 65 217 41 .49 8736.48 2290.91 2249.42 L-80 BTC 232,579 401.2 94.4 64 218 40.26 8776.74 2249.42 2209.16 L-80 BTC 233,535 403.0 94.9 63 219 41 .32 8818.06 2209.16 2167.84 L-80 BTC 234,517 404.9 95.3 62 220 41 .31 8859.37 2167.84 2126.53 L-80 BTC 235,499 406.8 95.8 61 221 40.94 8900.31 2126.53 2085.59 L-80 BTC 236,471 408.7 96.2 60 222 41 .73 8942.04 2085.59 2043.86 L-80 BTC 237,463 410.6 96.7 59 223 41 .83 8983.87 2043.86 2002.03 L-80 BTC 238,457 412.5 97.1 58 224 39.72 9023.59 2002.03 1962.31 L-80 BTC 239,400 414.4 97.5 57 225 41 .39 9064.98 1962.31 1920.92 L-80 BTC 240,384 416.3 98.0 56 226 40.14 9105.12 1920.92 1880.78 L-80 BTC 241,338 418.1 98.4 55 227 41 .23 9146.35 1880.78 1839.55 L-80 BTC 242,317 420.0 98.9 54 228 41 .62 9187.97 1839.55 1797.93 L-80 BTC 243,306 421.9 99.3 53 229 41 .22 9229.19 1797.93 1756.71 L-80 BTC 244,286 423.8 99.8 52 230 41 .06 9270.25 1756.71 1715.65 L-80 BTC 245,261 425.7 100.2 51 231 39.59 9309.84 1715.65 1676.06 L-80 BTC 246,202 427.5 100.6 • Joint Running Joint Depth BOUY FACTOR 0.80 I Joint# Joint# Length Total Bottom Top REMARKS: Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 66 centralizers weight bbls bbls 50 232 41 .46 9351.30 1676.06 1634.60 L-80 BTC 247,187 429.4 101.1 49 233 42.06 9393.36 1634.60 1592.54 L-80 BTC 248,186 431.3 101.5 48 234 40.48 9433.84 1592.54 1552.06 L-80 BTC 249,148 433.2 102.0 47 235 41 .69 9475.53 1552.06 1510.37 L-80 BTC 250,139 435.1 102.4 46 236 41 .36 9516.89 1510.37 1469.01 L-80 BTC 251,121 437.0 102.9 45 237 41 .66 9558.55 1469.01 1427.35 L-80 BTC 252,111 438.9 103.3 44 238 41 .81 9600.36 1427.35 1385.54 L-80 BTC 253,105 440.8 103.8 43 239 41 .25 9641.61 1385.54 1344.29 L-80 BTC 254,085 442.7 104.2 42 240 39.62 9681.23 1344.29 1304.67 L-80 BTC 255,026 444.6 104.7 41 241 41 .80 9723.03 1304.67 1262.87 L-80 BTC 256,019 446.5 105.1 40 242 39.95 9762.98 1262.87 1222.92 L-80 BTC 256,968 448.3 105.5 39 243 41 .51 9804.49 1222.92 1181.41 L-80 BTC 257,955 450.2 106.0 38 244 41 .31 9845.80 1181.41 1140.10 L-80 BTC 258,936 452.1 106.4 37 245 41 .40 9887.20 1140.10 1098.70 L-80 BTC 259,920 454.0 106.9 36 246 40.87 9928.07 1098.70 1057.83 L-80 BTC 260,891 455.9 107.3 35 247 40.76 9968.83 1057.83 1017.07 L-80 BTC 261,859 457.8 107.8 34 248 41 .44 10010.27 1017.07 975.63 L-80 BTC 262,844 459.7 108.2 33 249 38.73 10049.00 975.63 936.90 L-80 BTC 263,764 461.5 108.6 32 250 41 .85 10090.85 936.90 895.05 L-80 BTC 264,759 463.4 109.1 31 251 41 .83 10132.68 895.05 853.22 L-80 BTC 265,752 465.3 109.5 30 252 38.86 10171.54 853.22 814.36 L-80 BTC 266,676 467.1 110.0 29 253 41 .70 10213.24 814.36 772.66 L-80 BTC 267,667 469.0 110.4 28 254 41 .40 10254.64 772.66 731.26 L-80 BTC 268,650 470.9 110.9 27 255 39.67 10294.31 731.26 691.59 L-80 BTC 269,593 472.7 111.3 26 256 41 .24 10335.55 691.59 650.35 L-80 BTC 270,573 474.6 111.7 25 257 41 .76 10377.31 650.35 608.59 L-80 BTC 271,565 476.5 112.2 24 258 40.11 10417.42 608.59 568.48 L-80 BTC 272,518 478.4 112.6 23 259 42.11 10459.53 568.48 526.37 L-80 BTC 273,518 480.3 113.1 22 260 41 .79 10501.32 526.37 484.58 L-80 BTC 274,511 482.2 113.5 21 261 41 .41 10542.73 484.58 443.17 L-80 BTC 275,495 484.1 114.0 20 262 41 .16 10583.89 443.17 402.01 L-80 BTC 276,473 486.0 114.4 19 263 41 .75 10625.64 402.01 360.26 L-80 BTC 277,465 487.9 114.9 18 264 41 .76 10667.40 360.26 318.50 L-80 BTC 278,457 489.8 115.3 17 265 41 .25 10708.65 318.50 277.25 L-80 BTC 279,438 491.7 115.8 16 266 40.46 10749.11 277.25 236.79 L-80 BTC 280,399 493.6 116.2 15 267 41 .48 10790.59 236.79 195.31 L-80 BTC 281,384 495.5 116.6 14 268 38.63 10829.22 195.31 156.68 L-80 BTC 282,302 497.3 117.1 13 269 41 .23 10870.45 156.68 115.45 L-80 BTC 283,282 499.2 117.5 12 270 39.20 10909.65 115.45 76.25 L-80 BTC 284,213 501.0 117.9 9.61 10919.26 76.25 66.64 Pup Joint 284,442 501.4 118.0 11 271 39.64 10958.90 66.64 27.00 L-80 BTC 285,383 503.2 118.5 6.00 10964.90 27.00 21.00 Pup Joint 285,526 503.5 118.5 0.45 10965.35 21.00 20.55 Hanger 285,537 503.5 118.5 RKB 20.55 10985.90 20.55 0.00 RKB to Load shoulder 286,025 504.5 118.8 CASING RUN IN TALLY WELL NAME: SRU 13-27 DATE: 03/05/13 CASING SIZE 5.000 WEIGHT 15.00 CASING ID 4.408 GRADE L-80 THREAI DWC/C-HT Casing (Buttress Casing) CAPACITY 0.0189 bbls/ft TORQUE - MAXIMUM=9,400 MIN=8,400 DISPLACEMENT 0.0046 bbls/ft • SHOE DEPTH 11830.6 feet Coupling OD=5.563" , Drift=4.283" HOLE TD 11835.0 feet Foremen: Pederson/Greco/Grubb MUD WT 9.60 ppg Joint Running Joint Depth BOUY FACTOR 0.85 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacit}Displmt on Rack in hole feet feet feet feet weight bbls bbls Off Bottom 4.40 Block Weight = 25,000 Weatherford Bullnose Shoe,5 3/4"OD, SN- A Sho 1.63 1.63 11830.60 11828.97 573712 Model:303E 25,021 0.0 0.0 BakerLocked Joint w/2 Centrilizer&stop rings 1 38.35 39.98 11828.97 11790.62 10'&20'from shoe 25,510 0.8 0.2 Weatherford Float Collar. 5 3/4"OD, SN-577505 B 1.32 41.30 11790.62 11789.30 Model:402_ 25,527 0.8 0.2 Baker Locked Joint w/Centralizer#4&#5 2 38.21 79.51 11789.30 11751.09 Mid-joint 26,014 1.5 0.4 Non Baker Landing Collar,BTC, 5 3/4"OD, C 1.00 80.51 11751.09 11750.09 SN:21313 26,027 1.5 0.4 Joint 5" DWC 3 38.05 118.56 11750.09 11712.04 w/Centralizer#6 26,512 2.2 0.5 Joint 5" DWC 4 4 38.59 157.15 11712.04 11673.45 w/Centralizer#7 27,004 3.0 0.7 Joint 5"DWC 5 5 38.61 195.76 11673.45 11634.84 w/Centralizer#8 27,496 3.7 0.9 Joint 5" DWC 6 6 35.78 231.54 11634.84 11599.06 w/Centralizer#9 27,952 4.4 1.1 Joint 5" DWC 7 38.46 270.00 11599.06 11560.60 w/Centralizer#10 28,443 5.1 1.2 Joint 5" DWC 8 38.93 308.93 11560.60 11521.67 w/Centralizer#11 28,939 5.8 1.4 Joint 5" DWC 9 38.82 347.75 11521.67 11482.85 w/Centralizer#12 29,434 6.6 1.6 Joint 5" DWC 10 37.89 385.64 11482.85 11444.96 w/Centralizer#13 29,917 7.3 1.8 Joint 5" DWC 11 38.96 424.60 11444.96 11406.00 w/Centralizer#14 30,414 8.0 1.9 Joint 5" DWC 12 39.08 463.68 11406.00 11366.92 w/Centralizer#15 30,912 8.8 2.1 Joint 5" DWC 13 39.07 502.75 11366.92 11327.85 w/Centralizer#16 31,410 9.5 2.3 Joint 5" DWC 14 38.81 541.56 11327.85 11289.04 w/Centralizer#17 31,905 10.2 2.5 Joint 5"DWC 15 38.90 580.46 11289.04 11250.14 w/Centralizer#18 32,401 11.0 2.7 Joint 5" DWC 16 16 38.76 619.22 11250.14 11211.38 w/Centralizer#19 32,895 11.7 2.8 Joint 5" DWC 17 38.50 657.72 11211.38 11172.88 w/Centralizer#20 33,386 12.4 3.0 Joint 5" DWC 18 18 38.03 695.75 11172.88 11134.85 w/Centralizer#21 33,871 13.1 3.2 Joint 5"DWC 19 19 38.89 734.64 11134.85 11095.96 w/Centralizer#22 34,367 13.9 3.4 Joint 5" DWC 20 20 38.28 772.92 11095.96 11057.68 w/Centralizer#23 34,855 14.6 3.5 Joint 5" DWC 21 21 37.92 810.84 11057.68 11019.76 w/Centralizer#24 35,338 15.3 3.7 Joint 5" DWC 22 22 38.78 849.62 11019.76 10980.98 w/Centralizer#25 35,833 16.0 3.9 23 23 38.47 888.09 10980.98 10942.51 Jt 5"DWC 36,323 16.8 4.1 24 24 38.61 926.70 10942.51 10903.90 Jt 5"DWC w/cent#26 36,815 17.5 4.2 25 25 39.07 965.77 10903.90 10864.83 Jt 5"DWC 37,314 18.2 4.4 26 26 39.78 1005.55 10864.83 10825.05 Jt 5"DWC w/cent#27 37,821 19.0 4.6 •• Joint Rur, Joint Depth BOL CTOR 0.85 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacit)Displmt on Rack in hole feet feet feet feet weight bbls bbls XO,Flex-Lock Liner Hanger,XO,RS Packoff Seal Nipple Jt,HRD ZXP 32.07 1037.62 10825.05 10792.98 Packer,PBR. 38,230 19.6 4.8 Tripoint tic Packer & Service Tool Division V Company: Date: Temp: Gun Size: SPF: Phasing: Casing Size/Wt: Hilcorp Alaska 16-Mar-13 J 1-5/8"29.1# Lease: Well#: Expl.Type: Fluid Wt. &Type Specialist: Swanson River 13-21 8.6# FSW Nicholas Rivoire (Offshore Block: Parish: State: Completion Interval: Stage SRU Kenai AK Item Description O. D. I. D. Length Depth ® 1..1 ciD - "' ORKB - - 18.60 10.001 '• 32 32 9"Tubing Hanger 31/2 8rd Top and Bottom 9.000 2.992 0.50 18.60 31 31 31/2 9.3#L-80 Pup Joint 3.500 2.992 3.75 19.10 30 30 Crossover 2 7/8 8rd Pin X 31/2 8rd Box 4.500 2.992 0.80 22.8529 29 [1401 Joints of 21/8 6.5#L-80 8rd Tubing 2.815 2A41 4,434.10 23.65 .r 28 28 27/8 6.5#L-80 8rd Pup Joint 2.815 2.441 4.15 4,451.75 § 27 27 GLV#5 2212psi 4.625 2.441 1.06 4,461.90 '2 r 26 26 21/8 6.5#1.-80 8rd Pup Joint 2.815 2.441 3.85 4,468.96 -r 2, 25 [90)Joints of 2 7/8 6.5#L-80 8rd Tubing 2.875 _ 2.441 2,851.53 4,412.81 :r 24 24 21/8 6.5#L-80 8rd Pup Joint 2.815 2.441 4.15 _ 7,324.34 23 23 GLV#42066psi 4.625 2.441 7.08 7,328.49 "-i22 22 21/8 6.5#L-80 8rd Pup Joint 2.815 2.441 3.95 1,335.57 1 21 21 [501 Joints of 2 7/8 6.5#L-80 8rd Tubing 2.815 2.441 1,581.68 7,339.52 `r 20 20 21/8 6.5#L-80 Ord Pup Joint 2.815 2.441 4.11 8,921.20 z- > 19 19 GLV#31983ps1 (625 2.441 1.01 8,925.31 I 18 18 21/8 6.5#L-80 8rd Pup Joint 2.875 2.441 3.88 8,932.38 = 17 [331 Joints of 21/8 6.5#L-80 Ord Tubing 2.875 2.441 1,048.65 8,936.26 ` I 17 16 21/8 6.5#L-80 8rd Pup Joint 2.815 2.441 4.07 9,984.91 r 16 15 GLV#21923psi 4.625 2.441 1.10 9,988.98 i ` 15 14 2 7/8 6.5#L-80 8rd Pup Joint 2.875 2.441 3.68 9,996.08 1 r 14 13 [231 Joints of 2 7/8 6.5#L-80 Ord Tubing 2.815_ 2.441 731.98 9,999.16 `1 13 12 2 7/8 6.5#L-80 8rd Pup Joint 2.875 2.441 4.27 10,731.74 m r 12 11 GLV#1 Orifice (625 2.441 7.06 10,736.01 - . 11 10 2 7/8 6.5#L-80 8rd Pup Joint 2.875 2.441 3.58 10,743.01 1 r 10 9 [11 Joint of 21/8 6.5#L-80 Ord Tubing 2.875 2.441 31.55 10,146.65 1( 8 8 21/8 6.5#L-80 8rd Pup Joint 2.815 2.441 6.20 10,118.20 - 7 T-2 0n/Off Tool with X-Profile 6.250 2.313 1.84 10,784.40 1° 7 6 1-5/8"24-29.1#AS-1X Ret Pred Packer 6.672 2.500 7.50 10,786.24 f 5 [11 Joint of 21/8 6.5#L-80 8rd Tubing 2.875 2.441 31.95 10,793.74 al 4 X-Nipple 3.230 2.313 1.20 10,825.69 s 6 3 21/8 6.5#L-80 8rd Pup Joint 2.815 2.441 4.01 10,826.89 1m- 2 Wireline Re-Entry Guide 3.690 2.500 0.45 10,830.96 1 EOA - - - 10,831.41 4 338 Joints of 2 7/8 L-80 6.5#8rd Tubing in hole Pick Up Weight=62,000 3 X-Nipples @ 10826 a 10784 Slack Off Weight=48,000 2 9"Tubing hanger is 31/2 8rd Top and Bottom Block Weight=6,000 1 Packer Set with 6,000 Compression Printed on 3/18/2013 @ 7:50 AM Page 1 of 1 Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. SRU 13-27 Date 6-Mar-13 County Kenai Peninsula Burough State Alaska Supv. Joe Grubb/Jimmy Greco CASING RECORD TD 11835.00 Shoe Depth: 11830.60'MD/11247.42'TVD PBTD: MD/'TVD Casing(Or Liner)Detail _ Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 5 STL Wfd 1.63 11,830.60 11,828.97 1 5 15 L-80 )WC/C-H" 38.35 11,828.97 11,790.62 F.Collar 5 STL Wfd 1.32 11,790.62 11,789.30 1 5 15 L-80 )WC/C-H" 38.21 11,789.30 11,751.09 Land CLR 5 STL _ 1.00 _ 11,751.09 11,750.09 24 5 15 L-80 )WC/C-H" 925.04 11,750.09 10,825.05 LH/PKR Baker 32.07 10,825.05 10,792.98 Running tool Baker 8.48 10,792.98 10,784.50 Totals Csg Wt.On Hook: 152000 Type Float Collar: Float No.Hrs to Run: 23 hrs Csg Wt.On Slips: 0 Type of Shoe: DJ/Float Casing Crew: Wfd Fluid Description: 9.85 ppg / 6%KCUPHPA Mud/ PV=12 YP=17 HTHP=9.8 Liner hanger Info(Make/Model): Floex lock hanger,ZXP Packer Liner top Packer?: x Yes No Liner hanger test pressure: 3150 Centralizer Placement: Bow spring centralizers on each joint in shoe track,every joint F/11750 T/11019 and one every other jt F/10942 T/10825,total of 24 centralizer ran CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 12 Volume pumped(BBLs) 30 BBLS Lead Slurry Type: Yield: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry Type: Class G gasblok Yield: 1.35 ft3/sk 1 Density(ppg) 15.3 ppg Vol pumped(BBLs/sx) 46 bbls/191 sx Mixing/Pumping Rate(bpm): 6.5 I- Post Flush(Spacer) 0 Type: Density(ppg) Rate(bpm): Volume: ce LI Displacement: Type: 6%KCUPHPA Density(ppg) 9.85 ppg Rate(bpm): 7 bpm Volume(actual/calculated): 127 bbls/124bbls FCP(psi): 1000 Pump used for disp: SLB Cement Plug Bumped? X Yes No Bump press 2100 Casing Rotated? Yes X No Reciprocated? x Yes No %Returns during job 100 Cement returns to surface? x Yes No Spacer returns? x Yes No Vol to Surf: 30 bbl spacer,4 bbls cement Cement In Place At: 22:05 Date: 3/6/2013 Estimated TOC: 10,731 Method Used To Determine TOC: Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry La Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: la Displacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes _No Reciprocated? _Yes No %Returns during job • Cement returns to surface? Yes No Spacer returns? Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: WELLHEAD Make Seaboard Type SMB-22 Serial No. H245745 Size 16 3/4 x 11 W.P.3000/5000 Test Head To 3000 PSIG 10 MIN X OK Remarks: • Hilcorp Energy Company CASING &CEMENTING REPORT Lease&Well No. SRU 13-27 Date 27-Feb-13 County Kenai Peninsula Burough • State Alaska Supv. Rance Pederson/Jimmy Greco CASING RECORD TD 11000.00 Shoe Depth: 10985.90.'MD/10486.73'TVD PBTD: MD/'TVD Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 7 5/8 STL Wfd 1.63 10,985.90 10,984.27 2 7 5/8 L-80 BTC 80.69 10,984.27 10,903.58 F.Collar 7 5/8 STL Wfd 1.32 10,903.58 10,902.26 87 jts 7 5/8 P-110 BTC 3,495.83 10,902.26 _ 7,406.43 183 7 5/8 L-80 BTC 7,378.99 7,406.43 27.44 Hanger 6.45 27.44 20.99 RKB 22.90 20.99 -1.91 Totals 44r Csg Wt.On Hook: 261000 Type Float Collar: Float No.Hrs to Run: 23 hrs ,645 Csg Wt.On Slips: 0 Type of Shoe: DJ/Float Casing Crew: Wfd Fluid Description: 13.0 ppg / 6%KCUPHPA Mud/ PV=24 YP=17 HTHP=9.2 Liner hanger Info(Make/Model): Liner top Packer?: Yes x No Liner hanger test pressure: Centralizer Placement: Bow spring centralizers on each joint in shoe track,every other joint to CEMENTING REPORT __ Preflush(Spacer) Type: Mud Push II Density(ppg) 13.5 Volume pumped(BBLs) 50 BBLS Lead Slurry Type: Class G Extended Yield: 1.58 ft3/sk Density(ppg) 14.10 ppg Vol pumped(BBLs/SX) 380 bbls/1350 sx Mixing/Pumping Rate(bpm): 5 bpm Tail Slurry Type: Class G gaslok Yield: 1.35 ft3/sk 1 Density(ppg) 15.3 ppg Volume pumped(BBLs) 80 bbls/333 sx Mixing/Pumping Rate(bpm): 3 bpm 0 Post Flush(Spacer) 17) Type: Density(ppg) Rate(bpm): Volume: cc u. Displacement: Type: 6%KCUPHPA Density(ppg) 13.0 ppg Rate(bpm): 7 bpm Volume(actual/calculated): 496 bbls/501bbls FCP(psi): 1080 Pump used for disp: Rig pump Plug Bumped? X Yes No Bump press 1501 Casing Rotated? Yes X No Reciprocated? Yes x No %Returns during job 100 Cement returns to surface? Yes x No Spacer returns?____Yes x No Vol to Surf: 0 Cement In Place At: 16:00 Date: 2/27/2013 Estimated TOC: 4,000 Method Used To Determine TOC: ('61- ? Floats Held? X Yes No Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry La Type: a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): v) Post Flush(Spacer) 0 z Type: Density(ppg) Rate(bpm): Volume: 0 w Displacement: u) Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes No Reciprocated? Yes No %Returns during job Cement returns to surface? Yes No Spacer returns?_Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: WELLHEAD Make Seaboard Type SMB-22 Serial No. H245745 Size 16 3/4 x 11 W.P.3000/5000 Test Head To 3000 PSIG 10 MIN X OK Remarks: r Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. SRU 13-27 Date 31-Jan-13 County Kenai Peninsula Burough State Alaska Supv. Rance Pederson/Jimmy Greco CASING RECORD TD 3014.00 Shoe Depth: 3001.74'MD/3000'TVD PBTD: MD/'TVD Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade _ THD Make Length Bottom Top Shoe 10 3/4 STL Wfd 1.90 3,001.74 2,999.84 2 10 3/4 45.5 L-80 BTC 84.05 2,999.84 2,915.79 F.Collar 10 3/4 STL Wfd 1.45 2,915.79 2,914.34 71 jts 10 3/4 45.5 L-80 BTC 1,498.73 2,914.34 1,415.61 Hanger 10 3/4 L-80 BTC 6.05 1,415.61 1,409.56 RKB 23.14 1,409.56 1,386.42 Totals Csg Wt.On Hook: 155,000 Type Float Collar: Float No.Hrs to Run: 12 hrs Csg Wt.On Slips: 120,000 Type of Shoe: DJ/Float Casing Crew: Wfd Fluid Description: 10.1 ppg WBM / Spud Mud/ PV=28 YP=17 HTHP= Liner hanger Info(Make/Model): Liner top Packer?: Yes x No Liner hanger test pressure: Centralizer Placement: Bow spring centralizers on each joint in shoe track,every other joint to 300'f/surface CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 11.0 ppg Volume pumped(BBLs) 69 bbls Lead Slurry Type: Class A extended Yield: ✓ 2.44 ft3/sk Density(ppg) 12.0 ppg Vol pumped(BBLs/sx) 255 bbls/586 sx Mixing/Pumping Rate(bpm): 5 bpm Tail Slurry Type: Class A Conventional Yield: s/ 1.22 ft3/sk ' Density(ppg) 15.4 ppg Vol pumped(BBLs/sx) 80 bbls/368 sx Mixing/Pumping Rate(bpm): 3.5 bpm N Post Flush(Spacer) Type: Density(ppg) Rate(bpm): Volume: il Displacement: Type: Spud Mud Density(ppg) 10.4 ppg Rate(bpm): 6.9 bpm Volume(actual/calculated): 272 bbls/275 bbls FCP(psi): 1146 Pump used for disp: Rig pump Plug Bumped? X Yes No Bump press 1300 Casing Rotated? Yes X No Reciprocated? X Yes No %Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: e''""� 159 bbls Cement In Place At: 14:30 Date: 1/31/2013 Estimated TOC: surface Method Used To Determine TOC: 12.0 ppg returns @ surface weighed with PSI scales Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry w Type: . a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): 0) Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: o Displacement: co Type: Density(ppg) Rath(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes No Reciprocated? Yes No %Returns during job Cement returns to surface? Yes No Spacer returns? Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: . WELLHEAD Make Seaboard Type SMB-22 Serial No. 1-1245745 Size 16 3/4 x 11 W.P.3000/5000 Test Head To 3000 PSIG 10 MIN X OK Remarks: Debra Oudean Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Ililr ir� t1 isk:i.1.1Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 4/12/2013 To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTA SCU 13-27 Prints: SRU 13-27 Formation Log MD 2" & 5" SRU 13-27 Formation Log TVD 2" SRU 13-27 LWD Combo Log MD 2" SRU 13-27 LWD Combo Log ND 2" SRU 13-27 Drilling Dynamics MD 2" SRU 13-27 Drilling Dynamics TVD 2" SRU 13-27 Gas Ratio Log MD 2" SRU 13-27 Gas Ratio Log ND 2" SRU 13-27 Final Well Report.doc SRU 13-27 Final Well Report.pdf CD: Final Well Data , (L., DAILY REPORTS oC DML DATA Final Well Report LAS Files LOG PDF Files LOG TIFF Files Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Re ei d : Date: • c '7 Schwartz, Guy L (DOA) From: Schwartz,Guy L(DOA) Sent: Tuesday,April 02, 2013 8:39 AM To: 'Chad Helgeson' Subject: RE:SRU 13-27 perf adds -p Zt Chad, These perfs won't require a new sundry as you are in the same pool. Just report the operations in the final well report. Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Chad Helgeson [rnallto:(hdgesona.hlicorpcom] Sent: Monday,April 01, 2013 2:05 PM To: Schwartz, Guy L(DOA) Subject: SRU 13-27 perf adds Guy, I sent a request to you a couple weeks ago about possibly adding the H12 perfs to the SRU 13-27(new drill well)after we complete some testing. I would also like to request the addition of an additional 18ft in the top of the H13 sand. We would like to perforate 11,592-11,610'in this zone. We already have 11,612-11,631' perforated. I assume this is not an issue, but wanted to check with you before we went forward with adding perforations in this well. If you could let me know on the perforating of the H12 in this well too would be greatly appreciated as well. This was the interval 11,555'-11,578' (23'). Let me know if you have any questions or need additional information. Chad Helgeson Operations Manager North Kenai Asset Team Hilcorp Alaska, LLC Office: 907-777-8405 Mobile: 907-229-4824 1 Schwartz, Guy L (DOA) From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, March 19, 2013 1:59 PM To: Schwartz, Guy L(DOA) Cc: Kevin Eastham Subject: SRU 13-27 Additional Perfs 2/2_— / I f Guy, We are probably looking at adding the H12 sand to the SRU 13-27 well,depending on the results of the H13 test. I did not include these in the original sundry that we submitted. The proposed additional perfs in the H-12 are: 11,555'—11,578' (23'). We will probably be adding these after our test of the H-13 in the next 2 weeks. Let me know if you have any problems or concerns with adding these zones in this well. Chad Helgeson Operations Manager North Kenai Asset Team Hilcorp Alaska, LLC Office: 907-777-8405 Mobile: 907-229-4824 1 Swanson River Unit Well: SRU 13-27 PROPOSED PTD: 212-181 API: 50-133-20607-00 ilileorp Alaska, LLC KB-TNF: 18.6' CASING DETAIL t \--/ - [ Size Type Wt Grade Conn. ID Top Btm 16' 16„ Conductor—Driven to _ - Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 1-80 Buttress 9.875" Surf 3,001' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,985' ' 5" Prod Lnr 15 1-80 DWC/C HT 4.283" 10,793' 11,835' TUBING lo-3/4"4 46 12-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,805' 21 ID `S iN ;1 JEWELRY DETAIL 31 hi No. Depth ID OD Item i 1 2.44" - Tubing Hanger i. 2 8' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 16 port i 3 _. .3' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 16 port 4 ±8, ,.7' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 16 port 4 I 21 5 ±9,968' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 16 port 6 ±10,740' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 16 port Orifice ; 7 110,770' 2.313" 6.5" On/Off Tool w/X Nipple 8 r. ,10,775' 2.44" 6.675" Arrowset Mechanical Packer 5 1 ID 9 ±10,80` 2.313" WL Entry Guide w/X Nipple 6 7' I t. I y' 1"""^1 g Ir 4,04: PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 5/B"- /`4 - rt,;' -11,164' , '.108 110,629' 110,673' 44' 6 2-1/8"HC Future Proposed 9 H16 ±11,613 ,633' •11,042' ±11,062 20 6 3-3/8"HC March 2013 1113 ±11,642' 111,655' 111,0 '.089' 13 6 3-3/8"HC March 2013 If H3/4 Future ' r A �° s �1� Sccti7p� X13 '(/� f{r3 1113 6-3/4"Hole 5" E" TO=11,835'MD/11,314'ND PBTD=11,751 MD/11,171'ND Updated by CAH 03-06-13 (rOF�\I%%4.sTHE STATE Alaska Oil and Gas °fALASKA Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue O�cfit- Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Chad Helgeson Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Dave, Suite 100 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SRU 13-27 Sundry Number: 313-116 Dear Mr. Helgeson: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P Foerster Chair DATED this IPday of March, 2013. Encl. VE RECEISTATE OF ALASKA 4:1-AV<1) REMACR A 0 6 2 3 D ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair We1] Change Approved Program 0 Suspend❑ Plug Perforations❑ Perforate❑. Pull Tubin] Time Extension❑ Operations Shutdown❑ Re-enter Susp.Wel ❑ Stimulate❑ Alter Casing] Other. Complete ❑✓ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development D. 212-181• 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20607-00• 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123A Swanson River Unit(SRU)13-27• Will planned perforations require a spacing exception? Yes ❑ No ❑ 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399,A028406 Swanson River Field/Hemlock Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 11,835 ' 11,247 • 11,751 11,171 N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,001' 10-3/4" 3,001' 2,995 3,580 psi 2,909 psi Intermediate 10,985' 7-5/8" 10,985' 10,476' 6,890 psi 4,790 psi Production Liner 1,042' 5" 11,835' 11,247' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(It): •None None 2-7/8" 6.5#L-80 8rd EUE ±1,000 Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): N/A N/A 12.Attachments: Description Summary of Proposal Q • 13.Well Class after proposed work: Detailed Operations Program n BOP Sketch n. Exploratory n Stratigraphirn Development n• Service n 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 03/12/13 Oil ❑✓ . Gas ❑ WDSPL ❑ Suspended 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chad Helgeson Phone: 907-777-8405 Email chelgeson(d)hilcorp.com Printed Name Chad Helgeson Title Operations Engineer Signature ,:,, Phone 907-777-8405 Date 3/03 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. z. 4Mi Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: *. 3°4° Pc-. •&,P /e►5 rt— *-6( RBDMS MAR 12 22(M Spacing Exception Required? Yes ❑ No 121/ Subsequent Form Required: ire) l 07- /,p/a APPROVED BY / Approved by: ( 5 ' P �( COMMISSIONER THE COMMISSION Date:3-/7-/3 OFfritGoi/NIAL — 3Submit Form andApproved application is valid for 12 months from a date of approval. Anach in iicate \1 Well Prognosis Well: SRU 13-27 Hilcorp Alaska,LLC Date:3/6/2013 Well Name: SRU 13-27 API Number: 50-133-20607-00 Current Status: New Cased Oil Producer Leg: N/A Estimated Start Date: March 12th, 2013 Rig: Williams 405 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-181 First Call Engineer: Chad Helgeson (907)777-8405 (0) (907)229-4824 (M) Second Call Engineer: Luke Saugier (907)777-8395 (0) AFE Number: 1212875 Maximum Expected BHP: 4,150 psi @ 11,057' TVD Based on reservoir pressure samples Collected in open hole with formation testing tools in the H-13. Max. Allowable Surface Pressure: 0 psi Based on 6% KCI brine left in the well, fluid level will be maintained at surface for a static fluid gradient of 4,887 psi at bottom. Brief Well Summary This well was drilled with the Doyon Arctic Fox,January—March 2013. The completion and following work is proposed to be completed with Williams Rig#405. Notes Regarding Wellbore Condition The well will be cased with filtered 6%KCI brine. No open perforations. Completion procedure: 1. MIRU Williams 405 workover rig. 2. Pull BPV. 3. Circulate 6%KCI through kill string. 4. Set BPV in tubing hanger, ND tree, NU 11" BOPE and test to 250psi low/3,000psi high, annular to 250psi low/1,500psi high (hold each valve and test for 10-min). Record accumulator pre-charge pressures. a. Notify AOGCC 24hrs in advance to witness test. b. Notify BLM 48 hrs in advance of BOP test. c. Ensure winterization package is installed for the weather conditions. 5. POOH, LD kill string tubing. 1,vy 6. RU e-line 7. RIH and run CBL log 5"casing(11,751-10,790')and 7-5/8"casing(10,790-3,001'). Review CBL in intermediate section,determine if any remedial work is necessary to isolate the gas storage intervals. If additional remedial work is necessary a procedure will be sent to AOGCC and BLM for review for a block squeeze or isolation necessary to ensure that gas storage reservoir is isolated from other zones in wellbore. 8. Pending no remedial work is necessary RU e-line to perforate H13 Hemlock with 3-3/8" HC 6 spf guns. a. +/-11,642'-11,655' (13ft) Well Prognosis Well: SRU 13-27 Hilcorp Alaska,LLC Date:3/6/2013 b. +/- 11,613-11,633' (20ft) 9. POH and rig down e-line. 10. Monitor well and see if any losses or pit gains occur. (fill hole as necessary to maintain a fluid column). 11. RIH w/completion on 2-7/8" 8rd EUE tubing(mechanical packer and gas lift valves)as shown on proposed schematic, set packer at approx. 10,775ft. a. Land tubing in hanger. Close the lockdown pins. Minimize compression to 2-3 ft by using the on/off tools as necessary. � l i- t�?t 12. Drop RHCP plug in well and test casing_to 300Cfpsi and tubing to 3,000 psi, chart for 30 min ea. 13. Set BPV, ND BOPs, NU Tree,test tree to 5,000 psi. 14. Pull BPV. RDMO workover rig and equipment. 15. Turn well over to production. 16. NU piping and flowlines. 17. Gas lift well, unloading fluid from well, SI well leaving gas lift pressure on well. 18. RU slickline, PT lubricator to 3,000 psi Hi 250 low. 19. RIH and pull RHCP prong and plug. 20. RD Slickline. 21. Start production 22. Notify AOGCC of SSV testing within 5 days of brining well online. 23. Notify BLM of start of production within 5-days of production. 24. Perform flow rate test on H13 zone/interval. 25. Pending results of H13, perforate the H3/4 interval through tubing on a-line with 2-1/8" HC guns from approx.. 11,164'-11,208' (44ft). Attachments: 1. Existing Well Schematic(As proposed by Doyon work for completion) 2. Proposed Schematic 3. Williams BOP Schematic 4. Well proximity Map—No spacing Exception required. Swanson River Unit Well: SRU 13-27 07 11 EXISTING POST DRILLING PTD: 212-181 API: 520721U-31318-321- 0 133-206 -00 Hilcorp Alaska,LLC KB-THF: 18.6' CASING DETAIL ill p Size Type Wt Grade Conn. ID Top Btm 16" 16„ Conductor—Driven to Surf 80' r. Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,001' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,985' d 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,835' ti, TUBING 10-3/4" 7 'k':: 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf ±1,000' 44. ir 14 r `' t L Mt. *a k 14 7-5/8" A r 1, fi ft 1 ' "a 6-3/4"Hole 5„ 4o TD=11,835'MD/11,314'ND PBTD=11,751'MD/11,171'ND Updated by DMA 03-06-13 Swanson River Unit . . • Well: SRU 13-27 II PROPOSED PTD: 212-181 API: 50-133-20607-00 Hilcorp Alaska,LLC KB-THF: 18.6' CASING DETAIL a 1 L Size Type Conductor—Driven to Wt Grade Conn. ID Top Btm 16' t' 16„ - - Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" _ Surf 3,001' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 10,985' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 10,793' 11,835' TUBING 10-3/4" 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 10,805' 2 1 .. Iii 1y JEWELRY DETAIL 3 fNo. Depth ID OD Item d 1 18.6' 2.44" - Tubing Hanger 2 ±4,448' 2.44" _ 4.750" 3-1/2"SF0-1 Mandrel 8RD 16 port 3 ±7,320' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 16 port 4 ±8,917' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 16 port Lill 4 Al i 5 ±9,968' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 16 port 6 ±10,740' 2.44" 4.750 3-1/2"SF01 Mandrel 8RD 16 port Orifice 7 ±10,770' 2.313" 6.5" _ On/Off Tool w/X Nipple .70 ll 8 _ ±10,775' 2.44" 6.675" _ Arrowset Mechanical Packer 19 5 MI I 9 ±10,805' 2.313" WL Entry Guide w/X Nipple bi111 r t 6 f mt 8 , 'Jr! PERFORATIONS a r Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date s' * H3/4 ±11,164' ±11,208' ±10,629' ±10,673' 44' 6 2-1/8"HC Future Proposed 7-5/8" i 9 9 H13 ±11,613 ±11,633' ±11,042' ±11,062' 20 6 3-3/8"HC March 2013 H13 ±11,642' ±11,655' ±11,076' ±11,089' 13 6 3-3/8"HC March 2013 '' 4 1.„, H3/4 Future t H13 Y ; ¶' r 6-3/4"Hole 5" = ' r TD=11,835'MD/11,314'ND PBTD=11,751 MD/11,171'TVD Updated by CAH 03-06-13 Swanson River SRU 14B-27 and 13-27 03/05/2013 n,Icor, u.s•k.l.i.i.l. Swanson River SRU 14B-27 and 13-27 Williams BOP 2013 III it III drill iii iii t 1 ,--- 3.46' Shaffer 11"5M t1 ff1 frtlInliffl a a Shaffer LWS : ® _ 2.75'_ 6 ,_iE-' .11 11 SM -lf� , 2 1/16 10M Choke and Kill ` a • a — -— Valves �C � ' . J 1 t = .�;J� f : 2.00' �' :�'�:' _ I .. ■1 maul'. ffl a , ...,—.1l !. 13I , i c): ir 1.1..... ... ,m.,.., , , . _ . 11. _,- ,1 t' • ( Legend • SRU 13-27 (P1)Surface Location X SRU 13-27 (P1)Top of Productive Horizon SRU 13-27 (P1)TD Horizon (BHL) �• I ———- SRU 13-27 Well Track •' / • L _- •SRU 13-27 1000 foot radius z•z •,'I Surface Hole Location ,• ,, ., ,' SRU 12-27 BHL • Bottom Hole Location .•i7- -- ®Field Boundary ."�'' KGSF7 BHL , •/ P KGSF3 BHL. ,/ 1 • , / I KGSF2BHL41r / I / / I / SRU_13- 7 prop BHL / , / .. i SRU 13-27 (P1) _�' SRU 23-27 BHL — �KGSF7A BHL 1TD Horizon (BHL) --' SRU 13-27 (P1) , ;Top of Productive Horizon\I I S008N009W A028399 I I A028406 I I I I i I SRU 314-27PB ll ` ' SiRU 314-27 BHL • ® ! •SRU 314-27PB1 BHL I ASRU_14B-27 prop BHL I I .z J , , z. I I ' ,I , / ' SRU 13-27 (P1) I . �''��Surface Location —= •----- E SRU 21A-34 BHL SRU 32A-33 BHL Swanson Riser Unit II 0 1,000 2,000 SRU 13-27 Feet N Alaska State Plane Zone 4,NAD27 A Hilcorp Alaska,LLC November 8,2012 �, �, • • • Legend _ ' Surface Hole Location .''',/,' SRU 12-27 BHL • Bottom Hole Location /� '' O Abandoned Well / KGSF7 BHL /' ——— Well Paths tKGSF3 B . ,1 iField Boundary / / KGSF2 BHL i / - -____: / ER • ED / -/ •• /KGSF7A BHL SRU 23-27 BHL — - SRU 223-28 BHL SRU 13-27 Bottom Hole Location SRU 13-27 / Top and Bottom of Productive Interval 1. r` A028406 SRU 314-27 BHL A028399 f OSRU 314-27PB1 BHL I / 1 S008N009W , SRU 14B-27 BHL Ii 1/° / 1 i / —— —— i/ /. 1--- SRU 13-27 ' Surface Hole Location _.-- --- - SRU 21A-34 BHL EID En SRU 32A-33 BHL • Soldotna Creek Unit A028990 tSU 343-33 BHL / SCU 13-34 BHL r ., II 0 1,000 2.000 Swanson River Field Feet SRU 13'27 Alaska State Plane Zone 4, NAD27 A Hilcorp Alaska,LLC Map Date:March 7,2013 • I / / • Legend I //.//// Surface Hole Location /. ./ SRU 12-27 BHL • Bottom Hole Location / 'l,' / I Abandoned Well KGSF7 BHL // —— Well Paths KGSF3 B /// I I Field Boundary / KGSF2 BHL I I / , / / / / / \� I KGSF7A BHL SRU 23-27 BHL — / s SRU 223-28 BHL ' )SRU 314-27 BHL A028406' '� A028399 SRU 14B-27 eSRU 314-27PB1 BHL Bottom I tole Location] S008N009W \ SRU 14B-27 f,. / Top and Bottom r' .._-of Productive interval / r / SRU 14B-27 f (Surface Hole Location / •-_-- SRU 21A-34 BHL SRU 32A-33 BHL • CsklifitAila4 <..I t.;LF 1_,1it4 A028990 tS' U 343-33 BHL / / SCU 13-34 BHL 1 / 0 1,000 2,000 Il Swanson River Field Feet SRU 14B-27 Alaska State Plane Zone 4, NAD27 Hilcorp Alaska,LLC Map Date: March 7, 2013 Davies, Stephen F (DOA) From: David Duffy [dduffy@hilcorp.com] Sent: Thursday, March 07, 2013 3:17 PM To: Davies, Stephen F (DOA) Cc: Judy Stanek; Chad Helgeson; John Serbeck; Kevin Tabler Subject: RE: SRU 13-27 Sundry Application Attachments: SRU_14B-27_Permit403_v02.pdf; SRU_13-27_Permit403_v02.pdf Steve— Thanks for your email below. I've attached a revised maps of both SRU 13-27 and 14B-27. These will be the only two well open to the Hemlock in the SW1/4 of Section 27,T8N, R9W, SM. Other wellbores referenced in that quarter section (e.g., SRU 314-27 and 23-27) are not open to production. Therefore, no spacing exception will be required for either SRU 13-27, 14B-27 under Conservation Order 123A. Sorry that was not clear the first go-round. If you need any additional information, don't hesitate to call. David Duffy, Landman Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage,Alaska 99503 Office: 907 777-8300 Direct: 907 777-8414 Fax: 907 777-8580 Cell: 907 301-2629 Email: dduffv@hilcorp.com This email may contain confidential and/or privileged information and is intended for the recipient(s)only. In the event you receive this message in error, please notify me and delete the message. From: Davies, Stephen F (DOA) [mailto:steve.davies@aalaska.gov] Sent: Thursday, March 07, 2013 2:28 PM To: Chad Helgeson Cc: Judy Stanek Subject: SRU 13-27 Sundry Application Chad, Spacing for SRU 13-27 is currently regulated by Conservation Order 123A, which specifies: "Not more than two completed wells are allowed in any governmental quarter section." The productive portion of SRU 13-27 lies in the SW1/4 of Section 27,T8N, R9W, SM. According to Hilcorp's plat that is attached to the Sundry Application to perforate SRU 13-27, several other wells also lie within that same quarter section. Are any of these other wells open to the Hemlock Oil Pool in that same quarter section? If so, a spacing exception application will be required. Thanks, Steve Davies AOGCC 907-793-1224 1 • / J . , , • Legend 1 • Surface Hole Location // ,/ SRU 12-27 BHL • Bottom Hole Location ,/,e'�, L�` Abandoned Well ,/ KGSF7 BHL / ——— Well Paths r , . KGSF3 BHL' ' I Field Boundary / / KGSF2 BHL /fa FR ,. /KGSF7A BHL SRU 23-27 BHL — • ..— / SRU 223-28 BHL SRU 13-27 Bottom Hole Location / 1 SRU 13-27 Top and Bottom of Productive Interval /. A028406 t SRU 314-27 BHL A028399 / SRU 314-27PB1 BHL / S008N009W i �f /,,r7 SRU 14B-27 BHL // / s dr / /., —- I / /' SRU 13-27 !/.' .........../ Surface Hole Location' - SRU 21A-34 BHL CO (39 SRU 32A-33 BHL • Swanson River Unit 1 Soldotna Creek Unit A028990 tS,U 343-33 BH4 SCU 13-34 BHL I i/f 1 0 1,000 2,000 Swanson River Field Feet SRU 13'27 Alaska State Plane Zone 4,NAD27 A Hilcorp Alaska,LLC Map Date:March 7,2013 —� i / / / / / / / / • Legend / 4 Surface Hole Location //' 4/'' SRU 12-27 BHL • Bottom Hole Location /4..'/ / 1 o Abandoned Well KGSF7 BHL --— Well Paths P KGSF3 BHL/ // I / Field Boundary iKGSF2 BHL f I I I / I I ` I Ea I .� I KGSF7• BHL SRU 23-27 BHL I SRU 223-28 BHL A028406 1 SRU 314-27 BHL A028399 1 SRU 14B-27 : .SRU 314-27P81 BHL Bottom Hole Location S008N009W SRU 14B-27 Top and Bottom / of Productive Interval /'* rr/ SRU 14B-27 ,Surface Hole Location�/ /t / .-__ SRU 21A-34 BHL CO e3 SRU 32A-33 BHL • Swanson River Unit A028990 'SU 343-33 BHL Soldotna Creek Unit I SCU 13-34 BHL 1 fl / 0 1,000 2,000 II Swanson River Field Feet SRU 14B-27 Alaska State Plane Zone 4, NAD27 N11 Hilcorp Alaska,LLC Map Date March 7,2013 Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Saturday, February 16, 2013 8:47 PM To: Luke Keller Cc: Mike Leslie; Paul Mazzolini; Rance Pederson -(C) Subject: Re: SRU 13-27 (PTD#212-181) Luke , Change to well plan is approved. . Please send me updated cement plans and and an updated schematic as soon as possible . Guy Sent from my iPhone On Feb 16, 2013, at 9:04 AM, "Luke Keller" <lkeller@hilcorp.com> wrote: > Guy, > We are going to try and set the 7-5/8" casing slightly deeper than specified on the APD. We are planning on drilling the 9-7/8" hole to 10,700' instead of 10,000' . > This is an attempt to ensure we have all the lower tyonek water flow behind the 7-5/8" casing. > We are currently drilling ahead at 9,200' . We should be approaching this new TD target on Mon or Tues next week. > Let me know if you have any questions or need anything else from me concerning the revised casing point. > Thanks, > Luke Keller > Sent from my Windows Phone 1 Page 1 of 2 Schwartz, Guy L (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Monday, February 18, 2013 9:38 AM To: Schwartz, Guy L (DOA) Cc: Paul Mazzolini; Mike Leslie; Rance Pederson-(C) Subject: SRU 13-27 (PTD: 212-181) Revised 7-5/8" Casing Point Attachments: SRU 13-27 Proposed Well Schematic 2-18-2013.doc; SRU 13-27 Revised 7.625in Cmt Calcs.docx Guy, See attached revised WBD and cmt program to reflect the deeper setting of our intermediate string of 7- 5/8"casing. I went ahead and pushed the casing point to 11,000' (we will be setting the 7-5/8" shoe somewhere between 10,700'and 11,000'). Regarding the cmt calculations,we will still use 1000' of tail cmt,and TOC planned at 4000'. I reduced the OH excess from 50%to 30%on the lead slurry based off observations made on SRU 14B-27. The days vs depth for SRU 13-27 is below. Let me know if you have any questions or need anything else from me concerning this change to APD. 2/19/2013 Page2of2 SRU 13-27 Days Vs Depth jI 2000 - -SRU 13-27 Plan -SRU 13-27 Actual -SRU 148-27 4000 6000 a v 8000 a v 10000 \t. 12000 • 14000 16000 0 10 20 30 40 50 60 I Days Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 2/19/2013 Page 1 of 2 Schwartz, Guy L (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Monday, February 18, 2013 9:38 AM To: Schwartz, Guy L (DOA) Cc: Paul Mazzolini; Mike Leslie; Rance Pederson -(C) Subject: SRU 13-27 (PTD: 212-181) Revised 7-5/8" Casing Point Attachments: SRU 13-27 Proposed Well Schematic 2-18-2013.doc; SRU 13-27 Revised 7.625in Cmt Calcs.docx Guy, See attached revised WBD and cmt program to reflect the deeper setting of our intermediate string of 7- 5/8"casing. I went ahead and pushed the casing point to 11,000' (we will be setting the 7-5/8" shoe somewhere between 10,700'and 11,000'). Regarding the cmt calculations,we will still use 1000' of tail cmt, and TOC planned at 4000'. I reduced the OH excess from 50%to 30%on the lead slurry based off observations made on SRU 14B-27. The days vs depth for SRU 13-27 is below. Let me know if you have any questions or need anything else from me concerning this change to APD. 2/19/2013 Page 2 of 2 SRU 13-27 Days Vs Depth 0 — 2000 -SRU 13-27 Plan -SRU 13-27 Actual -SRU 14B-27 4000 6000 L { 8 8000 10000 12000 14000 16000 -r 0 10 20 30 40 50 60 Days Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 2/19/2013 Cement 7-5/8" Cement Procedure 1. Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. 2. R/U cmt head(if not already done so). Ensure top and bottom plugs have been loaded correctly. 3. Pump 5 bbls 13.5 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 4. Pump remaining 35 bbls 13.5 ppg spacer. Drop bottom plug. 5. Mix and pump slurry per below recipe. 6. Cement volume based on annular volume+30%open hole excess. Section: Calculation: Vol(BBLS) Vol(ft3) LEAD: (10,000'- 4000') x .038 bpfx 296 1664 9-7/8" OH x 7-5/8"csg: 1.30= Total Lead: 296 bbls 1664 ft3 TAIL: (11,000' — 10,000') x .038 bpf 57 320 9-7/8" OH x 7-5/8"csg: x 1.50 = TAIL: 90' x .046 bpf= 4.1 23.2 7-5/8" Shoe Track: Total Tail: 61.1 bbls 343 ft3 Slurry Information Stage Lead Tail System Conventional Conventional Density 14 lb/gal 15.3 lb/gal Yield 1.58 ft3/sk 1.35 ft3/sk Mixed Water 8.09 gal/sk 5.912 gal/sk Mixed Fluid 8.09 gal/sk 5.962 gal/sk Expected Thickening 5:301-IR:MIN 4:00 HR:MIN Expected ISO/API Fluid Loss 13 mL in 30 min Code Description Concentration Code Description Concentration G Cement 94 lb/sk WBWOB G Cement 94 lb/sk WBWOB D110 Retarder 0.05 gal/sk D110 Retarder 0.05 gal/sk VBWOC VBWOC Additives D046 Anti Foam 0.2%BWOB D046 Anti Foam 0.2%BWOB D020 Extender 4.0%BWOB D202 Dispersant 1.5%BWOB D065 Dispersant 0.3%BWOB D400 Gas Control Agent 0.8%BWOB D800 Retarder 0.2%BWOB D154 Extender 8.0%BWOB D 174 Expanding Agent 1.5%BWOB 7. After pumpmg cement, drop top plug and displace cement with mud. Displacement calcs: • 10910' x .0459 bpf= 500.7 bbls. • Displace with 9.5 ppg 6%KCl/PHPA drilling fluid(if feasible) 8. Monitor returns closely while displacing cement. Adjust pump rate if necessary. 9. Do not overdisplace by more than '/2 shoe track volume. Total volume in shoe track is 4.1 bbls 10. There should be no cmt returns to surface. TOC is planned to be at 4000' MD. Swanson River Unit • 11 Well SRU 13-27 Planned Planned WBD !1 I,,,,, \I.,-k..LI 1: illi iiiiiiiik Casing & Tubing Wt Grade Conn, ID Top Btm I \/ l Conductor- 16" � L� 16" Driven to Set 109 X-56 Weld 15" Surf 80' Depth 21 h1 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,001' 29.7 L-80 BTC 6.75" Surf 7500' 7-5/8" Intermediate P-110 31 hl 29.7HC BTC 6.75" 7,500' 11,000' 10-3/4"L 1, - 5" Prod Lnr 15 L-80 DWC/C 4.283" 10,800' 11,598' 4 r h Tubing 3-1/2" Production 9.2 L-80 IBT IBT 2.441 Surf 10,700' 51 111 .1E LLRY L)LTA1L No. Depth ID OD Item 61 h1 1 20' 2.44" - Tubing Hanger 2 1,300' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 71 6 3 2,400' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 4 3,500' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 5 4,600' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 81 1116 5,200' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 7 6,200' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 911 1 hl 8 6,900' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 10 9 7,900' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port I 1 10 10,660' 2.000" 6.5" On/Off Tool w/X Nipple ii 3E 3: = 11 10,680' 1.978" 4.140" Arrowset Mechanical Packer Il 12 10,700' - WL Entry Guide w/X Nipple 7-5/8" 12 Il000 p 0 1 i r I L-10 re:Ct--0-A. <-2— /g-/3 5" L TD=11,598/TVD=11,109' Undated by LEK 2/18/2012 � %, � THE STATE Alaska Oil and Gas • 711 °fALASKA Conservation Commission " - rti GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99524 Re: Swanson River Field, Hemlock Oil Pool, SRU 13-27 Hilcorp Alaska, LLC Permit No: 212-181 Surface Location: 780' FNL, 651' FEL, SEC. 33, T8N, R9W, SM Bottomhole Location: 1862' FSL, 212' FWL, SEC. 27, T8N, R9W, SM Dear Mr. Mazzolini: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this r day of December, 2012. cc: Department of Fish 86 Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA AL \OIL AND GAS CONSERVATION COMMI N PERMIT TO DRILL 20 AAC 25.005 a.Type of Work: lb Proposed Well Class: Development-Oil 0. +Service- Winj ❑ Single Zone 0. • 1 c.Specify if well is proposed for: Drill 0 I Lateral ❑ Stratigraphic Test El Development-Gas❑ Service-Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrit El Reentry ❑ Exploratory IJ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2 Operator Name: 5. Bond: Blanket 0 Single Well ❑ 1 11.Well Name and Number: Hilcorp Alaska,LLC Bond NoP,2zg3.,i2 • 22036-263• Al2/101 SRU 13-27. 3 Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Anchorage,AK 99524 MD: 11,598• - TVD: 11,109.. Swanson River Field/ 4a. Location of Well(Governmental Section). 7.Property Designation(Lease Number): Hemlock Oil Pool• ' Surface: 780'FNL,651'FEL,Sec 33,T8N,R9W,SM ' w' iZ/ A028399,A028406. Top of Productive Horizon: - 8.Land Use Permit: 13.Approximate Spud Date:/ 1484'FSL,72'FWL,Sec 27,T8N,R9W,SM• N/A Jan 6ths-T•1 '0 t 3 ' • Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 7 -42- 1862'FSL,212'FWL,Sec 27,1-8N,R9W,SM• 4,800 acres • '/� /t y • 4 W 7Zal , 4t.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: 182.6 feet• 15.Distance to Nearest Well Open 1,• it-- Surface: 1rSurface: x-347031 •, y-2465662 • Zone-4 GL Elevation above MSL:164 feet . , to Same Pool: 1500'(SRU 14B-27) Y. 16.Deviated wells: Kickoff depth: 500 feet • 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 23 5 degrees. Downhole: 3000 psig• Surface: 2187 psig• 10.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks f Hole Casing Weight Grade upling data) .. 13-1/2" IlikBT 1 1 C 3000 1 1 3000 2995 323bbl@ 12 ... 73.7 bbl @ 15.4 9-7/8" BTC 9000 1 1 900C 8678 9-7/8" :. , BTC 1000 9000 1 1 1 1 9617 285bbl@l4 •.• 70.6 .. ©15.3ppg 6-3/4" •1 LJDW /C HT 1800 9800 9430 11598 11109 76.1 bbls, 15.3ppg Class"G" 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural MIIIIIn=rill Surface Intermediate • Production IM MIIIMIIMMIDIMMIIMI Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): POG 20 Attachments: Property Plat 0 BOP Sketch 0 Drilling Program 0 Time v.Depth Plot 0 Shallow Hazard Analysis❑ Diverter Sketch 0 Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative. Date ( 1/Z0/ C%2v`�D 1 Z.. 22. I hereby certify that the foregoing is true and correct. Contact f/q(,uL/VI,4ZZOL./A1/ -� A� Email �l1l lG-3�o I,vii h'Ic a3 ;,nted Name /JL. f3 �ZC�L/1.1 I Title ��I LL 1 fN G !'I Email co • :gnaturePhone go 7-777-83(D4 Date / 70c.t.catleviy-d---- z,cj/z• Commission Use Only I'ermit to Drill API Number: Permit Approval / See cover letter for other Number: a/2.( 81 r 50-133- 0(o Off- -00 -00• Date: requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: U Other: 1---4400c) pat eine 7j- Samples req'd: Yes❑ No[7f Mud log req'd:Yes❑ No[7f ZOIPO!Diu r A� 03�H2S measures: Yes❑ No[/ Directional svy req'd:Yes[r Non {i t uL't'f-.' Li cc-%Ue-•.12Spacing exception req'd: Yes❑ No[•1/ Inclination-only svy req'd:Yes❑ No21 r ,te--- 5u_kt-Ger 7 v-7.--------s- C , APPROVED BY ) ;\pproved by: , / COMMISSIONER THE COMMISSION Date:/ /� 11l lZ •/3•/2- del iv 'v 0 RI I terctiti:). Submit Form and �\��0 This permit is valid for 24 months f om the date of approval(20 AAC 25.00518)) Attachments in Dupl�ca � HilcOIp Paul Mazzolini Hilcorp Alaska, LLC eowcompt y Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 11/15/2012 Tel 907 777 8369 Email pmazzolmi@hilcorp.com Commissioner Alaska Oil &Gas Conservation Commission RECEIVED 333 W. 7th Avenue Anchorage, Alaska 99501 NOV 2 12012 Re: Swanson River Unit 13-27 AOGCC Dear Commissioner, Enclosed for review and approval is the application for the Permit to Drill the Swanson River Unit 13- 27. SRU 13-27 is a grass roots Hemlock development oil well planned to be re-drilled in a NE direction from the existing SRU 41-33 pad. SRU 41-33 has been permanently plugged and abandoned.• Drilling operations will be conducted by the Doyon Arctic Fox. The Arctic Fox is a 400 kip, multi- module drilling unit with a telescoping doubt s mast. zv( C7- 17- Drilling operations are expected to commence approximately Jan 6th, 2442-depending on the progress of other ongoing projects. Pursuant to 20 AAC 25.055(a)(3), a spacing exception is NOT required: 1. SRU 13-27 does not fall within 500 ft of a property line where ownership or landownership / changes. 2. It is not a gas well. 3. It is the only well to be completed within the SW quarter section of Section 27, and is / more than 1000'from any other well capable of producing from the same pool. Pursuant to 20 AAC 25.005(c) &(d), the following is included: 1. Plat identifying the property on which the well will be drilled. 2. Diagram&description of blowout prevention equipment. 3. Information on drilling hazards. a. (5) formations will be penetrated that are potentially hydrocarbon bearing. MASP calculations are attached per 20 AAC 25.005(c)(4)(A) b. Potential target reservoirs and their predicted pore pressures are indicated in attached Drilling Program. 4. Formation integrity test procedure. 5. Planned casing &cement program (Drilling Program) 6. Diverter and diverter line schematic. 7. Drilling fluid program (Drilling Program) 8. Tabulation of predicted depths with equivalent formation pressures. 9. Requirements of 20 MC 25.025 have been met. a. Blanket bond issued for Swanson River, bond no. 2 3 2-1(-F35 2L/Y 10. Copy of Well Specific Drilling Program. " Il zs, i z_— Hilcorp Alaska, LLC Page 1 of 2 11. General description of waste disposal. Operator does not wish to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. a. Drilling waste (cuttings and water based drilling fluids) will be disposed of at the Swanson River G&I facility. 12. Requirements of 20 AAC 25.050(b) have been met. a. Plat showing path of proposed wellbore including all adjacent wellbores within 200' is attached. b. All wellbores within 200'of proposed wellbore are owned by Hilcorp. If you have any questions, please don't hesitate to contact myself at 777-8369 or Luke Keller at 777- . 8395. Sincerely, Rajzi7-iiet,vicre Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC Page 2 of 2 Surface Use Plan Swanson River Unit Well SRU 13-27 Surface Location Anticipated: 788' FNL, 650' FEL, Sec 33, T8N, R9W, SM Existing Road: The proposed SRU 13-27 within the «nit boundaries of the Swanson River Field. The roads in the field are suitable for transportation of the drilling rig and support equipment. The road leading into Swanson Field is within the boundaries of the Kenai National Wildlife Refuge and is also suitable for rig transport. Sterling, Alaska is the nearest town to the site and is approximately 25 miles south of the well site. A map showing the location of the proposed well site and access route to the site is included in Figure 1. New or Constructed Access Roads: There will be no new roads or road upgrades required for the drilling of this well. Location of Existing Wells: SRU 13-27 is a grassroots development oil well planned to be drilled on the SRU 41-33 pad. A map showing all known wells within a one-mile radius of the proposed SRU 13-27 is included in Attachment 2. Location of Existing and/or Proposed Production Facilities: New well SRU 13-27 will be connected to existing production facilities. A new flowline, gas lift line, and gas lift heater will be tied into the new well and have been addressed in a separate sundry notice. No other road or pad modifications will be required to drill the well. Location and Types of Water Supply: Existing water sources in Swanson River Field will be utilized. Available sources include the Alaska Department of Natural Resources permitted water well at TS 1-33. All water use will be tracked in compliance with applicable permits. Water will be transported via vacuum truck from water wells to the rig location. Construction Materials: No road upgrades will be needed to allow for rig access. Stockpiled clean gravel picked up from roads within Swanson River Field will be used to level the pad if needed. Methods for Handling Waste: Drilling muds and cuttings: Excess mud will be hauled from the rig pit system or storage tanks to an ADEC permitted drilling fluid containment area at SCU 243- 04 Pad. Excess cuttings will be stored in the ADEC permitted solid waste storage cell at SCU 43-04 Pad. Muds and cuttings will be injected in SCU 43-04 WD pending approval of a Grind and Inject unit in Swanson River Field. Brines& Completion Fluids: Eligible fluids will be hauled to a permitted Class II disposal well in Swanson River Field for disposal. Garbage: All household and approved industrial garbage will be segregated and transported to the Kenai Borough Central Peninsula Landfill for disposal. Chemicals: Unused chemicals will be returned to vendors or utilized in future operations. Sewage: All sanitary waste will be contained on-site and hauled off-site by a designated contractor. Ancillary Facilities: A trailer will be staged on the pad to house various supervisory personnel and a minimum number of support personnel. The remainder of the drilling crew will be housed at a temporary camp staged at nearby pad 12-27. Well Site Layout: Attached Figure 3 shows the existing pad, the access road to the location and the proposed well location. There will be no reserve pit on location. A plan view layout of , the Doyon Arctic Fox is provided in Figure 4. Plans for Surface Reclamation: No surface disturbances are required for drilling this well. Access will be on existing roads within Swanson River Field, and the well will be drilled from an existing pad. No pad expansion will be required. Approval for final abandonment of the well and location will be obtained from the BLM and U.S. Fish and Wildlife Service prior to any reclamation work. Surface Ownership: The surface lands of the Swanson River Field and the roads leading into the field are within the Kenai National Wildlife Refuge, and are managed by the U.S. Fish and Wildlife Service. Other Information: The Doyon Arctic Fox rig will be used to drill the well. A plan view layout of the rig is provided in Figure 4. SRU 212-1f Pad 11 7 8 9 10 11 12 let Ave SRU 16-09 ad So Pad '..»_..\111..._"�'� _"SRU 21115 Pad SRU 2I�,SPBa"""" ISRU 4115 Pad i i p'y 1 - 2-15 Vgi SRU 3215Paa—yr 1a 18 17 16 15\ 1, 15 0---SRU 23-15 Pad 4 1 J88 SRU 4315Pad 'SRU 234-15 Pad RU 2122 Pad—4 SRU 4,2-22 SRU 32-22 Pad SRU 3'23 Pad W 21 41ISRU222-2,Pad Paas SIO8NO1OW S008N00922 2.1 7L 19 20 1st Ave SRU 16-22 Pad SRU 331-27 Pad\ SRU 41-28 Pad SRU 223211 Pad' t 5,12127 Pad 512U 12-27 Pad SRU 32-27 Pad 2', 30 29 26 SPU 43-28 Pad 27 26 2 J SPU 34-28 Pad } SRU 13-27 '' (` Proposed • -,.,_,., - ��t'ei ';. Paa/� RU S2-34 ' .�.P �v. SRU 11-33 Pad 'I.... ' �� SRU]3-33 Pad �— ^~` —414{\ SRU 1,2-34 Pad4 .."-,, / 32 31 32 33 34 35 .` 36 '� SRU 23-33 Pad SCU 33-33 Pad i8/ SC Y SCU 43-33 Pad 1st Ave SCU 34-33 Pad 1 SCU 21-04 SCU 41-04 P. 3S -0TS 'l Cu 21-03 Pad SCU 32-05 2nd Ave‘'OFFICE U 12-03 Pad Paa\aSCU 3Paa-" ' Cs1 1,3 1 6 5 `--, 2 4 SCU 23-04 Pad 3 SCU z3-03 Pad 2 1 CU 43-05 Patl i SCU 43-04iP atlx ,.%. SCU 243-04 Pad iSCU 34-04 Pad SCU Se taa Pad SCU Pad ,-03 Pad -03 Pad SCU -05 }SCU .3 seu 1-02 P.a Pa,A, a St S007N009W SCU 32-08 PadX3,2-0SPaa SCU 32-09 Pad' Se Pad""3-' P4%,... aa 10 13 8 seu 26]-0ew SCU 43-08 Pa miso 1st Aven11 2 SCU 43-09 Pad 9 A St SCU 14-05 Pad 34.03 Pad SCU 34-0e Pad `�,, cu f MAIN GATE SCU P. SCU 21 f�..�'.� 1:118 17 .. 16-,e Pad 15 14 13 Swanson River Field Map Scale 1:32,000 Figure 1 Alaska State Plane 4 NAD 1927 2 lGlnnp 01,rk,.1.1.11 Miles ELD S>— ELDctrl 42 r otms • -2 TS .� EEO .&T7 } ii RIM) Ef0 sS4 .,.;ESo ffiCP KGSF2+SRO D3 a" t1y3J MVP gt1+72 ea)ff3�ekJ tk�3J d SR %CO Pal RGSF1 7. P&S YARD 111 a JGkZl ciao EGO1 MO SRU 13-27 Proposed Location 24-33WD'*- 1-33 TS gaggi ETD aa= MEI EPrORD ta.ao ODD CID P @WI cl&K,PEA =' lr,- C3�--eS3� 434.3-•33 OW 4.3 -33 DZO&3=. 1 ��JJJIII E J Ea—alElao 3?-�'}9 Ego O ESO: OM&L=X Q30 ff>° ECJ 6 'ID 'tm cel=X] II54g Prxi aMl9WO Peri JTdril EO SRF Field tagO MOF DO*, Overview E{ 7 E0£s-06 Pali' -.3 Pal 6 1GW.Ped37500 6 � L'rl [ PrAreaect cov x=Q /11=&3 E(fi *, ? DoD f5 ix7*'EOD! Et17 3140,3 ELa?l Jp C ( ztl 5531 41 J3 gFj=00 son Egs..J® Fb3=55 sGm ELSEMC@ 701 ��ir� E07 41-+X1 111 Legend N SRU 13-27 1 inch=1,250 feet n * Surface Wells Proposed Well /V 0 SRU 13-27 Proposed Location Feet Map Date.11/16/2012 Figure 2 0 2,000 4,000 OOne Mile Radius Buffer • - -__ -. .,...t.,:„. , OM1` - „ x.. - x A. " } Via= *r0M t•• °c € " ..fes tic, .. 'i •` a° o- ' . » s ,SRU I3-27 Proposed SRU 41 33* Surface Location, SRU 41-33 Pad' 4 SN-..63 Qs AJ 41.,..0.., --••..;_ �22R c 't A a ,. ,...,. moi:.... , RF Field , S IP,:. - Overview 't• ' Ir rte 6 :a it rt. > r ill r y. Legend SRU 13-27 Proposed Well N SCU 41-33 Well Pad 1 inch=50 feet A - Surface Wells Feet Map Date 11/1612012 0 SRU 13-27 Proposed Location Figure 3 0 50 100 r 51 0 (�d15 Big."II h tz Z_ .aS gilt "tet .i < it e Z J>- �9iS °"g$f-"6 a O J iilla69 _g o°t m a O oq? 5" ;"a o < a w m„f-F42 s [wS9'£L].01.-.117 H z H m m n w co LL f( 0 00 M • �� © t= Zai CL Z WC9 I � : I- 1,44, a Oix tq F O coo - oz I--g a 0 1-<0 (. ortla o �Q y= W 0 [ jm: Ib m LLI i� oIX cr�,oU,2 Q uj Za 1-=1 - 4 .- CI PJ CE c rdub 0 x _ U e, 14 k ci- 0 v ~W 0CI- 0 Ill• ui__ip� man �yf, �. W x W O 0 F 0=SOU 1 Il ��i cto, mo � zWW 47 zxOOo I , r ... =. 03>o w oza I-CLL. IL w�. .:L IIC_'i 1� �m8n a—I-<0- ui ia1111 = .r LIJ CL ce IlliyI ;= Ij MS-.l 0 z W g /7 0 W CO W dr unclog JIIII11 �' i�■MI :Ili Ir' h 7__� j� it O 1- o Ln C w I ce IIMMI1111Ir1�n;1 / a 'Wan i..r � min =”" it and iiii 4 ii yjv a i' itJa . a� IIII E. Eiti=11C 11- Ell11•I IIIII�lin I I I 1.� :_iiia■■■■_i�:A� it I`I ry u III. _mei 1 • I i�al i rte: Jr mA v- 00 zix z � U 1-- N �Ja W JJ we ;00 Z2 av �m0 =~ 2zm 0 0Jz 0I-1_ O [wzz.90.,E-,ES [w96'9Z1.01.-,99 \ Hilcorp Alaska, LLC SRU 13-27 Drilling & Completion Program Swanson River Revision 0 Nov 8, 2012 Hilcorp Alaska, LLC Hilcorp Energy Company Changes to Approved Permit to Drill Date: Nov 20, 2012 Subject: Changes to Approved Permit to Drill for SRU 13-27 File#: SRU 13-27 Drilling and Completion Program Any modifications to SRU 13-27 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. Section Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date SCU 13-27 Changes to APD Nov 2012 Swanson River Unit 13-27 Hilcorp Drilling Procedure Energy Company Contents 1.0 Well Summary 2 2.0 Tubular Program• 3 3.0 Drill Pipe Information• 3 4.0 Planned Wellbore Schematic 4 5.0 Drilling/Completion Summary 5 6.0 Mandatory Regulatory Compliance/Notifications 6 7.0 R/U and Preparatory Work 8 8.0 21-1/4"2M Diverter N/U and test 9 9.0 Drill 13-1/2"Hole Section 11 10.0 Run 10-3/4"Surface Casing 14 11.0 Cement 10-3/4"Surface Casing 16 12.0 BOP N/U and test 18 13.0 Drill 9-7/8"Hole Section 19 14.0 Run 7-5/8"Production Casing 25 15.0 Cement 7-5/8"Cement Procedure 27 16.0 Drill 6-3/4"hole section 30 17.0 Run 5"Production Liner 34 18.0 Cement 5"Production Liner 37 19.0 Wellbore Clean Up&Displacement 40 20.0 RDMO 40 21.0 BOP Schematic 41 22.0 Wellhead Schematic 42 23.0 Days Vs Depth 43 24.0 Geo-Prog 44 25.0 Anticipated DrIg Hazards 45 26.0 Rig Layout 48 27.0 FIT Procedure 49 28.0 Arctic Fox Choke Manifold Schematic 50 29.0 Casing Design Information 51 30.0 9-7/8"Hole Section MASP 52 31.0 6-3/4"Hole Section MASP 53 32.0 Directional Program(P1) 54 33.0 Directional Plan View(Plot) 62 34.0 Spider Plot 63 35.0 Surface Plat(NAD 27) 64 36.0 Spider Plot(Governmental Sections) 65 37.0 Mud Weight,PP,FG vs Depth Plot 66 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 1.0 Well Summary Well SRU 13-27 Pad&Old Well Designation SRU 41-33 Pad/SRU 13-27 is a grass roots well • Planned Completion Type: Gas lift on 3-1/2"IBT production tubing Target Reservoir(s): Hemlock • Planned Well TD,MD/TVD: 11,598'MD/11,109'TVD PBTD,MD/TVD: 11,500'MD/11,018'TVD Surface Location(Governmental) 780'FNL,651'FEL,Sec 33,T8N,R9W,SM Surface Location(NAD 27) X=347031,Y=2465662 . Surface Location(NAD 83) X=1487054,Y=2465423 Top of Productive Horizon(Governmental) 1484'FSL,72'FWL,Sec 27,T8N,R9W,SM TPH Location(NAD 27) X=347779,Y=2467924 TPH Location(NAD 83) X=1487802,Y=2467686 BHL(Governmental) 1862'FSL,212'FWL,Sec 27,T8N,R9W,S BHL(NAD 27) X=347924,Y=2468300 BHL(NAD 83) X=1487947,Y=2468062 AFE Number 1212875 AFE Drilling Days 28 AFE Completion Days 7 AFE Drilling Amount $4.713 MM AFE Completion Amount $1.571 MM Work String: 5" 19.5#S-135 NC-50(Rental string from Weatherford) 4" 14#S-135 HT-38(Rental string from Weatherford) RKB—GL: 18.6' Ground Elevation: 164'AMSL • BOP Equipment 11"5M Schaffer Annular BOP 11"5M Schaffer Double Ram 11"5M Schaffer Single Ram Page 2 Revision 0 Nov,2012 intSwanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Energy Company 2.0 Tubular Program: Hole O (in) ID(in) Drift Conn Wt Grade Conn Burst Collapse Tension Section .. . (in) OD (in) (#/ft) (psi) (psi) (k-lbs) Cond 16" 15" - - 109 X-56 Weld 13-1/2" 10-3/4" 9.95" 9.875" 11.75" 45.5 L-80 BTC 5210 2480 1040 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 BTC 6890 4790 683 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 P-110 HC✓ BTC 9470 7580 769 6-3/4" 5" 4.408" 4.283" 5.563" 15 L-80 DWC/C 8290 7250 350 HT 3.0 Drill Pipe Information: Hole OD (in) ID(in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) All 4" 3.34 2-9/16" 4-7/8" . 14 S-135 HT-38 18,400 13,800 403 Page 3 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp 5.0 Drilling / Completion Summary SCU 13-27 is a grass roots development oil well to be drilled off the SRU 41-33 pad. Integrated subsurface and 3- D geological interpretations, in conjunction with previous production data, indicates that stranded oil reserves r remain in the Hemlock 1-5 benches between the F and G faults. High on structure, G2,H1-4,reserves aren't recoverable in existing wellbores due to lack of takepoints,or mechanical condition of other existing wellbores in the fault block. H10 sands may be productive as well. The base plan is a slightly deviated wellbore reaching a maximum inclination of 23.5 deg and a 2785' vertical separation. Drilling operations are expected to commence approximately Dec 29th,2012. • The Doyon Arctic Fox will be used to drill and partially complete the wellbore. The Williams rig or AWS #1 will be used to perforate the liner and run the 3-1/2"production tubing. n Sk� fZ 3/ " General sequence of operations: , ,., 1. MOB Doyon Arctic Fox to well site J 2. N/U & function test 21-1/4"2M Diverter 3. Drill 13-1/2"hole to 3000' MD. Run and cmt 10-3/4" surface casing. 4. N/D diverter,N/U &test 11"x 5M Hydril BOP. 5. Drill 9-7/8"hole section to 10,000' MD. Run wireline logs. Run and cmt 7-5/8" intermediate casing. 100,4 XcAfri 6. Drill 6-3/4"production hole section to TD. Run wireline logs. Run and cmt 5"production liner. 7. TIH w/clean out assy, clean out liner to landing collar. Displace mud to 6% KC1 filtered completion fluid. 8. TOH, LDDP 9. N/D BOP,N/U temp abandonment cap, RDMO Page 5 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp 6.0 Mandatory Regulatory Compliance/Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC and BLM regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drlg Team. • BOPs shall be tested at(1)week intervals during the drilling and completion of SRU 13-27. Ensure to provide AOGCC 24 hrs notice&BLM 48 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/4000 psi& subsequent tests of the BOP equipment will be to 250/4000 psi for 10/10 min(annular to 50%rated WP,2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 7 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • All Federal regulations within BLM"Onshore Oil and Gas Order#1" • Ensure both AOGCC&BLM approved drilling permits are posted on the rig floor and in Co Man office. . Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) to- 13-1/2" • 21-1/4"x 2M Hydril MSP diverter v1/4/A- �\ e 1 Function Test Only I • 1 1"x 5M Hydril GK Annular BOP Initial 250/4000 • 1 1"x 5M Hydril Double Ram alTest:2500 5 si o Blind ram in btm cavity (Annularpsi) 9-7/8" & 6-3/4" • Mud cross • 1 1"x 5M Hydril Single Ram Subsequent Tests: • 3-1/16"5M Choke Manifold 250/4000 • Standpipe,floor valves,etc (Annular 2500 psi) • Primary closing unit: 1 ea.—Olio, 6 station, 3000 psi, 180-gallon accumulator unit,with a remote control panel in the doghouse. • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Secondary back-up is an air pump, and tertiary emergency pressure is provided by bottled nitrogen. Page 6 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running&cement operations. • Any other notifications required in APD. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and cmt operations • 48 hours before BOPE tests • 48 hours before logging, coring, &testing • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-276-7542/Email:guy.schwartz@alaska.gov Victoria Ferguson/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.ferguson@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236 (During normal Business Hours) Notification/Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Tom Zelenka/BLM Petroleum Engineer/(0): 907-271-4224 (C): 907-301-8972 Justin Miller/BLM Petroleum Engineer/ (0): 907-271-3406 (C): 907-717-4039 Use the below email address for BOP notifications to the BLM: BLM_AK AKSO_EnergySectionNotifications@blm.gov Page 7 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Eneu CognanY 7.0 R/U and Preparatory Work 7.1 Set16" conductor at 60' below ground level. 7.2 Dig out and set"Cellar Tech" impermeable cellar. 7.3 Install slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 7.4 Level pad and ensure enough room for layout of rig footprint and R/U. 7.5 Layout Herculite on pad to extend beyond footprint of rig. 7.6 R/U Doyon Arctic Fox, spot service company shacks, spot&R/U company man&toolpusher offices. 7.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 7.8 Mix mud for 13-1/2"hole section. 7.9 Set test Plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped during N/U of BOP. 7.10 Install 5" liners in mud pumps. We will need all (3)pumps to pump at 60.0 - 650 gpm. • 750 HP PZH mud pumps are rated at 3912 psi with 5" liners. Page 8 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hi'C 2 c 8.0 21-1/4" 2M Diverter N/U and test 8.1 N/U 21-1/4" Hydril MSP 2M diverter System. • N/U 16-3/4" 3M x 21-1/4"2M DSA(Hilcorp) on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter"T" (Doyon). • Knife gate, 16" diverter line (Doyon). • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C) 8.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 8.3 Ensure to set up a clearly marked"warning zone" is established on each side and ahead of the vent line tip. "Warning Zone"must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 8.4 Set 15.375" ID wearbushing in wellhead. Page 9 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company Swanson River SRC 13-7 111t12012 Diverter Schematic For 13-W Hole Section • • III III III Ill lii Ilii Milli 21 2t,/ I1 lit I11 Ill 11i Knife Gate 111 ill 111 Ill ISM Diverter Tee,21!/a'x 21-W x I 21,1 vn'17 ANSI 150 outlet Ill Ill Ili Ill IiI 16-'/."3Mx21'/s"2M OSA Nig Ina ,111,411 Seaboard 15-'h 3M Casing head Assy 6, Page 10 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 9.0 Drill 13-1/2" Hole Section 9.1 P/U 13-1/2" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Bit TFA should be .739 in2. We need to pump at 600 to 650 gpm to clean the hole effectively. • Have DD run an independent hydraulic analysis to confirm optimum TFA. • Motor AKO should be set at 1.2deg. Max DLS in the 13-1/2"hole section(P1) is 1.5 deg/100 • Workstring will be 5" 19.5# S-135 NC-50 9.2 Primary bit will be the Hughes Christensen 13-1/2" MXL-1X. These are available at Baker Hughes facility in Anchorage. 13 1/2"&1XL-1h (se2i mm) • SEM II sealed beaniag package(SEM[MEM II sealed bearing pelage is a second generation patented single energir metal seal system nub proyeietat went resistant seal surface to retard seal wear.unpros'e seating efficiency'.and 'j provide long life n high RPM motor applications. gall k 1log 4 •• GS carting strncrm a terhnologr he outtmg structure presides adtmced r -� cone profile.re-engineered compact tooth shapes opisaed carbide grade., r and strateg colts placed cone satyrs Flexible hydraulics application specific ^^t' tee, t ,. thong ofbased oe tmi tied hvdnmdin con5gre non m msurc cg tonmo cane +f '•'" cloning.reiue3 ballsag.gad managed cone eroaoa Forlong Is/e gad high N,Ai.46010 A 40%. penetration Ater. 411, - - • Flenibk h.dnmins Application specific choice of biased or tmbmsed hi dmdic cor—tgamons to mane optimum cone cleaningtettaced bill.,end il managed cors errica For long life and high penetration rates • Enhanced ODproternon mprosed epphcmons ofEndtrn.mater hardfacingnes conrssed shirred eoonietts.and BOSS pads for near an point stabr:ia_oz Prs.ides excellent leg end shirttail nem resistance fa long life m duect:onal d^;li...e applications. 1 PRODUCT SPECIFICATIONS' --- t`s k' IARC. 117 R.4.ia- Beaing i Seal Package kw I/Meal v,`'4 Cutting Snunturp Inner Ron RA apses Cnriat•nsen Heel Ron RrA s„ve.svaaaamnpmet Gauge Ron N/A Gauge Tris NA A Tooth HacdfacinE NiA OD Hardfacmg 1trA Nozzle Tape Standard Center let Display- N A Makeup Torque. 28.0-32.0 klbf-ft(38.0.63.4101m) Connection: 6-5.1 API �.._.. A ShippinfWeight 255L(1157kg) Reference Part lstambei 112075000 OPERATING RECOILMENDATIONS•: Weight Oa Bit: 20-57.5111:49-21 In et kdaN) Rode=Speed Fee HO Speed Rotary Motor Applicaccas RA Maas flushes slri.te•.en i Vea Hughes Ctcnmtc Caper. Page 11 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Enemy Company 9.3 5" HWDP & Jars will come from Weatherford. 9.4 13-1/2"proposed BHA: • 13-1/2"MTB (IADC 117) • Mud Motor(1.2deg) • Non-Mag Stab (13-3/8" OD) • NMPC • MWD (Directional +Inclination Only) • (3)Non-Mag Flex collars • XO • (5) 5"HWDP • 6-1/4"Dailey Jar • (21) 5" HWDP • 5"DP to surface. 9.5 No LWD tools will be run on the 13-1/2"hole section. • 9.6 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 9.7 Drill 13-1/2" hole section to 3000' MD /2995' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 600 - 650 gpm. This gives us an annular velocity of 90 fpm, which is borderline for effective hole cleaning. Ensure shaker screens are set up to handle this flowrate. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep API fluid loss < 10. • TD the hole section in a good shale btwn 2900' & 3100' MD. • Take MWD surveys every stand drld. Page 12 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Energy Company 9.8 13-1/2"hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1)ppg above highest anticipated MW. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 1Oppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 80-3000' 10.0 ) 60-85 10-30 45-25 <10 8.5-9.0 System Formulation: Aquagel/FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 12-15 ppb caustic soda 0.1 ppb (9 pH) BARAZAN D+ as needed BAROID 41 as required for weight 10.5ppg PAC-L/DEXTRID LT if required for<12 FL ALDACIDE G 0.1 ppb X-TEND II 0.02 ppb 9.9 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 9.10 TOH with the drilling assy, handle BHA as appropriate. 9.11 No open hole logs are planned for the 13-1/2"hole section. Page 13 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 10.0 Run 10-3/4" Surface Casing 10.1 R/U and pull 15.375"wearbushing. 10.2 R/U Weatherford 10-3/4"casing running equipment. • Ensure 10-3/4"BTC x 5"NC-50 XO on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 10.3 P/U shoe joint,visually verify no debris inside joint. 10.4 Continue M/U&thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on (thread locked). • (1)Joint with coupling thread locked. • (1)Joint with float collar bucked on pin end&thread locked. • Install (2)centralizers on shoe track over a stop collar. 10' from each end. • Ensure proper operation of float equipment. 10.5 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Use"API Modified"thread compound. Dope pin end only w/paint brush. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 10,750 ft-lbs. • After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. • Install (1) centralizer every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 10-3/4" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 10-3/4" 10,750 ft-lbs Page 14 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company Casing and Tubing Performance Data PIPE BODY DATA GEOMETRY Outside Diameter 10.750 in Wall Thickness 0.400 in API Drift Diameter 9.794 in Nominal Weight 45.50 lbs/ft Nominal ID 9.950 in Alternative Drift Diameter 9.875 in Plain End Weight 44.26 lbs/ft Nominal cross section 13.006 in PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Tension Yield 1,040,000 in Internal Pressure Yield 5,210 psi Collapse Pressure 2,470 psi Available Seamless Yes Available Welded No CONNECTION DATA TYPE:ETC GEOMETRY Coupling Reg OD 11.750 in Threads per in 5 Thread turns make up 1 PERFORMANCE Steel Grade LEO Coupling Min Yield 80,000 psi Coupling Min Ultimate 95,000 psi Joint Strength 1,063,000 lbs Internal Pressure Resistance 5,210 psi 10.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10.7 Slow in and out of slips. 10.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 10.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 10.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 10.11 After circulating, lower string and land hanger in wellhead again. Page 15 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 11.0 Cement 10-3/4" Surface Casing 11.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. 11.2 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 11.3 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 11.4 Pump remaining 35 bbls 10 ppg spacer. 11.5 Drop bottom plug. Mix and pump cmt per below recipe. 11.6 Cement volume based on annular volume + 100% open hole excess. Job will consist of lead& tail, TOC brought to surface. � 6 lc- Estimated Estimated Total Cmt Volume: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: 80' x .106 bpf= 8.5 47.8 16" Conductor x 10-3/4" casing annulus: LEAD: (2500' —80') x .065 bpf x 2 = 314.6 1766.5 13-1/2" OH x 10-3/4" Casing annulus: Total LEAD: 323.1 1814.3 TAIL: (3000'-2500') x .065 bpf x 2 = 65 365 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 90 x .096 bpf = 8.7 48.8 10-3/4" Shoe track: Total TAIL: 73.7 414 Page 16 Revision 0 Nov, 2012 • Swanson River Unit 13-27 VA Drilling & Completion Procedure Hilcorp Energy Company Cement Slurry Design: Lead Slurry (2500' MD to surface) Tail Slurry (3000' to 2500' MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.44 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Code Description Concentration Code Description Concentration Type1 Cement 94 lb/sk WBWOB Type1 Cement 94 lb/sk WBWOB D110 Retarder 0.12 gal/sk VBWOC D046 Anti Foam 0.2% BWOB Additives D046 Anti Foam 0.2% BWOB D065 Dispersant 0.4% BWOB D079 Extender 2.0% BWOB S002 CaCl2 0.2 % BWOB D020 Extender 2.6% BWOB S002 CaCl2 0.2 % BWOB 11.7 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 11.8 After pumping cement, drop top plug and displace cement with 10.5 ppg 6% KC1/PHPA drilling fluid (mud and MW to be used on next hole section). 11.9 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 11.10 Displacement calculation: 2910' x .0962 bpf=280 bbls 11.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 11.12 Do not overdisplace by more than '/2 shoe track volume. Total volume in shoe track is 8.7 bbls. 11.13 Be prepared for cement returns to surface. 11.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Page 17 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp c�Y 11.15 R/D cement equipment. Flush out wellhead with FW. 11.16 Back out and L/D landing joint. Flush out wellhead with FW. 11.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 11.18 Lay down landing joint and pack-off running tool. 12.0 BOP N/U and test 12.1 N/D the diverter system. 12.2 N/U Seaboard multibowl wellhead assy. Install packoff 10-3/4"P-seals. Test to 3000 psi. 12.3 N/U 11"x 5M Hydril BOP as follows: • BOP configuration from Top down: 11"x 5M Hydril GK annular BOP/11"x 5M Hydril double ram/11"x 5M mud cross/Hydril single ram. • Double ram should be dressed with 5" Fixed ram in top cavity, blind ram in btm cavity. • Single ram should be dressed with Z, 5fir<asing ram. • N/U bell nipple, install flowline. 12.4 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/4000 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. ./ • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 12.5 R/D BOP test assy. 12.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 12.7 Mix 10.5 ppg 6%KC1/PHPA drilling fluid for 9-7/8"hole section. 12.8 Set 10" ID wearbushing in wellhead. 12.9 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. Page 18 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Ewaa COY 13.0 Drill 9-7/8" Hole Section 13.1 P/U 9-7/8" "Drill Out" assy consisting of: • 9-7/8"Mill Tooth Bit (Baker Hughes MXL-1)(IADC 117) • 9-3/4"Near Bit stab (bored for float) • Pony Collar • 9-3/4" String Stab • (1) 6-3/4"DC • 9-3/4" String Stab • (2) 6-3/4"DC • XO • (5) 5"HWDP • Drilling Jar • (21) 5" HWDP • 5"DP to surface 13.2 Ensure BHA components have been inspected previously. 13.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 13.4 Bit for the clean out run will be the Baker Hughes 9-7/8"MXL-1. These are available at Baker Hughes facility in Anchorage (style sheet on next page). 13.5 Bit TFA should be between 0.55 and 0.65 in2. We need to pump at a minimum of 500 gpm to clean the hole effectively. Have the directional drillers run hydraulics calculations to confirm optimum TFA. Page 19 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company Till 9 7/8" h IXL-1 BAKER (250.8 mm) HUGHES ■ SEM II sealed bearing package(SEM II)SEM II sealed bearing package is a second generation patented single energize'metal ie al )40 system with pioplietar;wear resistant seal surface to retrad seal weal. impro':e Baling efficiency.and plo.,ide lour life in hi g]I RPM moto1 applications. 0.11 I at ¢ ■ GXcutting structure technology The cutting snit:hue paos.ides advanced cone paafile,.re•engineered compact tooth shapes.optunized carbide made..and strata ri,mlly placed cone save's. ■ Flexible hydraulics Application specific choice of biased a tnibiased hydraulic configurations to encore optimum cone cleaning.'educed o, balling,and managed cone ea Dim).For long life and high penenation rates ` ■ Boss Stabilization Sy steuiThe--e unique Cate.pated stabilizer,provide neat six-point contact with the boaehole wall fa unequaled stability and cutting:3311:11111 protection. to Ir,1,31::. CL)pi_,rci nImpla';ed applications ofEndtna_motor hardfacmg.new contoured shim ail geouyehy.and BOSS pads fa near ix point stabilization.Protides>•:;chart leg and shirttail weal resistance.fa long life in duectiontl dulling application:. ..` Product Specifications IADC: 117 Sealing Seal Package: Journal+Metal Cutting Structure £ Irma Row Supa Thick Heel Row Bi-Metallic II Gauge Row Super Gauge Gauge Tainnnel l N A Tooth Haldfacing: N A OD Haldacing o Mot Nozzle Type_ Standard Cents Jet Display: FF aVF Makeup Torque: 28.0-32.0 klbf-ti.36.0-43.4 kNm) Connection: 6-5'S REG API Approx.Shipping Wei est 145 lb;65.6 kg) Reference Part Number: H2O64901 Operating Recomfnendations*: Weight On Bit 173-45klb(?-20toorkdaN) Rotation Speed: For High Speed Rotary lotaa Applications *The manes ofnil weiea:and RPM loonsa-a:e?:esexa:raveof:s,icalope:a:a=_ pa:ar.e:En.3•a:will no:aecera_-tic yield o»xrs'o.Me o:lower.3iEin..:o s. I:i; R'R'll'.b,ikerhulle s.corn air a o�Tided :ne•noes brio of ben n•eizi:oat RPM Se:.ia s x.u5.sa.i i y ;•2112 Baha I'saglue bcorp seated Allriglee mewed .ontac:.Tom local E:ntes:t is:ea ea:exesaz:ire for:e:oasai?_:ions in y,r.r a a•. Page 20 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling & Completion Procedure HilEnecao 13.6 TIH to TOC (+/- 2900' MD). 13.7 R/U and test casing to 1500 psi/ 30 min. Ensure to record volume/pressure and plot on FIT graph. 13.8 9-7/8"hole section mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1)ppg above highest anticipated MW. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 10.5ppg 6%KC1/PHPA fresh water based drilling fluid. Properties: Depths Density Viscosity Plastic Viscosity Yield Point HTHP FL pH 3000'-10000 10.5— 60- 100 15-30 20-30 <10 8.5-9.5 12.5 System Formulation: 6% KCI / PHPA Product Concentration Water 0.905 bbl KCI 22 ppb Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.1 ppb (as required 18+YP) DEXTRID LT 1-2 ppb EZ MUD DP 0.5 ppb (initial.15 ppb) ALDACIDE G 0.1 ppb BAROID 41 208 ppb (as needed to 12.5) 120' 13.9 Drill out plugs and shoe track. Clean out rat hole and drill an addition of new formation. 13.10 CBU and condition mud for FIT. 13.11 Conduct FIT to 13.5 p EMW. ~ Note: Offset field test data predicts frac gradient at the 10-3/4"shoe to be btwn 12.3 & 15.9 ppg EMW. A 13.S ppg FIT results in a 1 ppg kick margin in the event a 12.5 ppg MW is used later in the hoe section. Page 21 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Enemy Company 13.12 Drill 9-7/8"hole section to approx 3200' MD to allow all of 9-7/8"directional assy to buried (excluding HWDP and Jars). 13.13 CBU, TOH. L/D BHA. 13.14 P/U 9-7/8" directional drilling assy consisting of: • 9-7/8" PDC bit (Baker Hughes HCD504ZX). • Mud Motor(1.2deg) • Non-Mag Stab (9-3/4" OD) • NMPC • NaviGamma(D&I, + Gamma Ray) • (3)Non-Mag Flex collars • XO • (5) 5" HWDP • Dailey Jar • (21) 5"HWDP • 5" DP to surface 13.15 Ensure BHA components have been inspected previously. 13.16 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 13.17 Ensure TF offset is measured accurately and entered correctly into the MWD software. 13.18 Bit TFA should be between 0.778 in2. We need to pump at a minimum of 500 - 550 gpm to clean the hole effectively. DD should run independent hydraulics to confirm optimum TFA. 13.19 Motor AKO should be set at 1.2deg. Max DLS in the 9-7/8"hole section(P1) is 2.5 deg/100. 13.20 Primary bit for the 9-7/8"hole section will be the 9-7/8" HCD504ZX PDC bit. It is available from Baker Hughes facility in Anchorage. Be sure to call out an insert bit to have available as back up. Page 22 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company IliiiIIII 9 7/8" HCD5O4Z.X TM BAKER (250.8 mm) GenesisHUGHES a • Applicado❑D Technology PDC bit are theproven solution for the ever in:lea:in!commplexity of directional application:and operator: p k tangle].pelfornnance objectives.In motor steerable.Iota*.steerable and ltical drilling applications our technology anhnncements offer r M..r superior peffoamance and duectional control. • EZ.Steer Technology Patented EZ Steer.depth-of-cut control technology Ives eagineel=-d bearing surface:to imp ove toolface control on motor steerable:y:tent and enhances petolmall.e on rotary steerable:y:tela:.The result 1:Unplowed dnectional petaamance and higher ROP:in all applications. • LGC Gauge Desien The bits gauge deign is optimized 61 the application to match the drive s}•sten.dog-1e s noun ement and formation chalacteiistics.LGC ;Length.Geometry and C uttine :tmctine)gang?design approach deliver,paedi:table and can:.i:tent z build aate without npiomi.ins hale quality. • Gece;isCutrel:.Our designei.can choose fiomadiveregroupof cutter,with a lanae of diamond table thi:ine::and diamond carbide interface:foi the ideal mix of argils:ivene::and divabihty. • Geue:i::CED H di:tunic.CFD analy:is is utilized foi e•:evy Genets: de sign and en sure:the optimum balance between flow.:utter cooling. and thrid notion. Reference Photo: 9-7:S in. (250.8nun) HCD504ZX Pmdnct kms IADC: M223 j `f Number of Blades: 4 L Critter Quantity;Total.Face): 53.2. s --. I. Pu iu.mr Cline]Size .625 in. 1S.S mm) Number of Ntt771e:: 6 ,, ,,,.. Nozzle Type: SP Fixed TFA 0 in' Q.0 mm'°) foolu . Gauge Length 4 in(101.6 mm) .i,` ' Junk Slot Area 12 S m-(52.5 cru) d 1' � , Bit Breaker 12321030 7.L 3210305.123215563 f :':. Cannaction: 6.5x5 API REG Makeup Toique: - ! ?1 2"—Bit Sub 37.1-42.4 kit-lb(50.3-57.f kNin) Reference Part Nrnnboi: Ni x112 Stam: Opel ating Recommendations-: Hydraulic Flow Rate: 403-953;pm:1533-34331pm) Rotation Speed: Fol Rotary.Motor.and Rotary Steerable Applications Max.\Veieht OD Bit: 2S kib;12 to of kdaN) 'the:amps afar weir.u and RPM saoan ase represesatice of,,}?icer opera:a g pa:asete:s.Sar will nx nevessa:ilv yield opx•.ix3i life o;loves:d±illioo co. I:is 1'i\\'W.biakerhuf11e S.COnl nor recoxmeoded ta'the upper:lix.in of 3o:2b weig3+.Jai F.PM ae ran szc•a3xneo.isly. ;2012 Baku E igtes)<rcotposaaed.Allriglts aetetted Contact wx lacal£.ie:es::a:is:as?a:eo:es aa:ive ix recormendatiaas in tree area. Page 23 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Enemy Company 13.21 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray LWD functioning properly. 13.22 Once on bottom, drill with light weight, and begin a new bottom hole pattern with the PDC bit. Do not be in a hurry to set down a bunch of weight and take off drilling. 13.23 Drill 9-7/8"hole section to 7500' MD/ 7268' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. • Take MWD surveys every stand drld. 13.24 At 7500', begin increasing MW slowly from 10.5 ppg to 12.5 ppg. Monitor well closely for any losses. If losses are observed, stop increasing MW and discuss forward plan with Anchorage drill team. 13.25 If MW is not at 12.5 ppg by 9000' MD/ 8677' TVD, stop drilling and inc MW to 12.5 ppg ,/ slowly before drilling ahead. r i '-r . 101-14,- vim i,,, 7e/7-7.7-VD -'kt .C .444 �r-e tee- ,s s C e e F.• Z 13.26 Drill to 9-7/8"hole section TD at 10,000' MD /9,617' TVD. if �� 13.27 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4" shoe. 13.28 TOH with the drilling assy, stand back BHA if possible. 13.29 R/U and run OH logs consisting of: • Gamma Ray(GR) • Dual Spaced Neutron (DSNT) • Spectral Density Tool (SDLT), includes single axis caliper • X-Y Cross Dipole Sonic • Array Compensated Resistivity Tool (ACRT)—5 depths of investigation, includes Spontaneous Potential response (SP). 13.30 Monitor the well at all times on the trip tank while logging. 13.31 After logging objectives accomplished, pick up a wiper trip BHA and make another run to TD. Circ B/U at TD and TOH. Rack back DP,handle BHA as appropriate. Page 24 Revision 0 Nov, 2012 Swanson River Unit E413-27 Drilling & Completion Procedure Hilcorp Enemy Company 14.0 Run 7-5/8" Production Casing 14.1 R/U and pull 10" ID wear bushing. 14.2 R/U Weatherford 7-5/8" casing running equipment. • Ensure 7-5/8" BTC x 5"NC-50 XO on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 14.3 P/U 7-5/8"29.7# P-110 HC BTC shoe joint, visually verify no debris inside joint. 14.4 Continue M/U &thread locking the shoe track assy consisting of: • (1) Float shoe joint w/float shoe bucked on. Install (2)bow spring centralizers at 10' from each end over a stop collar. • (1) Baker locked joint. Install (1) centralizer mid tube over a stop collar. • (1) Float collar joint w/float collar bucked on pin end. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float shoe and float collar. 14.5 Run approx 1000' of 7-5/8" 29.7# P-110 HC BTC casing to ensure coverage across the lower A/ tyonek water flow. • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers over couplings on every other joint. 14.6 Run 7-5/8" 29.7# L-80 BTC casing above the P-110. • Install centralizers over couplings on every 4th joint from 9000' to 4000' MD. 14.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 14.8 Slow in and out of slips. 14.9 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe approx 10—20' above TD. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. Page 25 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company Casing and Tubing Performance Data PIPE BODY DATA GEOMETRY Outside Diameter 7.625 in Wall Thickness 0.375 in API Drift Diameter 6.750 in Nominal Weight 29.70 lbs/ft Nominal ID 6.875 in Alternative Drift Diameter n.a. Plain End Weight 29.06 lbs/ft Nominal cross section 8.541 in PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Tension Yield 683,000 in Internal Pressure Yield 6,890 psi Collapse Pressure 4,790p si Available Seamless Yes Available Welded No CONNECTION DATA TYPE:BTC GEOMETRY Coupling Reg OD 8.500 in Threads per in 5 Thread turns make up 1 PERFORMANCE Steel Grade L80 Coupling Min Yield 80,000 psi Coupling Min Ultimate 95,000 psi Joint Strength 721,000 lbs Internal Pressure Resistance 6,890 psi 7-5/8" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 7-5/8" 7,630 ft-lbs ✓ 14.10 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 14.11 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat(slightly) to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 14.12 Continue circulating until required properties achieved for cmt operations. 14.13 After circulating, lower string and land hanger in wellhead again. Page 26 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Energy Company 15.0 Cement 7-5/8" Cement Procedure 15.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. 15.2 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 15.3 Pump 5 bbls 13.5 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 15.4 Pump remaining 35 bbls 13.5 ppg spacer. Drop bottom plug. 15.5 Mix and pump slurry per below recipe. 15.6 Cement volume based on annular volume+ 50% open hole excess. Section. Calculation: Vol(BBLS) Vol(ft3) LEAD: (9000'- 4000')x .038 bpf x 285 1600 9-7/8" OH x 7-5/8" csg: 1.50 = Total Lead: 285 bbls 1600 ft3 TAIL: 1000' x .038 bpf x 1.50 = 57 320 9-7/8" OH x 7-5/8"csg: TAIL: 90' x .046 bpf= 4.1 23.2 7-5/8" Shoe Track: Total Tail: 70.6 bbls 396.2 ft3 & a (i Page 27 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company Slurry Information System Conventional Conventional Density 14 lb/gal 15.3 lb/gal Yield 1.58 ft3/sk 1.35 ft3/sk Mixed Water 8.09 gal/sk 5.912 gal/sk Mixed Fluid 8.09 gal/sk 5.962 gal/sk Expected 5:30 HR:MIN 4:00 HR:MIN Thickening Expected ISO/API Fluid Loss 13 mL in 30 min Code Description Concentration Code Description Concentration G Cement 94 lb/sk 94 lb/sk WBWOB G Cement WBWOB D110 Retarder 0.05 gal/sk D110 Retarder 0.05 gal/sk VBWOC VBWOC Additives D046 Anti Foam 0.2%BWOB D046 Anti Foam 0.2%BWOB D020 Extender 4.0%BWOB D202 Dispersant 1.5%BWOB D065 Dispersant 0.3%BWOB D400 Gas Control Agent 0.8%BWOB D800 Retarder 0.2%BWOB D154 Extender 8.0%BWOB D174 Expanding Agent 1.5%BWOB 15.7 After pumping cement, drop top plug and displace cement with mud. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement calcs: • 9910' x .0459 bpf=455 bbls. • Displace with 9.5 ppg 6% KC1/PHPA drilling fluid 15.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 15.9 Do not overdisplace by more than '/2 shoe track volume. Total volume in shoe track is 4.1 bbls 15.10 There should be no cmt returns to surface. TOC is planned to be at 4000' MD. 15.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. • If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Bleed off pressure occasionally as necessary. 15.12 R/D cement equipment. Flush out wellhead with FW. 15.13 Back out and L/D landing joint, flush out wellhead with FW. Page 28 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 15.14 M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger pack-off. Run in lock downs and inject plastic packing element. Test void to 250/3000 psi for 10 min. 15.15 Lay down landing joint and pack-off running tool. 15.16 Reduce MW in active pits from 12.5 ppg to 9.5 ppg. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Note: 9.5 ppg was chosen as the starting MW for SRU 13-27 to stay as close as possible to formation pressure (which is expected to be 5.5 ppg) but still allow for adequate suspension of cuttings and LCM. Wellbore instability is not perceived to be an issue at 9.5 ppg. The only formation that exceeds a 9.5 ppg gradient would be the lower Tyonek water flow. This formation is expected to occur at a depth of 9177' TVD, so it is not expected that we will have communication with the lower Tyonek with 7-5/8" casing set at 9617' TVD. The lower Tyonek water flow has been observed with gradients as high as 12.5 ppg EMW. Lower Tyonek is now mapped for the Swanson River Field, completed by Kevin E. Differential sticking of the drill string and the production casing significantly increases with increasing mud weights. The differential pressure across the Hemlock interval (10,904' TVD) with a 9.5 ppg MW is 2268 psi however increasing the mud weight to 12.5 ppg would increase the differential pressure to 3969 psi, an increase of greater than 70%. 15.17 L/D 5" DP from derrick. 15.18 P/U and rack 4"DP. 15.19 Install 4" liners in mud pumps. PZH pumps are rated at 5000 psi and 144 gpm @ 110 spm with the 4" liners. Page 29 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hila 16.0 Drill 6-3/4" hole section 16.1 Remove 5" & 7-5/8"casing rams from BOP. Install 4" fixed rams in top cavity& 2-7/8"X 5" VBRs. Test BOPs on 4" and 5"test joints. 16.2 Pull test plug, run and set wear bushing. 16.3 P/U 6-3/4" directional drilling assy consisting of: • 6-3/4" PDC bit(Baker Hughes QD505X). • Mud Motor(1.18 deg) • Non-Mag Stab (6-5/8" OD) • NMPC • NaviGamma(D&I, + Gamma Ray) • (3)Non-Mag Flex collars • XO • (5) 4"HWDP • Dailey Jar • (21) 4"HWDP • 4"DP to surface. 16.4 BHA Components have been inspected previously. 16.5 Drift& caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 16.6 Ensure TF offset is measured accurately and entered correctly into the MWD software. 16.7 Confirm that the bit is dressed with a TFA of 0.46 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 350 gpm. 16.8 Motor AKO should be set at 1.18 deg 16.9 Primary bit will be the Baker Hughes QD505X. Spec sheet attached on next page. Page 30 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 5;V'lt :htel MIIII 6 314" Q►D505X7M BAKER (171.5mm) uantec u HUGHES • Application Quante:Directional PDC bits combine the very latest in HCC bit technology-lieu in Class cutte.rtechnology.superior stability " and hydrauhc e'n ien together with a design philosophy that is ` 4 tailored to your drilling objectives.Deacus are customized to achieve ;4_} ' continual per:om.ance impro:zn ent in the toughest applications while mi,,;nazing bit:ibranon for enhanced tool life. ' • Diamond Volume Management Diamond V oluire.t.lanagement (DVM)designs ensure that neither ROY or stabihtyis compronize3 in „. the bit design Prone.and cutter placement are tailored to the application in order to acine:-e the longest nm length at high overall HOP. • Quante:(utters Quante:cutter oar the:=rvlatest in technology. Optimized diamond feed and engineered non-planer interfaces combine to gave Superior wear resistance and outstanding toughness.Speak to your HCC rep for the cutter best suited to your application. u Gauze P rete ction High quality 1St'material is utilized to gave superior wear resistance and thus long bit rims.Optional Hex-shaped 1St' matenal alloys tighter packing for ultra abrasive environments. r QD Gauge Design Engineers select gauge length and gauge geometry to - meet dogleg hole quality and system specidc requirements. Reference Photo: 6-3.4 in.(171.5111in)QD5O5X Product Specifications LADC: M323 • Number of Blades: 5 Cutter Quantity(total.t ace): 38.19 s N 4 Nnmar,-Cutter Size .625 in(15.8 mm) Number o:Nozzle,: 5 t' y Nozzle 1�}oe: NIS?. ; N 1-ixed11-A Uiu'(0.Uinn-) 0 IP lb ♦ Gauge Length 1.5 in(38.0 mm) ,. Q� ,� Jul Siot Area 8 in'(51.6 cm=) tiit Stealer: C I a..1010111 Connection: 3-112 API KEG Makeup torque: . 41,8"Hit Sub 5?-5.!k ft-lb(1.1-;.:kltim) 41/4"Bit Sub 6.3-1.0 kft-lb(8.5-9.5 kl\m) 41:2"+Bit Sub ..;-8.5 k$-lb(10.4-11.5 kNm) Reference Pari Niwiler: M856 Operating Recommendations*: Hydra tic Clow Kate: 250-550 gpm(950-2100 1pm) Rotation Speed: t or Rotary and Motor Applications Max.1i.eight On ltit: _'0 klb(9 m or kdaN) Page 31 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Ham cry 16.10 TIH to TOC. Shallow test MWD on trip in. 16.11 Test casing to 3000 psi/30 min. Ensure to record pressure vs volume plot to compare with FIT. 16.12 Drill out shoe track and 20' new formation. 16.13 CBU and condition mud to 9.5 ppg in/out for FIT. /� ct 16.14 Conduct FIT to 12 ppg EMW. Note: Offset field test data predicts frac gradients at the 7-5/8"shoe to be bwtn 14.4 ppg and 15.4 ppg. A 12 ppg FIT results in a 2.5 ppg kick margin while drilling the interval with a 9.5 ppg fluid density. 16.15 Drill 6-3/4"hole to 11,598' MD using above motor assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team,try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain HTHP fluid loss < 9. 16.16 Hilcorp Geologists will follow LWD log closely to determine exact TD. Plan on drilling to a maximum of 11,598' MD / 11,109' TVD. 16.17 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 16.18 TOH with drilling assy, handle BHA as appropriate. Drop drift on trip out. 16.19 R/U and run OH logs consisting of: / g • Gamma Ray(GR) S • Dual Spaced Neutron(DSNT) • Spectral Density Tool (SDLT), includes single axis caliper • X-Y Cross Dipole Sonic • Array Compensated Resistivity Tool (ACRT)—5 depths of investigation, includes Spontaneous Potential response (SP). Page 32 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Emir Company 16.20 Make a clean out run again to TD (if necessary). Utilize same (or very similar) BHA design to what was used to drill the well. This trip is discretionary, and will be determined by actual hole conditions. Page 33 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 17.0 Run 5" Production Liner 17.1 M/U and rack cement stand in derrick. • Ensure to drift components prior to M/U. Ensure dart will pass through components. • Confirm largest OD of packer assy will pass through wear bushing. 17.2 Install and test 2-7/8"x 5"VBR in lower cavity if not done previously. 17.3 R/U Weatherford 5" casing running equipment. • Ensure 5"DWC/C HT x 4"HT-38 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total#of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 17.4 P/U shoe joint, visually verify no debris inside joint. 17.5 Continue M/U&thread locking shoe track assy consisting of: • (1) Shoe joint w/shoe bucked on&threadlocked(coupling also thread locked). • (1)Joint with float collar bucked on pin end&threadlocked(coupling also thread locked). • (1)Joint with landing collar installed INSIDE pin end. • Solid body centralizers will be pre-installed on shoe joint&FC joint. • Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe. 17.6 Continue running 5"prod liner ✓ • Fill casing while running using fill up line on rig floor. • Use"API Modified"thread compound. Dope pin end only w/paint brush. • Install solid body centralizers on every joint to the top of the G-zone. Leave the centralizers free floating. • Install them on every other joint from the top of the G-zone (10,532' TVD)to the liner hanger. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 5"DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 5" 8,400 ft-lbs 9,400 ft-lbs 12,500 ft-lbs Page 34 Revision 0 Nov, 2012 Swanson River Unit Ill13-27 Drilling & Completion Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.: Weight(Wall): Grade: DWC/C-HT Casing 5 in 15.00 lb/ft(0.296 in) L-80 standard How J• Material '5:S L-80 Grade , ,.� • 80,000 Minimum Yield Strength (psi) t tsvggrA*4yu USA 95,000 Minimum Ultimate Strength(psi) VAM USA 4424 W,Sam Houston Pawy.Suide Ise Pipe Dimensions Houston,TX 77041 5.000 Nominal Pipe Body O.D.(in) Fax: 713 -�4s79-323400 00 4.408 Nominal Pipe Body LD.(irt) E-mail:VAMUSAs;,aset,na•,snouteu col„ 0.296 Nominal Wall Thickness(in) 15.00 Nominal Weight(lbs/Ft) 14.88 Plain End Weight(lbs/ft) 4.374 Nominal Pipe Body Area(sq in) Si,. 5 Pipe Body Performance Properties e 350,000 Minimum Pipe Body Yield Strength(lbs) ! 7,250 Minimum Collapse Pressure(psi) ^r' 8,290 Minimum Internal Yield Pressure(psi) 1, 7,600 Hydrostatic Test Pressure (psi) v-,i Connection Dimensions • < 5.563 Connection O.D. (in) ', 4.408 Connection I.D.(in) 4.283 Connection Drift Diameter(in) to 4.06 Make-up Loss(in) _ -;... e 4.374 Critical Area(sq in) 100.0 Joint Efficiency(%) :Pil, Connection Performance Properties 350,000 Joint Strength(lbs) 16,670 Reference String Length(ft) 1.4 Design Factor `e,^ Irk• 379,000 API Joint Strength(lbs) • 350,000 Compression Rating(lbs) 7,250 API Collapse Pressure Rating(psi) f`a 8,290 API Internal Pressure Resistance(psi) 73.3 Maximum Uniaxial Bend Rating(degrees/100 ft] = "'. Appoximated Field End Torque Values 8,400 Minimum Final Torque(ft-lbs) 9,400 Maximum Final Torque(ft-lbs) 12,500 Connection Yield Torque(tt-lbs) For detailed information on performance properties,refer to DWC Connection Data Notes on following pagets). Connechon specifications Within the control of VAM-USA were correct as of the date printed.Specifications are subject to change without notice.Certain connection specilcations aro dependent on the mechanical proportos of the pipe.Mechanical properties of mill proprietary pipe grades were obtained from mil:publications and are subject to change.Properties of mill piuprietary grades should be confirmed with the mill.Users are advised to obtain current connection specircations and verify pipe mechanical properties for each application. 10/30/2012 6:58:27 PM Page 35 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Energy Company 17.7 Ensure to run enough liner to provide for approx 200' overlap inside 7-5/8" casing. Ensure hanger/pkr will not be set in a 7-5/8" connection. 17.8 Before picking up Baker ZXP liner hanger/packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.9 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with"Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 17.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 17.11 RIH w/liner on DP no faster than 1-1/2 min/ stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 17.12 M/U top drive and fill pipe while lowering string every 10 stands. 17.13 Slow in and out of slips. 17.14 Circulate 1-1/2 drill pipe and liner volume at 7-5/8" shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. Nominal liner hanger setting pressure is 2500 psi. 60% of this value is 1500 psi 17.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 17.16 Continue to fill the DP every stand down using fill up line on rig floor. Do not stop to fill casing. 17.17 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 17.18 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure(1500 psi). Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17.19 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 36 Revision 0 Nov, 2012 Swanson River Unit lii13-27 Drilling & Completion Procedure Hilcorp Emmy Company 18.0 Cement 5" Production Liner 18.1 Hold a pre job safety meeting over the upcoming cmt operations. 18.2 Attempt to reciprocate the liner during cmt operations. 18.3 Pump 5 bbls 12 ppg MUDPUSH II spacer. 18.4 Test surface cmt lines to 4500 psi. 18.5 Pump remaining 15 bbls 12 ppg MUDPUSH II spacer. 18.6 Mix and pump 15.3 ppg class "G" cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 100% OH excess. Cement Calculations 7-5/8"x 4 DP"Overlap: (9,800—9,600') x 0.03 = 6.1 bbls 7-5/8"x 5"Liner Overlap: (10,000' —9,800')x 0.022 = 4.4 bbls 6-3/4"OH x 5"Liner: (11,598— 10,000')x 0.020 x 2 = 63.9 bbls Shoe Track: 90' x 0.019 = 1.7 bbl Total Volume(bbls): 6.1 +4.4 +63.9+ 1.7= 76.1 bbls Total Volume(ft3): 76.1 bbls x 5.615 ft3/bbl= 427 ft3 Total Volume(sx): 427 ft3 / 1.35 ft3/sk= 316 sx Page 37 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcor EnerlY Co Slurry Information: System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.912 gal/sk Mixed Fluid 5.962 gal/sk Expected Thickening 100 Bc at 05:57 hr:mn Expected ISO/API 15 mL in 30.0 min at 175degF/ 1000 psi Fluid Loss Code Description Concentration G Cement 94 lb/sk D198 Retarder 0.4% BWOC Additives D046 Anti Foam 0.2% BWOC D202 Dispersant 1.5%BWOC D400 Gas Control Agent 0.8%BWOC D154 Extender 8.0 % BWOC D174 Expanding Agent 1.5% BWOC 18.7 Drop DP dart and displace with 9.5 ppg drilling fluid. ✓ 18.8 Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 18.9 If elevated displacement pressures are encountered,position liner at setting depth and cease reciprocation. Monitor returns &pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 18.10 Bump the plug and pressure up as required by Baker procedure to set the liner hanger(20% above nominal setting pressure. 2500 psi is nominal setting pressure. Pressure up to 3000 psi to confirm hanger setting. 18.11 Slack off total liner weight plus 20k to confirm hanger set. 18.12 Do not overdisplace by more than %2 shoe track. Shoe track volume is 1.7 bbls. 18.13 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner. Page 38 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Enmity Cir 18.14 Bleed pressure to zero to check float equipment. 18.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 18.16 Rotate slowly and slack off 50k downhole to set the ZXPN liner top packer. 18.17 P/U to P/U weight plus 1 ft. 18.18 Close annular and test 4" DP x 7-5/8"annulus to 1500 psi/ 10 min to test liner top packer. 18.19 Bleed off pressure, open up annular. 18.20 Pressure up to 500 psi down DP and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops off rapidly, indicating pack-off is above the sealing area(ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 18.21 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 18.22 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 18.23 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 18.24 POOH, verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 18.25 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise)torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 18.26 NOTE: Some hole conditions may require movement of the drilipipe to "work"the torque down to the setting tool. 18.27 After screws have sheared,the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point,the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 39 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp linew Company 19.0 Wellbore Clean Up & Displacement 13.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 4-1/4"bit or mill • Casing scraper&brush for 5" 15# casing (MI Swaco - Multiback) • +/- 1800' 2-7/8" workstring. • Crossover(No PBR Polish Mills) • Casing scraper&brush for 7-5/8" 29.7# casing (MI Swaco - Multiback) • (5000') 4" HT-38 DP. • Casing scraper& brush for 7-5/8" 29.7# casing (MI Swaco -Multiback) • 4" HT-38 DP to surface. 13.2 TIH & clean out well to landing collar(+/- 11,500' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi-vis sweeps as necessary to carry debris out of wellbore. • Ensure 4-1/4"bit is worked down to the landing collar. • Space out the cleanout BHA so that the 4-1/4"bit reaches the 5" landing collar when crossover is+/- 30' above the 5" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. 13.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 3000 psi/30 min. 13.4 Displace drilling fluid in wellbore with a hi-vis pill followed by fresh water. • Catch drilling fluid in rain-for-rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7-5/8"multi-back assy to surface. • RIH again&tag landing collar w/4-1/4"bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by 6%KC1 after fluid has cleaned up satisfactorily. Target NTUs are 80 - 100. 13.5 TOH w/clean out assy. LDDP on the trip out. Note any abnormal wear on the mill assy. 20.0 RDMO 14.1 Install tubing hanger&back pressure valve. N/D BOP. _ CC3)°, 14.2 N/U temp abandonment cap. e�.v► J SSS 14.3 RDMO Arctic Fox. Page 40 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp Energy Company 21.0 BOP Schematic Swanson River SRL?13-27 I 11 Hydril Dorn Wiling ..,EQp 11"51.1 HyonlV6VP 1$1 4116/1/141 Hydril V - 1 1'-5700 ice_ - .. 'MI5' 11-$11111111i III 1:47:,. .1 )1.1 BR P OW . i'Q ' .1111Millr. J;11 tai 111 IH I/r HydNIY - - - 11"-5000 - — ()rpyg level III.IIi III Iti I11 Spacerepool 1.95' 11SM%115M u1 III 411111 I111 4i11.....r I=a.. Saabnani-MES systom �� 1A�:3A1%115M a- �� 4 _}-IIII.111111 lliP . ..��e�ls.■ : 11 mat ham • D Ille . . ,j) •.f+ii1 Ilik _, trg. ,,,' 74-1,. -:,,, _, -it.„.. JIM I ,.. . I . Page 41 Revision 0 Nov, 2012 Swanson River Unit H13-27 Drilling & Completion Procedure Hilcorp Energy Company 22.0 Wellhead Schematic HILCORP ALASKA, LLC SWANSON RIVER 112 HO-28489a LI c1 I r,T sommi 4 3-1/8 5V (io 'I:ii o., 3-1 fts:tu—... R�r p 10�� 4I A ili3-1/8 5V---....I Area itiA1 TCR, SM-E-2CW so'' ■I 17 SM X 3-1/A SY TUBING HANGER, SVS-2CL—__i_illt Imola Ti1 X 3-1/2:API MOD 60X KIM _1 5I X 3-1/7 EL; 8RD BOX TCP � •mf `' j r ■1 ,_ R. ■—L `mom■1:+t,2 :IE'I. I CASING HANGER. 5M8-22 ( t it X 7-5/8 1 _ 411 2-1 '6 EM TY/'SEAL AyiEVHLY , 0 17 TG-3/4IP5 .. n CASINO HANGER..5MB-226-32-1/16 571 16-3/4 X 10-3/4 _ l- _ /4 3M W/I1MAFIY SEAL t 1@ j 1 mmi u �r`� {. I 16 CASING 1.: 11, 2-1/'6 5M 10-3/4 CASINC.--.. 7-5/8 CASING lio. . ` 3-1/2 MING 3SEAP ARD 5,00: ''SI NELIHEAD&TREE ASSEMBLY 76 X 1G-3/4 X 7-`s/6 X 3-1/2 RESTRICTED CONF1DENT14L DOCUVENT - 'L ' «Li " HI [WOOw 1">IfB.M..ryEs2 �+' Page 42 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 23.0 Days Vs Depth SRU 13-27 Days Vs Depth a -- — — - — — 2000 4000 ` IP{ot Areal 2 6000 — — 10000 12000 14000 0 5 10 15 20 23 30 35 40 Days Page 43 Revision 0 Nov, 2012 Swanson River Unit H. 13-27 Drilling & Completion Procedure Hilcorp Energy Company 24.0 Geo-Pro t A B C 0 E F G H I J 1 GEOLOGICAL PM76714 515 2 3 WELL NAVE ..5a/ FEW:. Swanson River 4 SZAFA.CE.- X=S4683317 LONG:-150.8557 (SRU 41-33 Pad) STATE Alaska 5 Y=24655374 LAT:60.746 6 BOTIO+IhaE X=347522 7 -150.8501754 TVD REF DATUM KB 7 Y246'831717/ AT:60.7534460 TVD REF ELEV 183' 8 SY5TE,1 Aga GROUND ELEV 164' 9 F3'MCT12 IL 4;&7'ALW(.117TH7 10 11 r i=ettie. Drill deviated grassroots Hemlock well with Gas Lift completion in H1-5 sands to fill in well spacing-1500 from 12 proposed SRU 148-27 well. 13 CeoStamn,a, s Integrated subsurface and 3-D geological interpretations,in conjuction with previous production data 14 .krsta'Si, x+: indicates that stranded oil reserves remain in the Hemlock 1-5 benches between the F and G faults. High on 15 structure,G2,H1-4,Reserves aren't recoverable in existing wellbores due to lack of takepoints or mechanical 16 condition of other existin wellbores in the fault block.H10 sands ma be productive as well. y 17w. !,''I/wr:1arl-1i1.74:i'rl.JIA.Y.00iZ,47.+.7i'1h/Vd:if:i, IIIIIIIIIIIIIIIIIMIII 18 EY/W7Ff Critical Intersection Poin lap 19 117P NAME FOPMAT/OM ELLdGP fl'OIFTI TNLLS5I'FT1 Est Pre ccsrrn X Y +. Affi $0 21 Gas Sand Shallow gas sand gaslwet 446 -263 Normal same as surface s,y's +1-30' 446 22 B-6 Lower Sterling wet i 3,098 -2,915 Normal 347019.7 2465918.2 +1-30' 3126 23 LBGT Top Lower Beluga wet 4,295 j -4,112 __ Normal 347110.9 2466151.2 +1-30' 4349 24 D1CT 25'TyonekCoal wetlgas 5,715 1_, -5,532 Normal 347212.2 2466434.8 +1-30' 5801 25 64-5 Gas Storage Sand GAS 6,427 -6,244 2500-3300 psi 347273.0 2466576.7 +1-30' 6529 26 TYNK HP H2O Lower Tyonek WATER 9,177 -8,994 5200-5500 psi 347587.0 2467417.5 +1-50' 9441 ✓ 27 G2 Tyonek Oil OIL/WATER 10,532 -10,349 2800-3000 psi 347820.1 2468035.5 +1-30' 10950 28 HKT Top Hemlock Oil OIL/GAS 10,615 .1- -10,432 2800-3000 psi 347840.3 2468076.0 +1-30' 11041 29 H2-5 Hemlock Oil OIL/GAS 10,634 L -10,451 2800-3000 psi 347840.3 2468086.1 +1-30' 11063 30 H7-8 Hemlock Oil WATER 10,794 -10,611 2800-3000 psi 347870.7 2468157.0 +1-30' 11241 31 H10 Hemlock Oil OIL/WATER 10,904 *. -10,721 2800-3000 psi 347891.0 2468207.7 +1-30' 11363 32 TO Lower Hemlock 11,117 -10,934 347922.7 2468306.1 +1-30' 11600 33 34 =Primary Objective 35 =Secondary Objective P 'R TRANUS 75' 37 , 38 DATA COLLECTION REQUIREMENTS: 39 Mud Logging: Surface Casing to TO 40 LWD Data: 41 E-Line Log Data: Quad combo in intermediate and production hole sections. 42 43 COMPLETION TYPE Gas Lift 44 ANTICIPATED RATES -2,000 bpd gross 45 ARTIFICIAL LIFT EQUIPMENT OD 46 TUBING SIZE 3.5" 47 48 OTHER COMMENTS 49 1.Pressure of Tyonek 64-5 Gas Storage Sand can be up to 3,300 psi depending on w here we are in the injection cycle w hen we drill 50 2. The D1CT coal is the thickest,most continuous coal in Swanson River. We expect it to be approximately 25'thick at this location. 51 We expect about 25 other mappable coals(5-15 ft thick)in a 2200'thick interval stretching"350'above and 1850'below the DICT top 52 3.Evidence of shallow gas is only seen on logs in SRU 31-33WD. 53 4. 3D Time seismic data exists over the Swanson River Field 54 55 6.We do not anticipate crossing any significant faults that would pose drilling problems. 56, Page 44 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Enemy Company 25.0 Anticipated Drlg Hazards 13-1/2" Hole Section: Lost Circulation: Ensure 500 lbs of BaroFibre (Fibrous Cellulosic Material), 500 lbs SteelSeal (Angular, dual- composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Maintain 10ppb total of BaraCarbs/Barofibre/Steelseal while drilling the interval to control any seepage losses. Hole Cleaning: Maintain rheology w/ Aquagel & Barazan D+. Sweep hole w/ 20 bbls Barazan D as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25-40 to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. 9-7/8" Hole Section: Lost Circulation: Ensure 500 lbs of BaroFibre (Fibrous Cellulosic Material), 500 lbs SteelSeal (Angular, dual- composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal while drilling the interval to control any seepage losses. Hole Cleaning: Maintain rheology w/ Aquagel & Barazan D+. Sweep hole w/ 20 bbls Barazan D as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 13- 20 to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. Maintain MW as necessary using additions of Barite. Filtrate control in the <6 range is required. Maintain additions of PAC L / Dextrid LT to maintain API fluid loss of <6. Maintain 6% KCI in system for shale inhibition. Page 45 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal seams (BARO-TROL PLUS 4 ppb). • Increase fluid density as required to control the running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. Overpressured Lower Tyonek Waterflow: Maintain MW at a minimum of 12.5 ppg with additions of barite from 8500' to section TD. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. 6-3/4" Hole Section: Lost Circulation: Ensure 500 lbs of BaroFibre (Fibrous Cellulosic Material), 500 lbs SteelSeal (Angular, dual- composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal while drilling the interval to control any seepage losses. Hole Cleaning: Maintain rheology w/ Aquagel & Barazan D+. Sweep hole w/ 20 bbls Barazan D as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 13 - 20 to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. Maintain MW as necessary using additions of Barite. HTHP control in the <5 range is required. Maintain additions of PAC L / Dextrid LT to maintain API fluid loss of <5. Maintain 6% KCI in system for shale inhibition. Page 46 Revision 0 Nov, 2012 Swanson River Unit EIF13-27 Drilling& Completion Procedure Hilcorp a Company Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal seams (BARO-TROL PLUS 4 ppb). • Increase fluid density as required to control the running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: J H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. v' Page 47 Revision 0 Nov, 2012 Swanson River Unit H13-27 Drilling & Completion Procedure Hilcorp Energy Company 26.0 Rig Layout E.9."J I f.1E.-r] 53.-3'[16.22,r] U -+ o Q, C)zz n ez� 4 J. .U. J..r> rr 2 71 r C1 r; <0 nam 1 e s z F• • ii i A ! _ ■. .i.. - • ■ irm1 MIMMN , I— E]l.i •1.I 1� l.i f i:II�► t• IIIc 1_ �1�� x 7 v' $IJ111.16■`..1111.11 I_, I - it - llir1 bit ri ;4! o'-1uI) 1fs� �e - - Iiltr• Muim14r /9 7.. t 2 a>z 1 rym rr; 1-:jam- r � � �. V Vi O: T U 0 O rr m .=illi ra� R:i — ,15_-!!...1.-'., .41..Z --__ riQNNr Jx ofr) Y--. I © iiii ■ m...- - C C_ c i .�' .."l:si5 yr. O G .. C. 2= .rn .o �`i OPS y `'Oz J.lii ' I.�{ s..al.. ■' I rntn z u 0 O.4c I Z 1'CJn -I C X' m 4 — t135 ;117..1, ill nfl .1 S A I.: �a n -.� Igi lit o Q /� . 1L i Cs1E I � - t�t� v- z rn X @y; s- -1■iiiT� M E 3 UEL. 4 1 1 \\ m 0 rr t0 en r D — 11 D U y A 44 JI0'$1:.65mJ Page 48 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling& Completion Procedure Hilcorp 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drilipipe pressure until appropriate surface pressure is achieved for HT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 49 Revision 0 Nov,2012 Swanson River Unit H13-27 Drilling & Completion Procedure Hilcorp Energy Company 28.0 Arctic Fox Choke Manifold Schematic LEDGEND OP A K!TA JV ©' It No lrte mallyndlerV&ves 411:1 I111 Handle Valves ,. Normally Closed Ta F PITS 0 i 0 MBopSTACK 0i 41 FRo 11 eq) —5 • 1 RE 6 aft 012)6 `y' TO F PITS � I, G 10 B „1 TO pEGASSER i INIEZEMEMINIMI Item Descri'tion A 3-1/16"10M Remota Operated Hydraulic Choke d 3-1/8"5M Adjustable Choke !,- ll ills 1 2-1/16"5M Manual Gate Valve '; 2-14 t a ARCTIC FOX Page 50 Revision 0 Nov, 2012 Swanson River Unit int13-27 Drilling & Com@e|onProcedure Hilcorp En___ 29.0 Casing Design Information 0 g ° , 1& 07. 271' 292%q% /§ \ § [ � [) § E i t)§k)§§§ !I § §E M. !r oeoma %% ~E I {1 k § § § q( § kq a -, § ; r h & § 8- 8' & § 13-0 a �/ p `§ 2 �§ §§k § § # 7!ii P k 2 /§ # # % i§(§ k I 2 ■ § § 222 H II m / §0g§, §wli 2i (( Q§ 2 7; 2 @ ° ® ~�k s ( ) § tE t ) E ) kR §( r N!7 ;; ;® °Fk k k k \@t & k \ k l§( '1 G ; \ §„m 11 / Page 51 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 30.0 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Swanson River Unit 13-27 llilcorp • &T, ve• Kenai Peninsula,Alaska 9-7/8" Hole Section Assumptions: 1. Max Frac gradient at 10-3/4"shoe(2995'TVD)estimated at 15.9 ppg EMW(0.83 psi/ft) based on field test data. 2. Pore pressure at Gas Storage sand estimated at 3300 psi (.513 psi/ft) 3. Pore pressure at Lower Tyonek water flow estimated at 5500 psi (.599 psi/ft) Fracture Pressure at 10-3/4" shoe considering a full column of gas from shoe to surface: 2995(ft)x 0.83(psi/ft)= 2486 psi 2486(psi)-[0.1(psi/ft)*2995(ft)]= 2187 psi MASP from pore pressure(Gas storage sand at 6427'TVD) Max pore pressure at 6427'TVD: MASP(Wellbore evacuated to gas) 6427(ft)x 0.513(psi/ft)= 3297 psi 3297(psi)-[0.1(psi/ft)*6427(ft)]= 2654 psi MASP from pore pressure(Lower Tyonek Water Flow at 9177'TVD) Max pore pressure at 9177'TVD: MASP(Wellbore evacuated to water) 9177(ft)x 0.599(psi/ft)= 5500 psi - 5500(psi)-(0.4316(psi/ft)*9177(ft)1= 1539 psi Summary: MASP while drilling 9-7/8"hole is limited by fracture pressure at the 10-3/4"shoe Page 52 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 31.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Swanson River Unit 13-27 Kenai Peninsula,Alaska 6-3/4" Hole Section Offset Information Well Date Hemlock Pressure TVD Grad SRU 21A-34 2009 2975 10683 0.2785 SRU 32A-33 2010 2800 10637 0.2632 SRU 331-27 March, 2012 3140 10600 0.296 Assumptions: 1, Max Fracture gradient at 9,617'ND is estimated at 15.4 ppg EMW(0.801 psi/ft) based on field test data. 2. Based on offset drilling&well test data, Hemlock PP is anticipated at 2800-3000 psi (0.270 psi/ft). 3. Reservoir fluid gradient is anticipated at 7.7 ppg. Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface: 9617(ft)x 0.801(psi/ft)= 7703 psi 7703(psi)-[0.1(psi/ft)*9617(ft)]= 6741 psi MASP from pore pressure Max pore pressure at TD (11,109'TVD) MASP(Wellbore evacuated to gas column) 11,109(ft)x 0.270(psi/ft)= 3000 psi SIBHP-gas gradient to surface: 3000(psi)- [0.1(psi/ft)*11109(ft)j= 1890 psi Summary: 1. MASP while drilling 6-3/4" production hole is governed by SIBHP-gas gradient to surface. 2. MASP during production life is governed by SIBHP-gas gradient to surface. Page 53 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 32.0 Directional Program (P1) f6T gE I " ll ig " P" '°EUIU i rr , r , 'r" Iir. i � t 1I 141 [0 1 51 `3. ri- tf goer w . u. M NW * 0 aQ 4 �, , � I l i e s 44 Fill; -. a ii - RI Bq se ` 2! Z a i V 1 - 1 / gilal J P iis 1 � R '11 wpm III Page 54 Revision 0 Nov,2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 40 opt, oa W1g§.4§ ,11..-c4 8gz E. Z: _ � S8 Beg : 8; 88 + 148 g € 4. 44-70. 4 ♦ s r _ :. .." 83. ...._.8._.3. _ i7 t gi O I 4 0 0 oIo o a r, w v ur ..„,„ —• cw u1 to .W_o a 911 � — , i. J f kJ L G Vi C L §5 ,..,5 L'a i W W*I 0111811% § ig 0p0 .0pQ8pn0 —'�.� y memo** ft NOtll�f OfaNOMP3aN+ OO ,0000 I �"' 1 00 J. Jo* . -, 1 u fsa#aNz 0Va WN L.--a it W - f, " & . 11 111 _N a. , ' . N _a}IePi� i- ,000,11 01 o aN Ili 1 to N e n .,. ii la why ��i30 -u— cgg [Q ya .0w i°"' °-- - e— .00,0aNt0V0 000 01 U n --N W=N ggg 8 . L"o�pa�E O�t1RS 14.A <-881 al 18888 24 9i�i i*'izit Ziil{S kitiala 1=00 0000 �� wr.zzz $iat "i. IA=W2 Y3Itt ''<W4088 :8888 ►44. of � I titer. W w ,..W W w w w W le. W W W W W W W W W W W W W W W _E - 2,R ti/ aaaaB. 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Freer 618141-33 E149-:7.11..27; fRU 13.4. BAKER 11,1-.1, %hikk,r.I I4 Phot reererce welpae frs SRU 13-27 Version at True.e'11m1 depths are IL-femme to aotC For IRT) Gr41 System:N .7/W Nanta SF,Zane 4 1,'G4.;;US feet 1.teasaed WM.&bre relerm ced as NtOC Foe iR1 North RetICIQ:True north clack For(Rfl to real sea eve!:175 feel Sok:The ce real sea Ilre1 to/f C Ine At Sct W.—,13-27:t e feet Deters are On feet Oaofdnries we In het re'erenced to Shot CPmtod by Jorelholl on 11271Z71.1 Sado ..• Ea67ng(1t) 4IIID a ton ✓tm m m ton i'�- I I I I I I I IIMI Qt 7Z.' - MO LhS11}2/G t.4[,.O. 64/2.-12 MUT-1V 11Y:0-1142.127O Ib'ian 671 0-I Madp. 3.11 - scr.nD7e 611U132T MO 6-14tM12 102- C1d a#dJtl 0111/13127 r17-11 6-Nm-17 11111.1134714211 645111113,21 MKT. 1w-12 fp 5OU1337 G3 6-140.-12 l 110 ton— 6.1211 fry.urcp 9.Y':107t L-d d12= GIIUI131 6$11-lk.-12 K - mao etd re rule - t0 .4-MI 13-2,Loof 5147v-12 +11UI2-2111c M HP H2O 5-147.92 a' - t0 110X1- e.1 3 !F n 12-2 01::1 6-Ibo-I: 2 AI -O NM- tr.'J11-2i 04-3 6-1b.-12 t 1- - tet11 r - - ton &m- Ii14!2-2'6413 L-iN.-I: - IMI I?::112i U'._I t-1-eo;-1: WM- 11.113;2 r T'wok H'trAl e-rbwi2+ - 1I WM- GijIY2i LH::I .'4-# 0M.1732f O-]:6Nw-12 lave/11L-fyy, 43. - 6MJ12-2/ISO 0 ,1l 2X'!1@e 1®- eJBJ7121 I Mot.-12 ran Star 610/137/W-0.5Nx-17 r 6MJI}4/MO 6fib,-17II0113-2t 0-6 G1.vr-II 610ane .43.TO I4IJ Q• ne+etel '.� L-11.7.10-lt - Kg UM- 1 ,1- 1'0" drn Adds 03 • End e'nibs doge.Cee Auig. - S I I I I I I SRJ13-27 410 0 11:11 ton 61♦ IMO 3- 0 . PI•3 M.oT 1140 rrr,rolledrom GLC H:IDOL -401 Page 62 Revision 0 Nov, 2012 Swanson River Unit H13-27 Drilling & Completion Procedure Hilcorp Energy Company 34.0 Spider Plot IliHilcorp Alaska, LLC VAI Lanre•* _ .,riot,.n..�..r+..+P.tir.A.j ecru 132x RAKER Fink!f S4.h R*Ltd fsw.a. SRL/13.2.7 V IrHUGHES Mr SRU Ru iwl:1-08-2?-1 Set;r v.. SKI tl,t,,'rr 4In4.o,II r Put rebrence re#.stt,Is SRU 13-27 Veni^a,at True.ertcs'.depths are refmerced b Mac Fox IRT; Gra Sfber:W W27 i TM Nada SP,Zane 3+:5304i,U5 Yet Mee:.red deptra are re:krenced to Mlc Fac;RT) North Reirence:True men. O.rtc Fax;RTi to gran sea levet 175?eel Scat:True atstarce mean sea level b Mud Fre IN Slat EMU 73-271:O'tcet tIeptra are In Yet Cod6nates are In feet terererced b Slat Created by.Jaretrcn on 117.+3312 EaSthg(tt) - •O RI 40 i I iNI 71 W 7 1D R MA I I I I I 1':_? I I I I I I I I S! � + — MIS "1 MO— — On aro— — r 4- :nLrs-.r n-e e4r11,-;, 011— — NB 010— — IDS / L-tl el elAtl In— — 11a f1 1' — f — 12 y g :j r 8 , 7— rccr LM al az ! IL— a. ,And.acro / — III 5RJ 138-27 1-c A Wel 1— a aaM.a — I SRli 13-27 511 II I' 40— 4ila I I I I I I I I I I I I I I -70 1131 fi -Si i ■ i Q 11 IQ 7 IQ 41 ad r Z.. Eastkrig(R) Page 63 Revision 0 Nov, 2012 H Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 35.0 Surface Plat (NAD 27) SECTION LINE ___ 28127 NOT TO SCALE _ ..____ _ N 24864til4 33 34 E 347e9o.ra I -I' P / \\\ ii/ "N z op Efr- „, . ...., z 47_' )1) 1 ..;...7 # 4/4- 65111FEL S E C 3 3 1 • ti pm 4141 /487 .4siekWili 1 1_ tiles, MED W131 -7-:. '`...t.... /, SRU 13-27 44•44:cif.,c/E-e, / N2405552.1110 a.4 y.....• _Ak_..... op. i/"Zi:".. • E347D31.1627 • 9.4:492aPir LAT:Eiri14482171rN to 10 LOMPa 1001111 7.8791ff 0 •-•''t-J-,4-'47C:.:-.--,_ 0#1 f ASP ZOPE 4 NAD27 °I; %II. gam hoiNE..1: FEL-01881' 0 • ' • 8-211X•;;,0 41: .....,_ #0” -.....- ELEv.168 s(NAVDMII) lia,111110 ;;1;01. 14;77.` ts SECTION sa, •a k ii,. v.."‘ TM.ROW,SFA,AK Mkt% NOTES 1)Dale OF CCOPLIDATE&NO8 CPUD DOLITT1011 rpm Mal VA111, TrAm',ENKA.%!TATE PILAW MINE 4 KUM 111300.1 MCI, NOR IeViiiii OF ELEVATICK P NUM REIET MI RAWL 11)21ECTIC14 UTE OFFOETe CONFUTED FWD DUI COMM -..-- POLMO Alle 1122 Mk NW X.MIS&Pi -}.,212 En API1 LIMO TO MIME PE COMA Ski CCON.DINATIMIFICIIMe. SCALE 41 RANDOM VINIMICN LAI 1111:11TWE van UTLIZED PON e me so Goya MIMED!1)14.11.121(WILIM 113 MOM 1 . 1 . 1 IRU 13-27 WELL AS-S'TAKED SURFACE LOCATION (NAD27) III SWANSON RIVER FIELD LOCATION:SECTION n, TOWNSHIP 6 NORTH, ,lik ENGINEER."'7;41" RAN 8 WEST.auctoa MERIDIAN ALASKA 111.4 FEVEYINTI-IMMO P.O.1101141113 Iii1.k,l,a, 1.1k fr°77-4, eouxrsui,AK ow Jim No, 1=is ip4priiididir voice QM 283421 FAX{91779126122615 owe. *make ig V A 1 Ni I MCLANECGMOIN 123110 Diatc1110&12 FIGURE. 1 Page 64 Revision 0 Nov, 2012 Swanson River Unit II13-27 Drilling & Completion Procedure Hilcorp Energy Company 36.0 Spider Plot (Governmental Sections) Legend Ea • SRU 13-27(P1)Surface Location X SRU 13-27(P1)Top of Productive Horizon -+- SRU 13-27(P1)TD Horizon(BHL) rt f f/ ----SRU 13-27 Well Track ,� ▪ SRU 13-27 1000 foot radius r` /J i �F Surface Hole Location f` c J • Bottom HOS Locaton r SRU 12-27BK. L_J Field Boundary e�ir �r J KGSF7 Bii_ 'la (GSF3 BHLI'A / • Jr �r j KGSF2 E1-IL 1 1 e ED r t EV STtU_7 7 prop BH f / JI rI SRL;13-27(P1) -r^~ `f J 2 �KGSF7e�BH_ TD Horizon(BHL) SRU 23-27 8HL---' / SRU 13-27(P1) `~ Top of Productive Horizon SO013N009W A028399 rr A028406 r r /1 SRJ 314-27 SRU 314-2"i BHL r/ [ 4 SRU 314-27PB1 BHL / ,SRJ 14527 prop BHL J f CJ / r rr ` / •-...- / `/ ff / r r• / / i ` SRU 13-27(P1) I f G,."-- Surface Location -/ SRU 21434 BFL 1; ES SRU 32A-33 51-IL a Arad cInR11-r<. Ha 1,CCr7 2,0): SRU 13-27 Feet Alaska State Plane Zone 4,-4-4727 A nhrnrp A Nam.1.14. November8.2012 Page 65 Revision 0 Nov, 2012 Swanson River Unit 13-27 Drilling & Completion Procedure Hilcorp Energy Company 37.0 Mud Weight, PP, FG vs Depth Plot SCU 13-27 MW, PP, FG vs Depth 0 — 500 1000 1500 —MW vs Depth 2000 —FG vs Depth 2500 —PP vs Depth -- 3000 +., 3500 4000 4500 • 5000 5500 ▪ 6000 --_, 0 6500 �_...• 7000 7500 8000 8500 9000 --- -� 9500 — 10000 r -- 10500 11000 11500 12000 4 6 8 10 12 14 16 18 EMW(ppg) Page 66 Revision 0 Nov,2012 Page 1 of 1 Schwartz, Guy L (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Thursday, December 13, 2012 3:19 PM To: Schwartz, Guy L (DOA) Cc: Paul Mazzolini Subject: Anti Collision Scan for SRU 13-27 Attachments: SRU13-27 Vers. #1 Clearance Report.pdf Guy, See attached Anti-collision scan (3D Closest Approach) for SRU 13-27. A brief summary of the offsets that fail the scan is below: SRU 31-33WD Currently P&A'd, surface location 592' west of SRU 13-27,total depth of 2400'. This well fails the scan due to survey uncertainty associated with it. Totco surveys indicate it is a vertical well. A collision with this well poses no HSE risk. SRU 41-33 Currently P&A'd, surface location is 60'west of SRU 13-27, total depth of 11,133'. This well fails the scan due to survey uncertainty associated with the Totco survey instrument utilized. A collision with this well also poses no HSE risk. We have designed the SRU 13-27 wellbore to avoid a collision with SRU 41- 33 even in the worst case scenario where all survey error was in the same azimuthal direction. The two wells diverge from 1254' MD. SRU 13-27 passes the scan against all other wellbores. Let me know if you have any questions. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 12/13/2012 Page 1 of 1 Schwartz, Guy L (DOA) From: Davies, Stephen F (DOA) Sent: Thursday, December 13, 2012 9:08 AM To: Schwartz, Guy L(DOA) Subject: RE: SRU 13-27 Diverter Waiver Request Agree-diverter waiver should be approved for this well. GJ " 6 ,2 �S•1L Steve D. From: Schwartz, Guy L(DOA) Sent:Thursday, December 13, 2012 8:18 AM To: Davies, Stephen F (DOA) Subject: FW: SRU 13-27 Diverter Waiver Request Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Luke Keller [mailto:lkeller@hilcorp.com] Sent: Wednesday, December 12, 2012 3:39 PM To: Schwartz, Guy L (DOA); Paul Mazzolini Subject: SRU 13-27 Diverter Waiver Request Guy, See attached Diverter Waiver Request for SRU 13-27. Let me know if there is any supporting documentation you would like to see in addition to this. We could also schedule a time to have our geo team accompany us over there to give a quick presentation. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 12/13/2012 Swanson River Well SRU 13-27 Hilcorp Diverter Waiver Request Energy Company SRU 13-27 Diverter Waiver Request Hilcorp respectfully requests a waiver to: (1 ) AOGCC regulations 20 AAC 25.035 (c) Hilcorp requests permission to drill the 13-1/2" surface hole to a depth of 3000' MD / 2995' TVD without the use of a diverter. AOGCC regulation 20 AAC 25.035 (h) (2) stipulates: (h) "Upon request of the operator, the commission will, in its discretion, approve a variance (2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter system is not necessary." Based on drilling experience obtained by previous operators of the field, it is conclusive that no shallow gas hazards exist beneath this pad to a depth of 3098' TVD. At this depth, the normally pressured Lower Sterling exists, but has the log signature of being wet with no hydrocarbons. This is the shallowest known formation that could potentially be hydrocarbon bearing. Geology: Shallow geology has been reviewed and the following summary of the lithology to be encountered is provided below: Surface - 500': Interbedded med to coarse grained sand and coarse gravels. 500 - 1000': Interbedded 75% - 25% fine to medium grained unconsolidated sandstone with claystone, clay siltstone and carbonaceous mudstones. 1000 - 1600': Interbedded 60 - 40% fine to medium grained sandstones, with claystone, siltstone, clay sandstone and carbonaceous mudstones. 1600 - 3000': Interbedded 75% - 25% fine to medium grained unconsolidated sandstone with claystone, clay siltstone and carbonaceous mudstones. Hilcorp is not aware of any significant faulting, nor do we expect any oil or gas to be trapped, as no suitable seals exist with this shallow section 12/13/2012 Page 1 of 2 .......... . . 14 Swanson River Well SRU 13-27 Hilcorpp Diverter Waiver Request Energy Company Experience in the near vicinity: Hilcorp has recently drilled the 13-1/2" surface hole section on SRU 14B-27 to a depth of 2980' MD / 2978' TVD and run (and cemented) the 10-3/4" surface casing with the shoe at 2960' MD / 2958' TVD. TD of the hole section was reached Dec 8th, 2012. The above hole section was drilled with a 10.2 - 10.5 ppg MW using a diverter system. There were no indications of shallow gas or shallow gas potential. The surface locations of SRU 13-27 & SRU 14B-27 are on the same pad, approx 37' apart. At the 10-3/4" casing point - the wells will be approx 160' apart. For the purpose of basic risk mitigation, Hilcorp will utilize a spud mud with a fluid density of 10- 10.5 ppg as specified in the approved permit to drill. 12/13/2012 Page 2 of 2 OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. TRANSMITTAL LETTER CHECKLIST WELL NAME S R ( - a� PTD# at 7.181 • x Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: Sfnllk,usou hZ L R.. • POOL: SWAiJ oc R1VF_!l , fl i 1&oc.K 6iL Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev:9/09/2011 a ❑❑ 0) -o C o 0 aa)) o o -p 0 O Q : N, lye a • EcTs QY, c N 3 co N a) o, C-. N 0 Qv, a), n' O 0. 0 O a o a) m ° p' 2 o �, c v. a co. a) O _: a 3 0 E. E. To v Z >, o E D, a 0. o a .- . a c o' o. U, ,n n. a 7 ,n c. aoi: o �: : 0, �: a) �: w o ` co c c, o c a� 0 0 3 0. 3 m L l. O. CO, C ao N. p O. rn Op, 4 O) Jo O a) .o y • ; > w, • � oO O oa a c, M' 6 `mo , 2 , v co c z 1 a), OO N ° � c' v. 0. 0 - ( CO � UQ' a 63' m' �, co 5'• Z� = I zp� w. w -0. 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( p C (N ,- 0 J N E ai o O o W 0 EE a a c Q 0 0 Q a a Q w 0 Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. Hilcorp Alaska, LLC SRU 13-27 FINAL WELL REPORT DML LOGGING DATA Provided by: Approved by: Kevin Eastham Compiled by: Larry Resch Craig Silva Distribution: April 2, 2013 TD Date: March 03, 2013 SRU 13-27 1 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW .............................................................................................. 2 1.1 Equipment Summary .................................................................................................................... 2 1.2 Crew ............................................................................................................................................. 2 2 WELL DETAILS ................................................................................................................................... 3 2.1 Well Summary .............................................................................................................................. 3 2.2 Hole Data...................................................................................................................................... 3 2.3 Well Synopsis ............................................................................................................................... 3 2.4 Daily Activity Summary ................................................................................................................. 4 3 GEOLOGICAL DATA ......................................................................................................................... 15 3.1 Lithostratigraphy ......................................................................................................................... 15 3.2 Lithologic Details ........................................................................................................................ 16 3.3 Connection Gases ...................................................................................................................... 34 3.4 Trip Gases .................................................................................................................................. 34 3.5 Sampling Program / Sample Dispatch ........................................................................................ 35 4 DRILLING DATA ................................................................................................................................ 36 4.1 Directional Survey Data .............................................................................................................. 36 4.2 Bit Record ................................................................................................................................... 41 4.3 Mud Record ................................................................................................................................ 42 5 SHOW REPORTS ............................................................................................................................. 45 6 DAILY REPORTS .............................................................................................................................. 52 Enclosures: 2” / 100’ Formati on Log (MD/TVD) 5” / 100’ Formation Log (MD/TVD) 2” / 100’ Drilling Dynamics Log (MD/TVD) 2” / 100’ LWD Combo Log (MD/TVD) 2” / 100’ Gas Ratio Log (MD/TVD) Final Data CD SRU 13-27 2 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type / Position Total Downtime Comments Mudlogging Unit Computer System Canrig: 3 HP Compaq Workstations (DML, RigWatch, and Sample Catcher) 16 hrs DML Software Issue Ditch Gas Canrig: (2) QGM Gas Traps (with High RPM Electric-Powered Agitators) Canrig: E-Series Hydrogen Flame Gas Analysis and Chromatography. -0- TOTCO RigSense All Drilling Parameters Unknown Incidental, Sporadic Communication Errors Block Height / Depth Totco WITS Feed -0- Hookload / WOB Totco WITS Feed -0- RPM Totco WITS Feed -0- Torque Totco WITS Feed -0- Return Flow Totco WITS Feed -0- Pit Volumes Totco WITS Feed -0- Mud Gain/Loss Totco WITS Feed -0- Pump Pressure Totco WITS Feed -0- Pump Strokes Totco WITS Feed -0- Rate of Penetration Calculated from Block Position tracking -0- Mud Flow In Calculated from Pump Output/Rate tracking -0- 1.2 Crew Unit Type : Arctic Steel Unit Unit Number : ML030 Mudloggers Years* Days*2 Sample Catchers Years Days*2 Technician Days Larry Resch 13 34 Dickey Hudgins 2 22 Craig Silva 34 42 Omar Hinostroza 4 22 Ralph Winkelman 22 8 Mary Koenig 4 3 Dan Hill 2 3 *1 Years experience as Mudlogger *2 Days at wellsite between spud and total depth of well SRU 13-27 3 2 WELL DETAILS 2.1 Well Summary Well: SRU 13-27 API Index #: 50-133-20607-00-00 Field: Swanson River Field Surface Co- Ordinates: 788’ FNL, 650’ FEL Sec 33, T8N, R9W SM Borough: Kenai Borough Primary Target Depth: Tyonek G2 10532’TVD Hemlock H10 10904’TVD State: Alaska TD Depth: 11835’MD/ 11301’TVD Rig Name / Type: Arctic Fox/ Double Suspension Date: N/A Primary Target: Hemlock Formation License: ADL 212181 Spud Date: January 27, 2013 Ground Elevation: 164.00 AMSL Completion Status: Run 5” liner RKB Elevation: 182.60 AMSL Classification: Development Secondary Target: Depth: Hemlock Top 10615’TVD Hemlock H2-5 10634’TVD TD Formation: Hemlock Formation TD Date: March 03, 2013 Days Drilling: 35 Days Testing: N/A 2.2 Hole Data Hole Section Maximum Depth TD Formation Mud Weight (ppg) Dev. (oinc) Casing/ Liner Shoe Depth FIT (ppg) MD (ft) TVDSS (ft) MD (ft) TVDSS (ft) 16” Conductor 80’ +103’ Recent -- -- 16” Conductor 80’ +103’ n/a 13-1/2” 3014’ -2831’ Sterling 9.90 0.69 10-3/4” 3001’ -2818’ 13.5 9-7/8” 11000’ -10304’ Upper Hemlock 13.15 24.78 7-5/8” 10986’ -10291’ 12.0 6-3/4” 11835’ 11247’ Lower Hemlock 9.65 22.52 5” 11830’ -11229’ 2.3 Well Synopsis SRU 13-27 is the second grass roots well drilled by Hilcorp during this current 2012-2013 phase of field development. The objective was to drill a deviated well into the Hemlock formation, targeting the H1 -5 sands. This well is a sister to the SRU 14B-27 well: a replacement for the mechanically failed SRU 41 -33. Primary targets include the top of the Hemlock and the H2-5 sands. Secondary targets include Tyonek G2 and Hemlock H10 sands. Pressure in the Tyonek 64-5 Gas Storage Sand can exceed 3300 psi. Drilling this sand with 12.5+ drilling fluid, 925 units of gas was observed and chromatographic break down from Methane through Pentane . W hile unexpected high pressure gas shows exceeding 2500 units were encountered when drilling the SRU 14B-27 sister well in the Tyonek (7345’ – 7378’MD/ 7340’ – 7373’TVD, 7617’ – 7702’MD/ 7588’ – 7651’TVD), these sands appeared less developed on the SRU 13-27 well. Maximum gas observed while drilling SRU 13-27 was 444 and 544 units respectively. SRU 13-27 was drilled to a total depth of 11835’MD/ 11247’TVD safely and without incident. SRU 13-27 4 2.4 Daily Activity Summary 01-27-2013: Finish picking up initial BHA. RIH, drill out 16" conductor shoe at 78' and spud well (at 01:10 Hours). Drill ahead with 13.5" bit to 985'. Perform 5 stand wiper trip. Continue drilling ahead from 985' to 1050'. 01-28-2013: Drill from 1050' to 1492'. Do 8 stand wiper trip. Drill from 1492' to 1997'. Do 8 stand wiper trip. Drill from 1997' to 2124'. 01-29-2013: Drill from 2124' to 2503'. Circulate out. Do 8 stand wiper trip. Drill from 2503' to surface casing point at 3014'. Circulate bottoms up and circulate and condition hol e (1 1/2 circulations). Pull out first 5 stands on wiper trip to 2692'. Pump a dry job. Continue pulling out of hole (10 more stands to 1997) on wiper trip. 01-30-2013: Continue wiper trip by pulling out of hole from 1997' to 257' and then running back in hole to bottom at 3014'. Break circulation and circulate bottoms up. Record 22 units wiper gas. Pump around 20 bbl sweep with nut plug and finish circulating and conditioning hole. POOH. Lay down directional tools. Prep and rig up to run 10 3/4" casi ng. Hold pre-job safety and operations meeting on procedures for running surface casing. Make up and run in 10 3/4" shoe assembly and continue running in hole with 10 3/4" casing (filling every joint on the fly) to 1432'. Break circulation, fill casing and begin circulating around. 01-31-2013: Finish circulating around at 1432’. Break out Full -Open Safety Valve and circulating swage, and break down topdrive and mud line. Continue running in hole with 10 ¾” casing from 1432’ to 2463’ (filling every joint and installing bow spring centralizers on every even -numbered joint). Make up FOSV and circulating swage to topdrive. Circulate bottoms up and briefly condition mud. Break out and lay down FOSV and circulating swage, and break down topdrive and mud line. Continue running in hole with 10 ¾” casing from 2463’ to 2972’ (filling every joint and installing bow spring centralizers on every even -numbered joint to 2546’). Make up landing joint with hanger. Remove false table. Land hanger. Make up circul ating swage, chick-san, low-torque valve and cement hose to landing joint. Circulate and reciprocate casing. Hold pre-job meeting with Schlumberger cementers on cement job procedures. Prime SLB cement pumps. Pump 5 bbls of water (independent of rig) to load cementing lines and pressure test to 3500psi. Pump 59 bbls of Mud Push II with the rig pumps and then shut down. Switch over and line up to SLB cementing lines. SLB drops bottom plug. Begin pumping cement after verifying plug drop. Pump 255 bbls of 12.0ppg Class A lead cement (at 5.0 bpm) and follow with 80 bbls of 15.4ppg tail cement (at 3.3 bpm). SLB drops top plug, verifies plug drop and pumps ahead 5 bbls water before switching over and lining up to rig pumps. Using rig pumps, displace cement with 272 bbls of 10.4 ppg spud mud. Start displacing at 4.2 bpm (500psi) and quickly stage up to 6.9 bpm (800psi). Start sending all fluids to cellar box at 1766 strokes/116 bbls into displacement. Start reducing pump rate during late stage displacement to 4.7 bpm (850psi), 4.2 bpm (1125psi, 4000 strokes) and 2.0 bpm before bumping plug at 1450psi (4183 strokes). Hold pressure for 3 minutes at 1300psi after plug bump. Bleed off and observe floats holding. Cement in place (at 14:30 hrs). Observed returns of 69 bbls of Mud Push II and 159 bbls 12 ppg lead cement to surface. Took all cement returns to cellar box. Obtained 2 samples of cement returns prior to bumping plug and 2 samples from mixing tub. Pumped 70% excess on both lead and tail cement a nd had full returns though out job. Start flushing surface lines, cellar and stack with black water. Blow down cement lines to trucks. Release Schlumberger. Blow down mud lines to rig. Remove cementing head and associated equipment. Pull landing join t. Position and install pack-off running tool and install pack-off in casing head. Pull and lay down landing joint. Continue cleaning out cellar. Clean surface equipment in pits. Begin loading new BHA string in pipe shed. Begin nipple down procedures. Rig down long bales. Blow down TIW and 10 ¾” crossover. Install long bales and elevators. Remove drip pan and bell nipple. Remove long riser, short riser and ODS sub beam. Start nipple up. Set well head. SRU 13-27 5 02-01-2013: Nipple down tubing head. Pack off p-seal. Inject plastic packing. Test void (250psi Lo – 10 min/3000psi Hi – 10 min). Install test plug in tubing head. Nipple up:18” spool, annular preventer, double gate rams, mud cross, lower rams, choke hard line, choke line, kill line, riser nipple, flow line. Measure RKBs . During nipple up: clean mud pits, empty rock washer, mix 180 bbls of 11.5ppg EZ -MUD (PHPA mud with 6% KCL). Continue mixing EZ-MUD to 390 bbls drill -out volume. Rig up to test BOPE. First attempt to test upper pipe rams failed. Change out test joint. Second attempt to test upper also failed. Begin troubleshooting test problems. Test gas alarms. Load and strap 70 joints of 5” drill pipe. Test lower rams to 250psi Lo / 4000psi Hi for 10 minutes. Perform accumulat or drawdown test. Test annular preventer to 250psi Lo / 2500psi Hi for 10 minutes. Excluding the upper pipe rams, test other BOPE to 250psi Lo / 4000psi Hi for 10 minutes. (Note choke valve #7 initially failed, but was successful on second try after bei ng grease and cycled). Strap pits and test TOTCO pit level alarms. Pull test joint. Blow down top drive and all integral surface lines. Prep for remediation work on 2 7/8” x 5” VPRs. Open upper pipe ram doors, change - out top seals and clean recessed ram cavities. Break pup joint from top of test joint and re-make at bottom of test joint. Make up test plug. Rig up to test upper pipe rams and begin pressure -up. Third attempt on test of upper pipe rams also fails when leak observed. 02-02-2013: Reseat test joint. Attempt to test upper VPRs, TIW and HCR. Test failed (fourth attempt). Bleed off and close manual choke. Attempt test. Test failed (fifth attempt). Drain stack and replace Variable packer elements. Fill stack and attempt test. Test failed (sixth attempt). Drain stack and replace wear plate. Attempt test. Test failed (seventh attempt). Rig down test joint and replace with 5” drill pipe. Make up TIW and ported sub. Fill stack and attempt test. Test failed (eight attempt). Empty stack to upper ram cavity, pressure up and observe the upper pipe rams. Observe wear plate leak. Drain stack and inspect wear plate. Change out bad seal. Install wear plate. Test upper variable rams. Test successful (on ninth attempt). Test VPRs, HCR, Choke valves #1 and Choke Valve #10 to 250psi Lo / 4000psi Hi for 10 minutes. Rig down test equipment. Set wear ring. Run in lock-downs. Break down/rig down lines and associated equipment. Suction out fluid from gas buster. Pick up, make up and ru n in hole 70 joints 5” drill pipe to 2128’. Break circulation and condition mud. Pull first stand wet and stand back. Build and pump dry job. Pull out of hole from 2064’ standing back drill pipe. Calibrate depth tracking system on rig floor. Clean ri g floor. Pick up, make up and run in hole drill out assembly to 65’. Run in hole HWDP (and jars) to 854’. Pick up 5” drill pipe singles from pipe house, make up and run in hole 70 singles to 1800’. Break circulation and circulate 900 strokes. 02-03-2013: Continue to pick up, make up and run in hole 5” drill pipe singles from pipe house. Run in hole and tag float collar at 2913’. Make up top drive and break circulation. Circulate and condition mud. Lay down single and rig up to test casing. Break circulation through cement line and kill line. Close upper pipe rams. Test casing to 1500psi for 30 minutes. (33 strokes to pressure up on chart test). Rig down test equipment and break down kill line. Drill out entire shoe track (float collar, cement , shoe at 3001’, rathole) to 3014’ (with varying pump rates, pump pressure, weight on bit and torque values). Drill 20’ of new hole from 3014’ to 3034’. Circulate bottoms up. Displace 9.9ppg Spud Mud with 11.5ppg/6% KCL/PHPA EZ -MUD. Obtain clean 11.5ppg returns. Stand back one stand of drill pipe to 2999’. Make up FOSV, head pin, tee, chicksan and Lo-Torque valve. Perform F.I.T. with injection pump. Test to 13.5ppg EMW. Pick up and make up first stand from derrick and wash down drill string from 29 99’ to bottom at 3034’. Drill from 3034’ to 3124’. Circulate bottoms up two times conditioning hole. Check for flow. Pull out of hole 5 stands from 3124’ to 2811’. Pump 15 bbl, 12.5ppg dry job. Check for flow. Continue pulling out of hole from 2807’ to top of HWDP at 854’. Pull out of hole standing back HWDP in derrick to 65’. Pull and stand back NM flex collars. Break and lay down bit, bit sub and stabilizer. Clear and clean rig floor. Upload pony sub to rig floor. Break lift sub from pup joint. Pick up, make and run in hole BHA with directional tools (bit, motor, NM stabilizer, pony sub, MWD, NM flex collars) to 125’. SRU 13-27 6 02-04-2013: Run in hole 2 stands of HWDP to 242’. Make up top drive and perform shallow test on directional tools. Run in hole remaining stands 5”HWDP and jars to 914’. Continue running in hole with 5” drill pipe and take weight at float collar at 2913’. Pick up and attempt to ¼ turn through three times but fail to work past. Attempt to wash through (200gpm, 10rpm), but t orque up and stall each time. Make up top drive, fill pipe and break circulation. Ream through float collar. Continue running in hole with 5” drill pipe to 3060’. Make up top drive and wash down from 3060’ to bottom at 3124’. MWD logging pass made at 100ft/hr while washing down. Obtain slow pump rates at 3121’. Drill from 3124’ to 3688’. Circulate bottoms up and condition hole. Monitor well. Pull out of hole from 3688’ to 3121’ on wiper trip. Check flow. Run back in hole from 3121’ to bottom at 3688’. Drill from 3688’ to 3991’. 02-05-2013: Drill from 3991’ to 4886’. 02-06-2013: Drill from 4886’ to 5203’. Circulate bottoms up and condition hole. Check for flow. (Note slight static loss). Pull out of hole on wiper trip from 5203’ to 4954’. Pump 20 bbl 13.2 ppg dry job. Continue pulling out of hole on wiper trip from 4954’ to 2297’. Work through tight spots on way out at: 4015’, 3959’- 3948’, 3928’, 3899’-3883’, 3835’-3828’, 3778’ (washing and reaming), 3720’-3710’, 3647’. (Note 15.1 bbls loss on trip). Circulate out at 2297’. Check for flow. Service rig. Change out oil and filters on draw works motor. Lubricate top drive, blocks and draw works. Change out saver sub on top drive. Run back in hole from 2297’ to 5141’. Wash and ream tight spot at 4598’ on way in. Wash down from 5141’ to bottom at 5203’ with no fill. Obtain slow pump rates. Drill from 5203’ to 5258’. 02-07-2013: Drill from 5258’ to 5804’ (into the top of the D1CT Coal). Circulate bottoms up. Control drill from 5804’ (through D1CT Coal and 56-9 Gas Sand) to 5880’. Resume non-controlled drilling, and drill from 5880’ to 6088’. 02-08-2013: Drill from 6088’ to 6214’. Circulate bottoms up. Obtain slow pump rates. Pull out of hole on wiper trip from 6214’ to 5206 ’. Work through tight hole on way out at 5654’ and 5607’. Run back in hole from 5206’ and take weight on way in at 6188’. Make up top drive and wash down from 6188’ to bottom at 6214’ Drill from 6214’ to 6766’. 02-09-2013: Drill from 6766’ to 7226’. Circulate bottoms up. Pump sweep around. Condition and clean hole. Monitor well. Pull out of hole 5 stands (on wiper trip to shoe) from 7226’ to 6910’. Pump dry job. Continue pulling out of hole from 6910’ to 3123’. (Work through tight spots on e very stand on way out from 6740’ to 5840’). 02-10-2013: Continue pulling out of hole from 3180’ to 2997’. Hold pre -job meeting on slip/cut procedures. Service rig. Slip (90’) and cut (120’) of drilling line. Service Eaton Brake. Grease crown, blocks and topdrive. Lift flow riser. Adjust brakes and calibrate block height. Run back in hole picking up and making up single joints from pipe shed. Run back in hole, singling in, from 2997’ to obstruction at 7132’. Attempt to work pipe through tight zone without success. Make up top drive, break circulation and wash and ream from 7132’ to bottom at 7226’. Drill from 7226’ to 7565’. Stop, work pipe and circulate bottoms up. Resume drilling. Drill from 7565’ to 7645’. 02-11-2013: Drill from 7645’ to 8234’. Circulate bottoms up. Prep to pull out of hole on wiper trip. Monitor well. Pull out of hole from 8234’ to 6784’. Work through tight spots at 7620’ and 7060’ to 7038’on way out. Break circulation and shoot new survey (at 6737’ survey depth). Run back in hole from 6784’ and hit tight spot at 7327’. Work pipe to 7337’. Make up top drive and ream through tight spot. Wash rest of stand down to 7352’. Continue running in hole from 7352’ to 8171’. Make up top drive. Wash down from 8171’ to bottom at 8234’. Drill from 8234’ to 8248’. 02-12-2013: Drill from 8248’ to 8595’. 02-13-2013: Drill from 8595’ to 8822’. Circulate bottoms up and condition hole. Pull out of hole from 8822’ SRU 13-27 7 to 6715’. SRU 13-27 8 02-14-2014: Continue pulling out of hole from 67 15’ to top of HWDP at 914’. (Total 6 bbl fluid loss during trip out). Pull and stand back HWDP, jars, flex collars, filter sub (upper BHA) to 62’. Pull, break and lay down (lower BHA) directional tools as per BHI representatives. Break out lock -downs. Pull wear ring. Run in test plug. Prep and rig up to test BOPE. Install test equipment. Fill stack with water. Close annular and bleed off air. Test annular to 250psi Low / 2500psi High for 10 minutes. Test all other BOPE to 250psi Low / 4000psi High for 10 minutes. Test Super Choke and Manual Choke against 1000psi. Rig down, uninstall and lay down test equipment. Lay down test plug. Re -install wear bushing. Run in lock-downs. Pick up, make up and run in directional tools (lower BHA) to 73’ as per BHI representatives. Make up and run in filter sub, flex collars and two stands of HWDP to 257’. Perform shallow pulse test and confirmation of directional tools. 02-15-2014: Complete shallow test of MWD tools. Make up and run in remaining 11 sta nds of HWDP and jars (upper BHA) to 925’. Pick up, make up and run in hole 5” drill pipe singles from 925’ to 3576’. Break circulation and re-check pulsar function on way in at 3018’ (just outside of shoe). Continue running in hole with 5” drill pipe stands out the derrick from 3576’ to 8686’. Make up top drive and wash down from 8686’ to bottom at 8822’. Record 2638 units of Trip Gas. Drill from 8822’ to 9045’. 02-16-2014: Drill from 9045’ to 9447’. 02-17-2014: Drill from 9447’ to 9822’. Get survey. Circulate bottoms up and continue to circulate and clean hole. Record 564 units of survey gas during hole cleaning. Pull out of hole (with only elevators) on wiper trip from 9822’ to 8720’. Run back in hole from 8720’ until weight stacked on bit 9 791’. Make up top drive, break circulation and wash down last joint of drill pipe from 9791’ to bottom at 9822’. Drill from 9822’ to 9853’. Pick up off bottom when receiving very high gas returns from wiper trip. Record maximum 3443 units of Wiper Gas. Shut in well and circulate through choke. Record maximum of 336 units through choke. Open choke, resume circulating through flow line and continue drilling ahead. Record 507 units of gas during initial circulation after opening choke. Drill from 9853 ’ to 9867’. Circulate gas down to 150 units while drilling ahead. 02-18-2014: (While drilling ahead from 9867’; record 1196 units total gas at bottoms up from “pumps -off” period while choke was still shut in at 9853’; begin building MW from 12.5ppg to 12.7ppg after recording 770 units CG from the connection at 9885’). Drill from 9867’ to 10190’. 02-19-2014: Drill from 10190’ to 10531’. 02-20-2014: Drill from 10531’ to 10707’. Monitor well. Pump dry job. Pull out of hole on wiper trip to 8622’. Run back in hole to 8938’. 02-21-2014: Continue running back in hole on wiper trip from 8938’ to 9822’. Make up to top drive, break circulation and wash down from 9822’ to 9885’. Continue running back in hole from 9885’ to tight spot at 10049’. Work tight spot from 10049’ to 10060’. Make up top drive and wash and ream from 10060’ to 10075’. Continue running back in hole from 10075’ to 10643’. Make up to top drive, break circulation and wash down last stand from 10643’ to bottom at 10707’. Drill fro m10707’ to 10710’. Observe very high wiper trip gas returns. Begin circulating out wiper trip gas. Record two successive gas peaks of 3407 units and maximum 3450 units. Circulate wiper trip gas down to 2170 units and resume drilling ahead. Drill from 10710’ to 10727’, while continuing to circulate gas down from 2170 units to new background at 64 units. Continue drilling ahead. Drill from 10727’ to 10960’. 02-22-2014: Drill from 10960’ to 11000’ (intermediate casing point). Circulate bottoms up. Obtain slow pump rates. Perform survey. Monitor well. Pull out of hole with 5” drill pipe and stand back in derrick, 5” drill pipe out of hole on wiper trip from 11000’ to 8622’. Work tight spot at 10920’ on way out. Monitor well. Run stands of 5” drill pipe back in hole from 8625’ to 10962’. Ream through tight spot at 10730’ on way in. Wash down from 10962’ to bottom at 11000’. Circulate bottoms up. Record 1214 units of wiper trip gas. Break SRU 13-27 9 connection at 10990’ and drop carbide. Pump 26 bbl Hi -Vis sweep. Circulate around carbide and sweep to determine hole gauge. Condition hole. Pull out of hole from 11000’ to 10706’ and monitor well for 30 minutes. Pump dry job. Blow down top drive and mud lines. Continue pulling out of hole from 10706’ to 2945’. Observe tight spots at 7760’, 7726’, 7470’, 7419’, 7277’, 7234’ 7024’, 6863’, 6780’, 6642’, 6571’, 6317’, 4049’. SRU 13-27 10 02-23-2014: Kelly up top drive. Monitor well. Note slight loss in fluid. Slip and cut drill line. Cut and initial 165’ of drilling line and observe line in bad condition. Cut and additional 95’ of drilling line for 260’ total. Service top drive, draw works and top drive generator. Recalibrate block height encoder. Run back in hole with 5” drill pipe in derrick from 2945’ to 10959’, filling pipe every 2000’. Work through tight spots at 10694’ and 10710’ on way in. Wash down from 10959’ to 11000’. Note 15’ of fill on bottom. Circulate bottoms up. Record 681 units of wiper gas. Circulate around a second full bottoms up. Ob tain slow pump rates for mud pumps #2 and #3. Pull out of hole 5 stands from 11000’ to 10704’. Pump dry job (with 15.1ppg slug). Pull 5” drill pipe out of hole (standing back in derrick) from 10704’ to 4522’. Pull out of hole, breaking and laying down single joints of 5” drill pipe, from 4522’ to 2895’ (just inside shoe). Monitor well. Note slight loss of fluid. Continue pulling out of hole, breaking and laying down single joints of 5” drill pipe, from 2895’ to 925’ (top of HWDP). 02-24-2014: Monitor well at 925’. Note slight loss in fluid. Pull out of hole and stand back 5” HWDP, jars, 6 ¾” NM collars and filter sub from 925’ to 67’. Pull, break and lay down lower directional assembly (MWD tool, pony subs, stabilizer, motor and bit). Inspect and grade bit. Clear and clean rig floor. Prep and rig up Halliburton Wireline Services for open -hole logging. Pick up, make up and run in hole Halliburton’s Quad - Combo wireline logging assembly. Run assembly all the way to bottom and, (with only minor o verpull incident), log up from10999’ to surface. Pull, break and lay down Q -C logging tools and rig down all surface wireline running equipment. Clean rig floor. Pick up, make up and run in hole clean out assembly (bit, bit sub, string stabilizer, NM collars, HWDP, jars) to 854’. Continue running in hole, picking up and making up single joints of 5” drill pipe from 854’ to 4891’, and filling pipe every 1200’. Continue running in hole with stands of 5” drill pipe in derrick from 4891’ to 7545’, filling pipe every 1200’. 02-25-2014: Continue running in hole with stands of 5” drill pipe in derrick from 7545’ to 10955’, filling pipe every 1200’. Pick up and make up the last 2 joints while washing down from 10955’ to bottom at 11000’. No fill on bottom. Circulate bottoms up. Record 733 units of trip gas. Pump Hi -Vis sweep around and continue to circulate and condition hole (for 3 full circulations). Record Slow Pump Rates. Monitor well. Note slight fluid loss. Pull out of hole 5 stands from 11000’ to 10702’. Monitor well. Note slight fluid loss. Kelly up. Pump 25 bbl/15.0ppg dry job. Pull 5” drill pipe out of hole (standing back in derrick) from 10702’ to 7671’. Pull out of hole, breaking and laying down single joints of 5” drill pipe, from 76 71’ to 2899’ (just inside shoe). Monitor well. Note slight fluid loss. Continue pulling out of hole, breaking and laying down single joints of 5” drill pipe, from 2895’ to 854’ (top of HWDP). Continue pulling out of hole, breaking and laying down 5” HW DP, jars, NM collars, string stabilizer, bit sub and bit. Clear and clean rig floor. Lay down mouse -hole. Make up and lay down running tool. Pull wear bushing. Change upper pipe rams from 5” to 7 5/8”. Pick up, make up and set 7 5/8” test joint and t est plug. Prep and rig up to test pipe rams. 02-26-2014: Test 7 5/8” rams to 250psi Low (10 minutes) / 4000psi High (10 minutes). Pull test plug and rig down test equipment. Prep and rig up to run casing. Lay down rig make -up tongs, 5” elevators and bails. Rig up long bails, Weatherford power tongs, false table, and spiders. Upload 68 centralizers to rig floor. Dummy run the casing hanger and landing joint to confirm spacing. Change out the Weatherford power tongs. Run the 7 5/8” (29.7 ppf) intermediate casing as per Hilcorp detailed procedures. Make up and run in the shoe track to 83’, using Bakerlok on each set of joint threads, installing 2 centralizers over stop rings on joint #1 and 1 centralizer over stop ring on joint #2. Fill float joint s and ensure proper operation of float equipment. Continue running in 7 5/8” casing to 2126’. On way in, install 1 centralizer on every odd joint, fill every joint on the fly and top off every 10 joints to ensure balanced displacement. Service rig. Con tinue running in 7 5/8” casing from 2126’ to 2993’ (just inside 10 ¾” shoe at 3001’). Continue installing 1 centralizer on every odd joint, filling every joint on the fly and topping off every 10 joints to ensure balanced displacement. Rig up circulatin g head and circulate out. Continue running in 7 5/8” casing from 2993’ to 3884’. Continue installing 1 centralizer on every odd joint, filling every joint on the fly and topping off every 10 joints to ensure balanced displacement. Observe pipe skate not functioning correctly. Rig up circulating head and circulate while repairing skate. Finish repairing skate and continue running in 7 5/8” casing from 3884’ to 6558’. Continue installing 1 centralizer on every odd joint, filling every joint on the fly a nd topping off every 10 joints to ensure balanced displacement. Rig up circulating head and circulate bottoms up. Record SRU 13-27 11 184 units maximum gas. Continue running in 7 5/8” casing from 6558’ to 7055’. Continue filling every joint on the fly and topping off every 10 joints to ensure balanced displacement. SRU 13-27 12 02-27-2014: Continue running in 7 5/8” casing from 7055’ to 10958’, filling every joint on the fly and topping off every 10 joints to ensure balanced displacement. Make up hanger and landing joint. R un in hanger and make up to cross-over, TIW valve, head pin and circulating hose. Circulate, staging up the pump rate from 3 bpm to 5 bpm/690psi. Circulate bottoms up and continue to clean hole for two full circulations (18734 strokes). Record 1055 units of trip gas. (Note gas peak arrived very early, at only 4547 strokes). Rig down cross-over, TIW valve, head pin and circulating hose. Land hanger. Shoe set at 10985.90’. Rig up cross - over, cementing head, cement line, tee and low torque valve. Circ ulate through the cement head, quickly staging up to 5 bpm/680psi, (an additional 8255 strokes). Hold pre -job meeting for all hands on cementing procedures. Switch over to Schlumberger cementers, pump 5 bbls fresh water and test cement lines to 4000psi. Line up back to rig, pump 52 bbls of 13.5ppg Mud Push II at 4 bpm with rig pumps and shut down. Switch back over to SLB cementers, who were batching up cement while spacer was being pumped. SLB drops bottom plug, pumps 382 bbls of 14.1ppg Class A lead c ement at 5 bpm/600psi, batches up and follows with 80 bbls of 15.3ppg tail cement at 3.5bpm/200psi. Displace cement with 501 bbls of 13.1ppg drilling mud. Bump plug at 11000 strokes pumped. Hold at 500psi over for 5 minutes to check floats. Cement in place. Top of cement estimated at approximately 4000’. Blow and rig down cementing equipment. Pull landing joint and install pack-off. Test pack-off at 5000psi for 15 minutes. Lay down landing joint. Clear and clean rig floor. Remove unnecessary equi pment from rig floor. Grease the choke and HCRs. Change upper rams to 2 7/8” x 5” VPRs. Change the lower rams to 4” hard body integral rams. Change out from long bails to short bails. Hang pipe tongs. Upload spinner hawks to rig floor. Install wear bushing (with 9.0” wear ring). Prep to lay down drill pipe. Break and lay down 5” drill pipe from the derrick. 02-28-2014: Continue breaking and laying down 5” drill pipe from the derrick (106 joints total). Clear and clean rig floor. Off load all re maining 5” tools from rig floor and move up all necessary 4” tools. Pull wear bushing. Prep and rig up to test BOPE. Build both 5” and 4” test joints. Install test plug and 4” test joint. Test all BOPE holding pressure levels on each test for 10 minutes. Test annular preventer to 250psi Low / 2500psi High. Test all other BOPE (top pipe rams, lower pipe rams, TIW valve, dart valve, upper IBOP, lower IBOP, HCR choke, HCR kill, manual choke, manual kill, choke manifold valves 1 -2-3-4-5-6-7-8-9-11- 12-13-14-15) to 250psi Low / 4000psi High. Perform accumulator drawdown test. Remove 4” test joint and install 5” test joint. Test upper variable rams (VPR) to 250psi Low / 4000psi High. Test annular preventer on 5” pipe to 250psi Low / 2500psi High. Remove 5” test joint. Rig up test pump on choke valve #1 and test blind rams to 250psi Low / 4000psi High. Rig down test equipment. Change out saver sub from 4 ½” IF to HT-38. Blow down choke and kill lines. Change out elevators to 4”. Pick up, make up and single in hole 38 joints of 4” HT-38 drill pipe. Begin building new 9.5ppg (6% KCL PHPA) EZ -MUD drilling fluid (to 900 bbls volume). Pull out of hole racking back 19 stands of 4” HT -38 drill pipe. Clear and clean rig floor. Move directional assembly tools up to rig floor. Pick up, make up and run in hole directional assembly with 6 ¾” bit to 141’. Run in to 172’ on first joint of HWDP and perform shallow function test. Continue running in hole with 4” HT-38 HWDP to 323’. 03-01-2014: Continue building new 9.5ppg (6% KCL PHPA) EZ-MUD drilling fluid (to 900 bbls volume). Continue running in hole from 323’ with 4” HT -38 HWDP (and jars) to 745’. Pick up, make up and run in hole 4” HT-38 drill pipe singles from 745’ to 5555’. On way in, fill pipe at t op with fill-up line every 2000’. Load and strap 169 joints of drill pipe in the pipe shed. Perform an inspection of the derrick. Continue building new 9.5ppg drilling fluid. Pick up from pipe shed, make up and run in hole 4” HT -38 drill pipe singles from 5555’ to 10898’. On way in, continue to fill pipe at top with fill -up line every 2000’. Tag up on float collar at 10898’. Kelly up, break circulation and displace the old 13.1ppg intermediate EZ -MUD with new clean 9.5ppg (6% KCL/PHPA) EZ-MUD. Obtain clean 9.5ppg returns all around. Pull and lay down single to 10871’ and rig up to test casing with injection pump. Close upper pipe rams and, pumping through cement line and kill line, perform casing test to 3000psi for 30 minutes. (Require 2127 injec tion strokes to pressure up to test level on chart recorder). Rig down test equipment and break down kill line. Pick up single and wash down from 10871’ to 10898’. Drill upper part of shoe track (float collar and cement) from 10898’ to 10950’. SRU 13-27 13 03-02-2014: Continue to drill out remaining shoe track (cement, shoe at 10986’, rathole) to 11000’ (with varying pump rates, pump pressure, weight on bit and torque values). Drill 20’ of new 6 ¾” hole from 11000’ to 11020’. Perform F.I.T. with injection pump . Pressure up to 1373psi. Shut in pump and hold pressure for 10 minutes. Pressure held steady at 1368 psi (12.0ppg EMW). Bleed off pressure and open up rams. Blow down equipment used in test. Drill from 11020’ to 11539’. 03-03-2014: Drill from 11539’ to 11686’. Observe shut down of Totco RigSense System during normal drilling process at 11681’. Continue drilling ahead while attempting to restart system. Drill rest of stand down to 11686’ and circulate bottoms up while continuing attempts to resta rt system. Cease circulating and pull out of hole to 10996’ (just inside shoe) to wait for arrival of Totco technician. Continue to troubleshoot Totco RigSense System. Slip and cut drill line. Service rig. Replace the application server card for RigSense system, restart and function check the system and restore data acquisition. Run back in hole from 10996’ to bottom at 11686’. Drill ahead from 11686’. Record 106 units of wiper gas. Drill from 11686’ to TD of well at 11835’ (at 18:53). Circulate b ottoms up. Take final survey. Pull out of hole to 10996’ (just inside shoe) on wiper trip. Run back in hole from 10996’ to 11812’. Kelly up and wash down from 11812’ to bottom at 11835’. Circulate bottoms up. Record 53 units of wiper gas. Pump Hi -Vis sweep around to clean and condition hole. 03-04-2014: Finish circulating around Hi -Vis Sweep. Monitor well for 10 minutes. Pull out of hole from TD at 11835’ to 10995’ (just inside shoe). Check for flow. Pump dry job. Blow down top drive and mud l ine. Pull out of hole from 10995’ to 5841’. Monitor well for 10 minutes. Pull out of hole from 5841’ to 140’. Monitor well for 10 minutes. Well is static. Pull and lay down bottom hole assembly. Clean rig and prepare to rig up wire line. Hold pre-job meeting on procedures and safety during wireline operations. Rig up Halliburton Wireline Services to run e -logs. Pick up, make up and run in hole Halliburton’s Quad -Combo logging assembly (Run #1: hole finder, array compensated resistivity sonde, shor t axis kit, regal standoff, wave sonic insite, flex joint, density insite pad, spectral density tool, dual spaced neutron, gamma telemetry tool). Circulate over top of hole with trip tank pump while logging. (Perform Simops while e -logging: clean rockwasher pits using VAC trucks, clean and service rig, fix oil leak on draw works, unclog and service centrifuge, change out charge pump on mud pump #3). Perform wireline logging Run #1 with no issues, and then pull out of hole, breaking and laying down tools. Pick up make and run in hole Formation Tester logging assembly (Run #2: hole finder, gamma ray tool, formation pressure tester). Perform wireline logging Run #2 with no issues and then pull out of hole breaking and laying down tools. Rig down Halliburt on wireline- running equipment. 03-05-2014: Finish rigging down Halliburton wireline -running equipment. Clean rig floor. Stage bit, bit breaker bit sub for clean out run. Make up and run in hole clean out assembly (mill tooth bit, bit sub, NM stabilizer, crossover, 4” HWDP, jars) to 616’. Strapping 4” drill pipe all the way in, continue running in hole from 616’ to 2502’. Fill pipe. Continue running in hole from 2502’ to 10980’ (just inside shoe). Fill pipe. Continue running in hole from 10980’ to 11746’. Kelly up and wash down from 11746’ to bottom at 11835’. Circulate bottoms up. Record 146 units of trip gas. Pump around Hi -Vis sweep. Circulate until shakers are clean. Monitor well for 5 minutes. Well static. Pull out first joint from 1183 5’ to 11810’. Beak and lay down joint and drop rabbit. Pull out of hole from 11810’ to 10843’.(1 ½ stands inside shoe). Monitor well for 30 minutes. Well static. Pump dry job. Blow down top drive and mud lines. Pull out of hole from 10843’ to top of HWDP at 616’ (circulating over top of hole with trip tank pump). Pull out of hole from 616’ to surface with clean out assembly, racking back 9 stands of HWDP, and breaking and laying down jars, 1 joint HWDP, crossover, NM stabilizer, bit sub and bit. Cl ear and clean rig floor. Prep to run 5” production liner. Pick up, stage and rig up casing running tools and equipment. (Rabbit all crossovers). Clear and clean rig floor. SRU 13-27 14 03-06-2014: Pickup, make up and run in hole 25 joints of 5” (15 ppf, DWC/C -HT) buttress casing to 1005’. Pickup, make up and run in hole Baker ZXP liner top packer assembly (crossover, flex lock liner hanger, crossover, RS packoff seal nipple joint, HRD ZXP packer, PBR), running tool and 4” HT -38 x 3.5”IF crossover to 1048’. Fil l liner tieback sleeve with “Pal mix”, ensuring mixture is thin enough to travel past the HRD tool and down to the pack-off. Rig down casing-running equipment while waiting 30 min for PAL mixture to set up. Make up 5” liner string to first stand of HWDP and run in hole to 1139’. Circulate liner volume. While controlling the rate of run-in and carefully monitoring the displacement, continue running the 5” liner string on 4” drill pipe from 1139’ to 10955’ (inside the shoe). On way in, kelly up top drive , break circulation and fill pipe at 4419’ and 7881’. Kelly up again at 10955’, break circulation, stage pumps up slowly monitoring for losses and wash to the bottom of the 7 5/8” shoe at 10986’. Circulate the drill pipe and liner volumes (8214 strokes) without exceeding 1500psi. Obtain up and down weights of the liner string before entering open hole. Continue running in hole from 10985’ to near the bottom of the hole at 11830’. Circulate and condition drilling mud with the liner near bottom. Cease ci rculating, break out the last single in the liner string, place it in the mouse hole, make up the cementing head on top of it, and then make up cementing equipment to the cementing head. (Include a 10’ pup and crossover to the bottom of the cement head and a 5’ pup on the top). Remake the cementing head to the top of the liner string. Break circulation, and tag bottom at 11835’ while circulating. Circulate bottoms up and record 56 units of trip gas. Continue to circulate and condition mud until Schlumberger cementers are ready (25710 strokes total). Hold pre -job meeting on cementing procedures. Pump 30 bbls of Mud Push II spacer with the rig pumps. Line up and switch over to Schlumberger pumping unit. Pump ahead 5 bbls of water and pressure test cem ent lines to 5000psi. Pump 46 bbls of 15.3ppg Class G cement at 5 -6 bpm, then pump 5 bbls of water and drop dart. Pump and chase cement with drilling mud, and bump plug at 127 bbls mud away. Pressure up to 3150psi and slack off 60 K to confirm hanger is set. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner. Bleed pressure to zero to check float equipment. Pick up 4’ to verify setting tool is released, and expose the setting dogs on top of tieback sleeve. Cement in place. Ro tate slowly and slack off 60k downhole to set the ZXPN liner top packer. Close annular and test 4” DP x 7 -5/8” backside annulus to 1100 psi for 10 minutes to test liner top packer. Bleed off pressure and open up the annular. Unsting from liner top. 5” Liner Shoe is set at 10830’, top of Liner at 10731’. Observe pressure drop off and immediately start pumping with the rig pumps while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. Circulate out 30 bbls of Mud Push and 4 bbls of cement and send to Rock Washer. Continue to circulate until the mud is clean. SRU 13-27 15 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Prognosed tops were provided by Hilcorp geologist Kevin Eastham . Observed tops were picked by CANRIG mudlogger Craig Silva. FORMATION PROGNOSED OBSERVED MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) Shallow Gas Sand 446 -263 507 507 -331 Sterling B-6 3098 -2915 3032 3028 -2852 LBGT 4295 -4112 4311 4272 -4096 D1CT 5715 -5532 5793 5665 -5489 Gas Storage Sand 6427 -6244 6551 6379 -6203 TYNK HP H20 9177 -8994 9508 9137 -8961 Tyonek G2 10532 -10349 11028 10512 -10336 HKT 10615 -10432 11117 10592 -10417 Hemlock H2-5 10634 -10451 11160 10631 -10455 Hemlock H7-8 10794 -10611 11390 10840 -10664 Hemlock 10 10904 -10721 11512 10951 -10775 TD 11117 -10934 11835 11247 -11072 SRU 13-27 16 3.2 Lithologic Details Tuffaceous Claystone, Tuffaceous Siltstone (3014'-3060') = light gray, very light gray; very soft to soft; curdy, mushy; pulverulent in part; no pronounce fracture or cuttings habit; dull, subsucrosic in part with varying abundance of very fine quartz; noncalcareous; note loose sand, conglomeratic sand. Sand (3060'-3120') = distinctive Sterling Sand, initially congolmeratic or bimodal; medium dark gray to dark gray with strong olive gray secondary hues; fine lower to medium upper range; dominant size group at fine upper to medium boundary; grains are equ ant to slightly prismoidal, spherical to subdiscoidal, and dominantly subangular, but range from angular to well rounded; lithic arenite; estimated 55 -70% monocrystalline and polycrystalline quartz and variations of cryptosilica, 5 -10% feldspar, 25-35% lithics and mafic minerals; abundant greenstone grains which are strongly contrasted by spotty but well distributed orange and reddish orange lithic volcanic rock fragments. Sand (3120'-3210') = 90% loose sand, 10% well disseminated grayish white to very light gray argillaceous material; lower medium to upper very fine grain, subangular to subrounded; subprismoidal and discoidal equally represented; occasional upper medium subrounded clasts; moderate to well sorted in part; translucent to grayish white quartz dominant with abundant dark gray to grayish black, reddish orange lithics and mafic minerals; note well rounded translucent volcanic glass; no hydrocarbon indicators. Tuffaceous Claystone, Tuffaceous Siltstone (3210'-3270') = light gray, often with slight yellowish brown hues, light bluish gray to slight greenish gray in part; prominently ashy -tuffaceous; soft to slightly firm; pulverulent, brittle to crumbly; irregular fracture; tabular cuttings habit; dull, sparkly in part, occasionally sub-sucrosic; noncalcareous; arenaceous in part with abundant extremely fine quartz; air dried samples quickly de-hydrate, crack and crumble. Sand, Conglomeratic Sand (3270'-3360') = > 85% loose sand; lower medium grain, upper fine grain common; subrounded, subangular in part; subprismoidal and subdiscoidal; moderate to well sorted; occasionally well disseminated within grayish white to very light gray devitrified ash/tuffaceous matrix; grain supported in part with significant matrix component; n o visible porosity; translucent and grayish white quartz with secondary feldspars and mafic clasts; note trace well rounded, subprismoidal pebble fragments. Tuffaceous Siltstone, Tuffaceous Claystone (3360'-3390') = light gray to light bluish gray firm to soft; pulverulent, sectile, crumbly in part; irregular fracture; nodular to slightly tabular cuttings habit; dull, sparkly, occasionally sub- waxy; texture varies with amount of extremely fine quartz; massive, with no apparent bedding or laminar structure; non-calcareous. Tuffaceous Sandstone, Sand (3390'-3510') = varies from 50-80% consolidated sand; very light gray to light gray, slightly light bluish gray; upper very fine to fine grain; subrounded, subdiscoidal; also subangular, subprismoidal; moderate to well sorted; generally grain supported; matrix supported when well disseminated in tuffaceous/ argillaceous matrix; noncalcareous; no visible porosity; dominantly translucent, grayish white quartz with abundant secondary feldspars, r eddish orange lithics, mafic minerals; note both well rounded and angular, translucent volcanic glass clasts; note carbonaceous shale, coal; no hydrocarbon indicators. Tuffaceous Siltstone, Tuffaceous Claystone (3510'-3600') = very light gray with occasional light yellowish brown hues, very light bluish gray; firm to soft; crumbly, pulverulent; sectile; irregular fracture, nodular to slightly tabular cuttings habit; sparkly, often subsucrosic, occasionally subwaxy luster; gritty with abundant locally abundant translucent and transparent quartz; with poorly developed coal = brownish black, grayish black; soft to firm; pulpy to crumbly; platy to subfissle; earthy; in part grades towards a carbonaceous shale. SRU 13-27 17 Tuffaceous Sandstone (3600'-3700') =very light gray to grayish white; upper very fine to lower medium grain; subrounded, subdiscoidal; also subangular, sub prismoidal; moderate to locally well sorted; poorly consolidated with abundant devitrified ash and tuff matrix; grain supported and matrix supported equally as common, varies throughout the interval; no visible porosity; noncalcareous; no hydrocarbon indicators. Tuffaceous Claystone (3650'-3750') = dominant lithology of overall sandy tuffaceous mudstone to "muddy" tuffaceous sandstone; medium dark gray to dark gray (wet) with strong olive to olive black and faint brownish gray secondary hues; minor higher lightness value greenish gray variation; very dominantly hydrophilic and soft, but spotty firm to mod brittle fragments; clayey to ashy to silty textures; earthy luster; tuff clay is supporting matrix of adjacent sandstone; many subtle local transitions from clay dominant to silt dominant; vitric glass microshards become discernible and locally prominent when overall ash content increases; note very thin zones with clastic sand size coal fragments. Tuffaceous Sandstone (3700'-3850') = pervasive high clay matrix percentage and closely gradational to very sandy tuffaceous claystone; not inclusive with other soft clayston es with abundant floating sand grains but is very fine to fine sandstone with even grain distribution; large fraction is very fn fluvial reworked shards from volcanic ash; dark gray (wet) to light gray (dry) to common dark greenish gray to greenish gray variation, and com associated secondary hues within same color group; very fine lower to fine upper range, dominantly very fine upper; equant to slightly elongated grains, spherical to discoidal, angular to rounded; shares many claystone characteristics when volume of supporting tuff clay matrix is high; rare zones with only spotty claystone are well sorted with fragile silica cementation. Sand/Conglomerate (3820'-4000') = abundant percentage increase, good distribution of loose floating sand grains and conglomerate clasts; size range from fine upper to pebble; poor sorting overall, major fraction of sand is coarse lower to coarse upper; sand/conglomerate is compositional graywacke with 50 -80% lithics; loose sand fraction is medium dark gray to dar k greenish gray; sand dominate by dark gray chert, greenstone lithics and other non-differentiated diverse silicate lithics; very likely that many of the large greenish gray sandy claystone pieces are actually fragments of soft pebble -cobble size claystone clasts, several examples of firm round claystone clasts within softer partially soluble claystone; well rounded coarse sand grains and conglomerate clasts are more abundant than angular fragments; though dark gray smooth chert casts are slightly dominant, well rounded, smooth, hard dense greenstone lithics and other diverse polycrystalline silicate clasts are also very abundant. Conglomerate/Tuffaceous Claystone (3800'-4140') = note prominent overall changes in color with very faint dusky bluish green and dusky blue and grayish blue secondary colorations after 3840' that are increasingly distinctive after 3960' and dominant to pervasive after 4020'; (wet) bulk sample is dusky bluish grayish green to grayish blue green with faint to moderate dark greeni sh gray to medium gray to medium bluish gray secondary hues; overall greenish -bluish colorations derived from weathering of large diverse greenstone conglomerate clasts; matrix clays surrounding the clasts appear to be a pale greenish gray alteration product that displays variegated green -colored post-weathering micro fragments; note after 3960' that soft claystone and conglomerate are the dominant lithologies, and tuffaceous silts and very fine tuffaceous sands are very minor. Conglomerate/Conglomeratic Sand (4140'-4230') = localized poor to fair consolidated tuffaceous sand; greenish gray to light pale green; lower fine to rarely lower medium; generally well disseminated, and occasionally near grain supported, within the clays; 75% medium to coars e, often very coarse subangular conglomeratic sand; prismoidal to subdiscoidal; poor sorting; note well rounded, subprismoidal pebbles > 7mm; note rounded pebble fragments and irregular, angular lithic fragments > 15mm with high impact fracture; minor interbedded claystone and siltstone; no hydrocarbon indicators. SRU 13-27 18 Conglomerate/Conglomeratic Sand (4230'-4290') = > 80% loose sand and lithic fragments; generally upper fine to lower medium grain but ranges from fine to coarse grain and beyond; angular , subangular in part; prismoidal to subprismoidal; poorly sorted; note 10 -15% highly angular lithic fragments up to 5mm x 10mm x 15mm and larger; occasional to rare well rounded pebble fragments with high impact fracture; larger fragments are greenish gray to grayish green and appear monolithic; no hydrocarbon indicators. Conglomeratic Sand/Tuffaceous Siltstone/Conglomerate (4290'-4380') = lithic and pebble fragments, conglomeratic sand continue; note color and texture change to light yellowish brow n, pale yellowish brown, light gray with light brownish hues; very soft; poor cohesion, adhesion; expansive; pulverulent, brittle to slightly crumbly in part; irregular to earthy; tabular to nodular cuttings habit; dull, slightly sparkly in part; varies from silty to clayey; no apparent bedding or structure noncalcareous; locally abundant matrix supported quartz sand, occasional grain supported lithic arenite; note trace poorly developed carbonaceous shale/ coal; no hydrocarbon indicators. Tuffaceous sandstone, Sandstone, Sand (4380'-4470') = yellowish gray, light gray with light brown hues, pale yellowish brown; lower very fine grain, often upper very fine; subrounded to subangular; subprismoidal, subdiscoidal; moderate sorting; poorly con solidated quartz grains well disseminated in tuffaceous/ ashy matrix; grain supported in part; no visible porosity; note sandstone = upper fine to lower medium grain; angular to subangular; prismoidal; tight, no visible porosity; noncalcareous; wel l cemented, hard; note locally abundant carbonaceous flakes, clasts, detrital material in argillaceous, occasionally slightly earthy sediment; no hydrocarbon indicators. Tuffaceous Sandstone/Claystone (4470'-4560') = 30% loose sand grains; remaining is light gray, often with slight brownish hues, light pale yellowish brown; upper very fine grain; rounded to subrounded; discoidal to subdiscoidal; varies from grain supported to matrix supported with well disseminated translucent to grayish white quartz; well rounded volcanic glass clasts and transparent glass shards common; interval grades from an arenaceous claystone to an argillaceous sandstone; note carbonaceous flakes, clasts, rare streaks, no hydrocarbon indicators. Tuffaceous Claystone (4560'-4730') = note two closely associated color groups: dominant brownish gray with strong dark yellowish brown secondary hue, and slightly less abundant medium dark gray to medium gray with strong brownish gray and faint olive gray secondary hues; note many subtle variations of primary colors and secondary hues associated with the dominant color groups, also trace to spotty pale greenish and bluish secondary hues; hydrophilic clays are soft, mushy and generally soluble; "ashier" soft clays often display micro-shards in colloidal -looking material; many pieces have swirling or mottling with variations in silt-clay-ash concentration; floating sand grains very often pervasive in softer clays; clay is obvious supporting matrix for conglomerates and sands; fin er sand grains often form lineations in clays; firm to brittle claystone is generally siltier overall, and has fewer floating grains; clayey to ashy to silty various mixed and mottled textures; earthy luster; note spotty slightly shaly carbonaceous cla ystones. Sand/Conglomeratic Sand/Conglomerate (4700'-4760') = dark greenish gray with moderate medium dark gray and faint bluish gray secondary hues; overall greenish coloration derived from abundant greenstone lithics; range fine upper to pebble(12mm); poorly sorted overall, but grain size also well distributed; full range of shape and angularity; but most very coarse and larger grains are well rounded; fragile clay matrix supported; many grains/clast clustered together at weathering and alteration clays contact points; overall compositional graywacke to lithic arenite very prominent variegated green low grade metamorphic greenstone rock fragments, various groups of monocrystalline and polycrystalline silica; distinctive trace jasper, epidote, rare citrine; overall very diverse lithics and minerals. SRU 13-27 19 Tuffaceous Claystone (4760'-5000') = dominant brownish gray with strong dark yellowish brown and pale brown secondary hues, common to locally abundant medium dark to medium gray with strong brownish gray and faint olive gray secondary hues; note many subtle variations of primary colors and secondary hues; overall the claystone in this interval is slightly more homogenous than the major clay -silt sections above 4700'; note significant zones of brown carbonaceous tuffaceous claystone associated with carbonaceous shale; sands in interval do not appear as discreet beds, but as lineal concentrations of floating sand grains in the clays; clayey to silty to ashy texture; earthy lusters. Carbonaceous Claystone and Tuffaceous Carbonaceous Claystone (4760'-5010') = co-bedded with other claystones, but commonly distinctive pale brown to brown color; same general characteristics but has organic appearance; generally more homogenous in texture than the prom inently ash-derived claystones; many of these claystones display very fine carbonaceous-coaly particles; roughly half of cuttings pieces have particles in rough parallel orientation, and the rest are randomly oriented; most carbonaceous claystone lacks floating sand grains; trace fragments of interbedded micro -thin coal and carbonaceous claystone. Tuffaceous Claystone (5010'-5070') = various shades of pale yellowish brown, light gray with brownish hues; soft, poor to moderate induration; pulverulent, crumbly; irregular to earthy fracture; tabular to nodular cuttings habit; generally dull, earthy; smooth texture; silty to sandy in part; non - calcareous; note abundant carbonaceous material as clasts, flakes, streaks, micro-thin coal; note earthy, sublithic coal, carbonaceous shale/ claystone. Coal, Carbonaceous Shale, Carbonaceous Claystone (5070'-5130') = note first appearance of developed bedded coal; black, grayish black in part, more dense cuttings exhibit organic layers with micro -thin brownish black substrate; an organic rich clayey shale in part; most often occurring as organic detritus in a somewhat earthy, very argillaceous, somewhat tuffaceous claystone; clay - stone is very silty in part with well disseminated extremely fine carbonaceous clasts, flakes, scale-like material. Tuffaceous Claystone, Tuffaceous Siltstone (5130'-5200') = pale yellowish brown, light gray with brownish hues, rare very light gray to grayish white; soft; pulverulent, crumbly; readily swells and crumbles when rehydrated; irregular , earthy fracture; tabular cuttings habit; dull; no apparent structure; locally abundant carbonaceous materials as clasts, flakes, scale-like fragments, micro-thin coal/ sublithic organic material; note occasional silty tuff/ devitrified ash. Tuffaceous Siltstone/Sand/Coal (5200'-5225') = diverse group of lithologies dominated by distinctive olive gray firm to brittle siltstone; spotty large pieces display micro -thin sand-silt-carbonaceous interbedding; note some carbonaceous particles are arrayed in a prominent parallel orientation. Tuffaceous Claystone (5220'-5400') = note that all tuffaceous claystone is more homogeneous overall in both color and texture; secondary colorations are almost all muted in the clays; abundan t claystone is hydrophilic, soft, medium dark gray to medium gray with very faint brownish gray to olive gray secondary hues, then transitions after 5250' to medium gray to medium light gray with very faint yellowish gray secondary hues and a denser, smoother-looking texture with only rare floating sand grains; note that overall the claystone is becoming slightly to moderately firmer, with a blockier and lumpier cuttings habit; some of the broken ends of the brittle claystone display a concentration of mi cro-thin flaky carbonaceous particles; clayey to smooth to partially ashy to partially silty texture; earthy to dull luster; most appears gradational to a non-tuffaceous, non-differentiated slightly shaly claystone. Carbonaceous Tuffaceous Claystone, Carbonaceous Material, Carbonaceous- Organic Claystone, Carbonaceous Material, Carbonaceous Shale, Coal (5340'-5460') = significant brown carbonaceous rocks locally interbedded with the very homogeneous medium gray claystone; many of the partings of the fi rm gray SRU 13-27 20 claystones display concentrations of tiny fragile black flakes; many of the individual coal pieces are not durable, because they a interbedded with the carbonaceous claystones. SRU 13-27 21 Tuffaceous Siltstone, Tuffaceous Claystone (5460'-5550') = light gray with yellowish brown to brownish hues, light gray to very light gray, slightly yellowish gray; soft, firm but yielding; pulverulent, crumbly; no definable fracture characteristics, tabular to slightly nodular cuttings habit; claystone often appears massive and clean, but also shows degrees of gradation towards an argillaceous siltstone; massive clays contain abundant micro-fine wisps of black organic material whereas siltier sediments contain locally abundant very fine to lower fine carbonaceous clasts, flakes, rare micro-thin organic layering; no hydrocarbon indicators. Tuffaceous Sandstone (5550'-5640') = light gray with yellowish brown hues, light pale yellowish brown, grayish white; fine grain, lower very fine in part; subrounded; subdiscoida l to subprismoidal; moderate to well sorted; poorly consolidated with abundant devitrified ash/ tuffaceous clay/ argillaceous clay matrix; varies from matrix supported to grain supported; noncalcareous; no visible porosity; quartz dominant; note abundant well indurated and disseminated carbonaceous clasts; claystone and siltstone common; note associated adjacent coal is dull black to grayish black, with occasional brownish black layering, moderately hard to firm, hackly to sometimes planar, display s rare birdseye fracture and has fine outgassing bubbles. Tuffaceous Claystone, Tuffaceous Siltstone, Coal (5640'-5730') = light brownish gray, pale yellowish brown; soft; mushy to punky; pulverulent; earthy; tabular to slightly nodular cuttings habi t; dull, slightly sparkly in part; no apparent bedding or structure; noncalcareous; note very little organic/ carbonaceous material in sediments; note well developed interbedded coal is black to grayish black, hard, dense, rarely brittle or crumbly, forms coffee ground cuttings mixed with large cavings up to 70mm x 30mm x 10mm, platy, fissile in part, generally massive with common birdseye fracture and has vigorous outgassing bubbles. Tuffaceous Claystone (5730'-5790') = light pale yellowish brown, light gray with yellowish brown hues; very soft to soft; curdy to mushy, slightly pasty in part; pulverulent, rarely crumbly; earthy; tabular to slightly nodular cuttings habit; dull, slightly subwaxy in part; generally massive to slightly silty in pa rt, occasionally slightly sandy; note absence of organic/ carbonaceous component. Sand/Sandstone/Tuffaceous Sandstone/Conglomeratic Sandstone/Conglomerate (5845'-5870') = very diverse sand/sandstone section, ranges from very fine to pebble; sandstone s ize ranges from very fine (winnowed from volcanic ash) to fragile consolidated conglomerate; diverse matrix includes volcanic ash, both tuffaceous and non-tuffaceous clay, weak siliceous cementation, moderately calcareous cementation, various degrees of i ntergrain weathering and various forms of secondary mineral replacement; note two (2) color modes: sandstone with variegated greenstone lithics (1) and lithics -poor medium gray sandstone (2); most sandstone is fragile; spotty sandstone is harder, with c alcite cementation; mostly angular and discoidal, but widely ranges from very angular to well rounded and spherical; note minor mode of very fine monocrystalline well sorted quartz sand with grains that appear to be winnowed from volcanic ash. Tuffaceous Siltstone, Sandy Tuffaceous Siltstone, Very Sandy Siltstone (5870'-6030') = brownish gray to brownish black (wet) with faint olive gray to olive black and dark yellowish brown to dusky yellowish brown secondary hues; all appears volcanic ash derived, bu t prominent variation of very sandy siltstone also includes apparent lithic micro -grains; hydrophilic, soft; abundant fraction is very closely gradational to very fine lower sandstone, has combined ash-silt-clay matrix, ranges from 30 to 100 microns, is mostly equant monocrystalline quartz grains and is locally displayed in micro -thin roughly parallel layers and/or zones; silty to ashy to mottled and mixed textures; earthy lusters. SRU 13-27 22 Sand/Sandstone/Tuffaceous Sandstone/Conglomeratic Sandstone/Conglomerate (5900'-6120') = colors are difficult to define; "ashier" tuffaceous sandstone is medium light gray to occasional light gray; loose sand and other sandstone is medium dark gray to med gray with complex mix of faint brownish gray, olive gray, pale yellowish brown secondary hues; note several variations of sand/sandstone; dominant group is medium gray, medium grain size, moderately sorted, subangular to subrounded and mostly with tuffaceous matrix, but also minor group with calcite and trace silica ceme ntation; locally abundant loose disaggregated sand with homogeneous appearance, moderately well sorted, with evenly distributed mix of black, pale gray, and colorless translucent grains of: both monocrystalline and polycrystalline quartz, feldspar and mafic lithics; lithic arenite to compositional graywacke (>30% lithics). Sand/Tuffaceous Sandstone/Tuffaceous Siltstone (6120'-6210') = no change in characteristics of coarse lower and finer sands, but conglomeratic sand and conglomerate is reduced to a tra ce; note that overall sorting is improved and the overall diversity is reduced; dominant sand/sandstone is medium gray, medium lower to coarse lower, moderately well sorted, angular to subangular and subdiscoidal; loose disaggregated lithic arenite sand has same composition as the consolidated pieces; note that the tuffaceous sandstone, rather than grading finer, has the same characteristics as the loose sand. Tuffaceous Claystone, Tuffaceous Sandstone (6210'- 6330') = dusky yellowish brown, light gray often with definite brownish hues; very soft; pulverulent, slightly crumbly in part; no definable fracture; slight tabular to nodular cuttings habit; generally dull, sub -waxy common; very massive, smooth texture, occasionally slightly silty, sandy i n part; with grayish white to white, very light gray tuffaceous sandstone: very fine; subrounded, rounded in part; subdiscoidal; moderate sorting; quartz dominant; also fine to lower medium grain; subprismoidal to subdiscoidal; subangular to subrou nded; varies from grain to matrix supported with abundant devitrified ash; generally quartz dominant, often a lithic arenite with a variety of black to grayish black, minor mafic clasts; note loose sand, conglomeratic sand, occasional well rounded pebble fragments with high impact fracture; no hydrocarbon indicators; note well developed coal: black to grayish black; hard; dense; subplaty to slightly splintery, occasional birdseye fracture; with fine streams of outgassing bubbles. Tuffaceous Sandstone, Loose Sand, Pebbles (6330'-6390') = poorly consolidated sandstone is grayish white to white, with occasional light yellowish brown hues; fine to lower very fine grain in part; subrounded to rounded, occasionally subangular; subdiscoidal; fair to moderate sorting; clasts dominated by an abundance of argillaceous/ devitrified ash matrix; cleaner sand is grain supported with abundant clay fill; no visible porosity; a quartz dominant lithic arenite with abundant black, grayish black, greenstone an d occasional mafic secondary components; noncalcareous; up to 30% loose sand, conglomeratic sand and pebble fragments; no hydrocarbon indicators. Tuffaceous Claystone, Tuffaceous Siltstone (6390'-6550') = very light gray often with yellowish brown hues, light pale yellowish brown to dark yellowish gray; very soft, occasionally firm but yields easily; pulverulent, brittle to crumbly; earthy to irregular fracture; tabular cuttings habit; dull, often subwaxy when massive and more argillaceous; slight ly sparkly when more silty; slightly sandy in part; noncalcareous; siltier samples contain very fine carbonaceous detritus as clasts and specks; darker, more brownish cuttings contain more organic material, micro fine coaly layers, grading towards a ca rbonaceous shale; note coal as described up section. Tuffaceous Sandstone/Sand (6550'-6590') = medium gray to medium dark gray to brownish gray to dark yellowish brown; disaggregated sand with higher lightness values to med light gray and light gray; v ery fine lower to medium lower; moderately well sorted at fine lower to fine upper; equant to very slightly elongate grain dimensions, angular to subangular, subdiscoidal to subspherical; volcanic ash derived supporting matrix; note that the mode of very fine grains may all be almost all shards washed out of the matrix; rare grain supported sandstone with weak silica cementation; lithic quartz arenite to sublithic arenite; non -lithic fraction is 90-95%; dominant monocrystalline quartz, minor polycrystalline quartz, very minor feldspar, spotty lithics dominated by variegated greenstones and dark gray phyllite -argillite rock fragments; mafic minerals SRU 13-27 23 are non-differentiated; note that a trace "crust-like" coating on quartz grains may be altered and/or devitrified volcanic glass. SRU 13-27 24 Tuffaceous Claystone, Tuffaceous Siltstone (6590'-6790') = medium gray to medium dark gray with moderate brownish gray to brownish black secondary hues and faint dark yellowish brown and olive gray hues; hydrophilic and soft when hydrated, to crumbly when dry, massive; forms irregular non-blocky cuttings pieces; a significant fraction of claystone has very fine to fine floating sand grains, and many zones present a layered lithology with local concentrations grading to tuffa ceous sandstone; clayey to silty to ashy to mixed and mottled textures; earthy to occasionally faint sparkly luster; note local brown color variations are carbonaceous tuffaceous claystone; occasionally thinly interbedded with coals. Tuffaceous Siltstone, Non-Differentiated Siltstone, Tuffaceous Claystone (6790'-6840') = generally same characteristics as immediately up section, but also subtle increasing complexity within the bulk homogeneous appearance; the silt content itself is varying, and there i s some siltstone that displays secondary mineral replacement. Tuffaceous Claystone, Tuffaceous Siltstone (6840'-6960') = claystone varies from light gray to very light bluish gray, light olive gray to light pale yellowish brown; soft to firm, yields easi ly to probing; pulverulent, brittle to slightly crumbly; earthy in part; tabular cuttings habit; grayish clays are more often massive, cleaner, ashier, subwaxy; brownish clays appear to be more earthy, dull to slightly sparkly, silty in part and contain carbonaceous material within very fine orientated organic layers, flakes, streaks; note absence of indurated carbonaceous clasts; locally abundant free floating coffee ground coal; siltstone appears in the brownish range; earthy; very argillaceous, slightly sandy in part; noncalcareous; note well developed coal at bottom of interval with common fine streams of outgassing bubbles. Tuffaceous Sandstone (6960'-7080') = 10-30% loose sand, remaining is poorly consolidated ashy sandstone; grayish white to white, dark yellowish gray with slight yellowish brown hues; lower fine to upper very fine, upper very fine less common, occasional lower medium grain; subangular to subrounded; subprismoidal, discoidal; moderately well sorted; very soft, poorly consolidated; generally very quartz rich, matrix supported sand in a pulverulent devitrified ash matrix; grain supported quartz dominated lithic arenite with abundant ash/ clay matrix; no visible porosity; noncalcareous; quartz varies from translucent and transparent grains, volcanic glass and very fine, thin glass shards; locally abundant disseminated carbonaceous clasts; note apparent bitumen or other black to brownish black solid hydrocarbon; samples display mineral fluorescence only, no hydrocar bon indicators. Tuffaceous Siltstone, Tuffaceous Claystone (7060'-7130') = pale yellowish brown, slightly light olive gray to light gray with definite brownish hues; very soft to soft; crumbly, pulverulent; tabular to nodular cuttings habit; earthy, irregular fracture; most cuttings fall apart when probed; dull to sparkly luster; no apparent structure but extremely fine bedding planes/ sandy layers are common; earthier material contains micro fine carbonaceous layered material as coal, roughly para llel-oriented flakes and planar organic detritus; noncalcareous; commonly sandy; tuffaceous in part; note interbedded carbonaceous shale, coal. Tuffaceous Sandstone (7130'-7210') = medium light gray to light olive, with faint light brownish gray and very faint yellowish gray secondary hues; ranges from fine lower to coarse upper, moderately well sorted at fine upper to medium lower, with the most abundant fraction at fine upper; equant to very slightly elongated grains, angular to subangular, discoidal to subspherical; fragile devitrified ash matrix support; spotty grain supported, with minor secondary calcite cementation; ashy lithic quartz arenite. Tuffaceous Siltstone, Tuffaceous Claystone (7210'-7350') = light pale yellowish brown, light olive gray, light gray often with slight brownish hues; soft to firm, crumbles easily when probed; pulverulent; irregular to earthy fracture, subplaty in part with micro thin bedded carbonaceous layers and non -connected flakes; interval varies and grades to and from a silty claystone, argillaceous to locally tuffaceous very arenaceous siltstone; noncalcareous; cleaner clays are massive and contain little organic material; organics, carbonaceous streaks, flakes, detrital clasts increase within the siltier/sandier sediments; note interbedded coal, ashy tuffaceous sandstone, occasional well rounded pebble fragments with bit impact fractures. SRU 13-27 25 Coal (7380'-7400') = black, with strong brownish black and grayish black secondary hues; brittle to marginally hard; fragile to tough; dull luster, occasional partially vitreous or resinous; planar to irregular fracture; mostly thick platy habit, but also displays abundant thin hackly -flaky fragments; very dense matte to smooth texture; many large fragments displ ay abundant outgassing. Tuffaceous Sandstone (7400'-7540') = medium light gray to light olive gray, with faint light brownish gray and very faint yellowish gray secondary hues; many pieces have black grains contrasted against white kaolinite-ash background; range from very fine upper to coarse upper, moderately well sorted at fine upper to medium lower, and large percentage fraction of fine upper; grains are equant to slightly elongate, angular to subangular discoidal to subspherical; abundant very fin e grains are shards winnowed from volcanic ash; fragile devitrified ash (smectite) is the pervasive supporting matrix, but also locally very common matrix with soft white kaolinite; trace grain supported sandstone with weak calcite cementation; ashy lit hic quartz arenite to marginal sublithic arenite; 75 -90% monocrystalline and polycrystalline quartz (includes amorphous volcanic glass shards); 5-10% feldspar, 5-15% lithics and mafic minerals; note that the overall olive color is derived from variegated green low grade meta greenstone rock fragments; dark gray to black grains mostly argillite and phyllite lithics. Tuffaceous Siltstone/Tuffaceous Claystone (7400'-7800') = medium gray to medium dark gray with moderate brownish gray to brownish black sec ondary hues and faint dark yellowish brown and olive gray hues; also common local variations to higher lightness values, especially medium light gray with faint yellowish gray and pale yellowish brown hues; dominant hydrophilic and soft, but very common firm to brittle fragments; most of the brittle siltstone is moderately tough; note that the siltstone occasionally displays (micro-scale) fluid structures, especially swirls and micro "rip-ups" of claystone; claystones are most often associated with and abundance of floating sand grains, but siltstones also have concentrations of very fine to fine sand and many thin zones display layered micro -strata that sometimes grade to tuffaceous sandstone; clayey to silty to ashy to various mixed and mottled textu res; earthy to occasional faint sparkly luster; note locally very abundant brown carbonaceous tuffaceous claystone that is adjacent to coals. Tuffaceous Sandstone (7800'-7860') = medium light gray to light olive gray, with faint light brownish gray and very faint yellowish gray secondary hues; range very fine upper to coarse upper, moderately well sorted at fine upper to medium lower, large percentage fraction in fine upper; grains are equant to slightly elongate, angular to subangular discoidal to subspherical; abundant very fine grains are glass shards winnowed from volcanic ash; fragile devitrified ash (smectite) is the pervasive supporting matrix. note locally very common mix of volcanic ash and soft white kaolinite; trace grain supported sandst one with weak calcite cementation; ashy lithic quartz arenite to marginal sublithic arenite;75 -90% monocrystalline and polycrystalline quartz, 5% feldspar. Tuffaceous Siltstone, Tuffaceous Claystone (7860'-7920') = pale yellowish brown; slightly light olive gray, light gray to very light gray, often with brownish hues; soft to slightly firm; pulverulent, crumbly to brittle; earthy, irregular to slightly platy fracture; tabular cuttings habit; generally dull to sparkly, subsucrosic part with abundant very fine well rounded translucent to transparent quartz; noncalcareous; abundant clay cuttings readily rehydrate, crumble but do not swell; darker cuttings more earthy with very fine, thin carbonaceous material; lighter cuttings are more tuffaceous/ ashy, sandier; locally abundant white to grayish white tuffaceous/ ashy sandstone; no hydrocarbon indicators. Tuffaceous/Ashy Sandstone (7920'- 7980') = white to grayish white, very light gray; upper very fine to lower fine grain; rounded to subrounded; subdiscoidal to discoidal; moderately well sorted; non to slightly calcareous; poorly consolidated; cuttings are very fragile; quartz sand dominated by very pulverulent weathered ash matrix; trace grayish black to dark gray, mafic clasts; note l oose well rounded transparent, often frosted translucent volcanic glass; no hydrocarbon indicator SRU 13-27 26 Tuffaceous Siltstone, Tuffaceous Claystone (7980'-8080') = light gray to very light gray, often with slight yellowish brown to brownish hues, light olive g ray, light pale yellowish brown; soft to firm, yields easily to probing; moderate to well indurated; pulverulent, crumbly, irregular, earthy fracture; tabular to slightly nodular cuttings habit; dull matrix, sparkly to subsucrosic with increased quart z content; noncalcareous; no apparent structure; rare bedding indicated by very fine, thin sand lenses and micro fine sublithic carbonaceous layers; locally very sandy; note coal/ carbonaceous shale. Tuffaceous Sandstone/Sandstone/Sand (8080'-8180') = light gray to very light gray; minor faint yellowish gray to light olive gray secondary hues; pervasive tiny white patches and spots of matrix ash -kaolinite; fine upper to very fine lower; moderately well sorted in fine range; equant to slightly elo ngate grains; angular to subangular; discoidal to subspherical; fragile supporting matrix is dominantly devitrified ash, plus trace vitric ash, minor silica and calcite cementation, concentrations of microshards, trace calcareous tuff, variegated silt-clay and trace to locally common white kaolinite group clay; non to very slightly calcareous; common carbonaceous streaks displayed along “smushed” pieces; fine detrital material is well distributed and differentiated within micro-layers/micro-zones within the sandstone and matrix; note >30% loose disaggregated sand. Tuffaceous Siltstone /Tuffaceous Claystone (8080'-8310') = medium gray to medium dark gray with moderate brownish gray to brownish black secondary hues and faint dark yellowish brown and ol ive gray hues; many subtle local variations to higher lightness values, especially medium light gray with faint yellowish gray and pale yellowish brown hues; dominant hydrophilic and soft, but very common firm to brittle fragments; most of the brittle siltstone is mod tough; note that many tuff siltstone cuttings fragments display floating sand grains that are concentrated in roughly parallel lineations; silty to ashy to various soft matte to occasionally gritty textures; earthy to "soft glassy" luste r Tuffaceous Siltstone /Tuffaceous Claystone (8310'-8430') = very light gray to light gray, often with yellowish brown to brownish hues, light olive gray, pale yellowish brown; soft to slightly firm, yields easily when probed; pulverulent, brittle to cr umbly; earthy, irregular fracture; tabular cuttings habit; more massive clays and silts are dull, subwaxy in part, becoming sparkly to subsucrosic with increased very fine to lower fine well rounded quartz; noncalcareous; occasionally banded with micr o fine bitumen plastic-like solid hydrocarbon or carbonaceous material; carbonaceous clasts and flakes are common; trace carbonaceous shale/sub-lithic coal. Tuffaceous Sandstone/Sandstone/Sand (8430'-8610') = light gray to very light gray with faint yel lowish gray to light olive gray secondary hues; pervasive white patches and spots from matrix kaolinite and ash; generally well sorted at fine upper; range very fine upper to medium lower; occasional mode of very fine lower appears to be microshards wi nnowed from the tuffaceous sandstone matrix; equant to slightly elongated grains; angular to subangular; discoidal to subspherical; fragile supporting matrix consists of abundant devitrified ash with trace vitric ash, minor silica and calcite cementati on, concentrations of microshards, trace calcareous tuff, variegated silt -clay and trace to locally common white kaolinite group clay; non to very slightly calcareous; common carbonaceous streaks and well distributed fine sand grains concentrated in parallel-oriented micro-layers/zones on bit-cut faces; disaggregated grains range from trace to 30% or more; ashy lithic quartz arenite to marginal sublithic arenite;75 -90% monocrystalline and polycrystalline quartz, 5% feldspar; 5-15% lithics/mafic minerals; lithics are dominantly low grade metamorphic greenstones and medium grade metamorphic argillite-phyllite rock fragments. SRU 13-27 27 Tuffaceous Siltstone, Tuffaceous Claystone, Tuffaceous Sandstone (8610'-8820') = light olive gray, light gray to very light gray with yellowish brown to brown hues, light pale yellowish brown; soft to firm; pulverulent, brittle to crumbly, occasionally dense, tough; earthy to irregular fracture; tabular, nodular cuttings habit in part; clay components vary from dull to subwaxy when tuffaceous, sparkly with locally abundant very fine glass shards; subsucrosic with increased very fine well rounded translucent and transparent quartz grains; massive claystones and very argillaceous siltstones contain banded and orientated bitumen/carbonaceous material; note localized earthy, silty carbonaceous shale and shaley coal; tuffaceous sandstone is very fine to fine; subdiscoidal; moderately well sorted; quartz generally well disseminated and supported in white to grayish white ashy/k aolinitic matrix; gradational to very ashy sandstone; grain supported in part with no visible porosity; no hydrocarbon indicators. Tuffaceous Siltstone/Tuffaceous Claystone (8820'-8990') = medium dark gray to dark gray to brownish gray with strong olive gray secondary hue and partial lower lightness value brownish black to olive black; consistent minor "ashier" variation is medium gray to light gray with moderate to faint light olive gray to yellow gray to pale yellowish brown secondary hues; appears both hydrophilic and hydrophobic; pieces range from soft and mushy to brittle and moderately tough; dominant characteristic is slightly hydrated and soft in exterior zone of fragment, but drier and slightly firm or slightly brittle when pressed apart wit h a probe; massive and formless to very slightly shaly and sub-tabular; irregular to sub-blocky-sub-platy habit; note trace of fluid micro-structures, especially flames and tiny claystone "rip -ups"; claystone often displays floating sand grains in random or rough parallel orientation; siltstones commonly have concentrations of very fine to fine sand, occasionally as distinct micro-layers, and are often gradational to tuffaceous sandstone; clayey to silty to ashy to various mixed and mottled textures; earthy to occasional faint sparkly luster; note locally very abundant brown carbonaceous and tuffaceous claystone adjacent to coals. Tuffaceous Sandstone/Sand/Sandstone/Conglomeratic Sand (8990'-9180') = color group shifts slightly away from medium and medium dark gray to brownish gray with strong light olive gray to olive gray and faint pale yellowish brown secondary hues; medium gray is also a secondary hue; tuffaceous dominant, so very fine to fine are major size group; pervasive very fine are glas s shards are winnowed from volcanic ash; many local variations, but overall moderately well sorted at fine upper -medium lower; dominantly equant to slightly elongated grains, angular to rounded, subdiscoidal to spherical; dominantly angular to subangula r; prominent devitrified and non -devitrified volcanic ash matrix support that in many zones diminishes in volume, leaving grain supported (or near grain supported) sandstone with a complex intergrain material that includes very weak silica and/or calcite cementation; very ashy lithic quartz arenite to sublithic arenite;75 - 90% monocrystalline and polycrystalline quartz, 5% feldspar; 5 -15% lithics and mafic minerals dominated by argillite-phyllite and greenstone rock fragments. Tuffaceous Claystone, Tuffaceous Siltstone (9160'-9320') = light gray to very light gray generally with yellowish brown to light brown hues, slightly olive gray, light pale yellowish brown; soft to firm; yields easily when probed ; pulverulent, brittle to crumbly, fragile when mo re silty; dense in part when cleaner, more massive and tuffaceous; earthy to irregular, occasional hackly fracture; tabular to slightly nodular cuttings habit; matrix is generally dull, becoming sparkly to subsucrosic with increased very fine well roun ded transparent and trans- lucent quartz; less arenaceous clays are subwaxy; air dried clays rehydrate easily, swell slightly and crumble; while silts remain intact; siltstone locally grades to a silty/ ashy / tuffaceous sandstone with no visible porosity; note coal/ carbonaceous shale/ earthy carbonaceous claystone. SRU 13-27 28 Tuffaceous Sandstone/Sandstone/Silty Tuffaceous Sandstone (9320'-9450') = prominent gradational lithology; overall silty tuffaceous sandstone; dominantly very fine grains that are app arent glass shards and microshards winnowed from volcanic ash by fluvial action, and either redeposited with the immediate reworked ash or other silt-clay; abundant individual cuttings pieces display micro interbedding of ash -clay- silt-sand; dominantly brownish gray to medium gray to dark gray with moderate to strong olive gray secondary hues; complex colors overall with many slight variations of gray and brown primary colors - secondary hues; very fine lower to fine upper, and moderately well sorted with in shifts in that range; note that most abundant size mode is very fine -silt group from 40 to 110 microns; dominantly equant grains, subdiscoidal to spherical shape, angular to subrounded; note many shards are slightly elongated, but still rounded; prominent matrix of both devitrified and vitric ash; non to slightly calcareous in part; ash -rich lithic quartz arenite to sublithic arenite; apps 80 -90% monocrystalline and polycrystalline quartz and clear volcanic glass, 5% feldspar, 5-15% mafic minerals and lithics (dominated by greenstones and argillite rock fragments). Tuffaceous Claystone, Tuffaceous Siltstone (9320'-9510') = medium light gray to medium gray; diverse secondary hues include: yellowish brown, pale brown, pale yellowish brown, olive gr ay to light olive gray; pulverulent; soft when hydrated to brittle to crumbly; occasional brittle and marginally tough; tuffaceous to i/p argillaceous; irregular to hackly fracture; tabular to massive, formless cuttings habit; locally grades to silty-ashy-tuffaceous very fine sandstone; both clays and silts have floating sand grains; clayey to ashy to silty to various soft matte to mixed textures; earthy to occasional very slightly sparkly luster. Tuffaceous Sandstone, Sand (9510'-9690') = 30-60% loose disaggregated sand is very fine to fine; subangular to angular, prismoidal to subprismoidal, white to grayish white quartz, feldspars ; also subangular to rounded, discoidal to spherical translucent volcanic glass clasts and thin, angular sharp g lass shards; poor to moderate sorting; mafic mineral content varies throughout the drilled interval; sandstone is light gray to grayish white with yellowish brown to brownish hues, light olive gray, light pale yellowish brown; bimodal very fine to fine subrounded to rounded subdiscoidal grains; also fine to lower medium, rare upper medium subangular to subrounded subdiscoidal to subprismoidal grains; locally moderately well sorted, fair sorting overall; non to slightly calcareous; firm yet crumbly; varies from matrix to grain supported with abundant tuff and devitrified ash matrix; no visible porosity; occasionally clean, grain supported with very little clay fill; trace to poor visible porosity; sandstone varies from a lithic quartz arenite to sublithic arenite; note intermittent conglomeratic sand, conglomerate, whole well rounded very coarse and larger clasts and fragments of similar size; no hydrocarbon indicators. Tuffaceous Siltstone (9710'-9780') = very light gray to light gray, often with slight brownish hues, pale yellowish brown, light olive gray ; soft to firm, yielding easily when probed; pulverulent, crumbly to brittle; earthy; tabular to sub platy cuttings habit; matrix generally dull, sparkly in part with increased volcanic g lass shards, subsucrosic in part grading towards a very argillaceous/tuffaceous sandstone with extremely fine quartz grains; locally abundant carbonaceous material. Tuffaceous Sandstone/Sandstone/Sand (9780'-9990') = light gray to medium light gray with faint yellowish gray to light olive gray secondary hues; common "off -white" patches and zones of matrix kaolinite and ash; moderately well sorted; range very fine upper to coarse lower; minor mode very fine lower apparent microshards winnowed from volcanic ash and sandstone matrix mat; equant to slightly elongated grains, angular to subrounded; discoidal to subspherical; dominant matrix of abundant devitrified ash with less com vitric ash, minor silica and calcite cementation, micro -shard concentrations, trace very calcareous ash, variegated silt-clay and trace kaolinite group clay; non to very slightly calcareous; common carbonaceous streaks displayed on bit cut faces; very ashy sublithic arenite to occasional lithic quartz arenite; 75 -90% monocrystalline and polycrystalline quartz, 5% feldspar, 5 -15% lithics and mafic minerals; lithics dominated by variegated greenstones and grayish black argillite -phyllite rock fragments. SRU 13-27 29 Tuffaceous Siltstone, Tuffaceous Claystone (9990'-10080') = light gray to very light gray, often with yellowish brown to soft brown hues, light olive gray, light pale yellowish brown; soft to firm; brittle to crumbly, generally pulverulent; earthy, irregular to amorphous fracture; tabular cuttings habit; earthy to dul l, slightly sparkly, often subsucrosic luster; no apparent structure but both silts and clays contain locally abundant extremely fine to very fine sand lenses and carbonaceous material as resinous bitumen, parallel layered oriented carbonaceous micro-layers, fragments, streaks; note poorly developed carbonaceous shale/shaley coal; note 10-20% intermittent very fine grain loose sand. Tuffaceous Sandstone/Sandstone/Sand (10080'-10200') = light gray to medium gray with moderate light olive gray to yellowi sh gray secondary hues; abundant white patchy zoning of matrix volcanic ash and kaolinite; moderately well sorted; very fine upper to coarse lower; rare very coarse -conglomerate; very fine mode is dominantly glass microshards winnowed from volcanic ash and coarse sandstone intergrain; equant to slightly elongated grains, angular to subrounded; discoidal to spherical; complex matrix of abundant devitrified ash with lesser fractions of vitric ash, minor silica and calcite cementation, aggregated microshards, very calcareous ash, variegated silt -clay and kaolinite group clays; non to very slightly calcareous; common carbonaceous and other streaks on sharply cut cuttings surfaces; ashy sublithic arenite to trace lithic quartz arenite; 75-85% monocrystalline and polycrystalline quartz, 5% feldspar, 10 - 15% lithics and mafic minerals (dominated by variegated greenstones and grayish black argillite -phyllite rock fragments. Tuffaceous Claystone, Tuffaceous Siltstone, Undifferentiated Siltstone (10200'-10350') = light gray, light to very light gray with yellowish brown hues, light olive gray, light pale yellowish brown moderate brown in part; soft to slightly firm; brittle, crumbly, pulverulent; earthy, often amorphous fracture; tabular cuttings habit; dull to sparkly, rarely subwaxy; clays and silts equally hydrophilic and break down easily; noncalcareous; carbonaceous fragments and detrital material common; earthier cuttings often grade to carbonaceous shale and very low grade coal; note localized ashy kaolinite-rich sandstone. Tuffaceous Sandstone (10350'-10410') = white to grayish white to very light gray, darker grays generally with light yellowish brown secondary colorization; upper very fine to lower fine, rare upper fine grain; round to subround, subangular in part; spherical to subdiscoidal; well to moderate sorting; brittle to crumbly; 60% matrix / 40% grain supported with very fine pulverulent tuff/ devitrified tuff/ ash/ kaolinite; poor siliceous cementation; no visible porosity; lithic to sublithic arenite with locally abundant mafic minerals; note occasional conglomeratic sand and small pebbles. Tuffaceous Sandstone/Sandstone/Sand (10410'-10590') = two color groups: major light gray to medium gray with mod to faint yellowish gray, light olive gray, light brownish gray and pale yellowish brown secondary hues; minor light brownish gray with faint olive gray and light med gray secondary hues; nearly all tuffaceous sandstone displays spotty to pervasive white patchy zones and spots; overall very complex sandstones with diverse characteristics; matrix support is mostly devitrified volcanic ash, and closely grades to a very sandy "ash-stone" that displays a mix of floating grains and variegated grain to grain contact; very subtle micro layers, micro-facies, micro flow structures are discernible; note pervasive white patches, spots and micro-zones of white air-fall and water deposited ash; mostly moderately sorted in fine lower to medium lower range, but overall ranges from very fine lower to pebble fragments; very angular to well rounded, very discoidal thin and flat to spherical; equant to sharply elongated; some large individual pieces display all diverse characteristics; ashy sublithic arenite; 75 -85% monocrystalline-polycrystalline quartz, 5% feldspar, 10-15% lithics and mafic minerals. Tuffaceous Claystone (10590'-10710') = light gray to very light gray; soft; pliable, very pasty; pulverulent; no definable fracture or cuttings habit; hydrophobic; balls up easi ly on shaker; generally massive; surface of cuttings contain drilled sand and varying amounts of disaggregated sediments; claystone also appears pale brown to pale yellowish brown, light olive gray; soft to firm; crumbly; earthy to sub - planar fracture; tabular cuttings habit; silty to sandy in part; often carbonaceous; note dark gray to grayish black carbonaceous shale/lithic coal. SRU 13-27 30 SRU 13-27 31 Coal (10520'-10710') = note overall apps higher grade than previous; black to brownish black; brittle and very tough to hard; subbituminous to bituminous; smooth texture; shiny resinous to vitreous luster; planar to "flat" birdeye fracture; platy to thin platy habit to bladed habit; note associated carbonaceous shale is dense, hard and very tough (unlike all the fragile carbonaceous shales in the younger rocks), note very shiny lithic coal within the carbonaceous shale. Tuffaceous Sandstone (10710'-10770') = grayish white to very light gray, yellowish gray to light olive gray, light pale yellowish brown; very fine to fine grain; moderately well sorted; grain characteristics vary widely from subrounded, subangular, rounded; subdiscoidal, subprismoidal, spherical; non to very slightly calcareous; brittle and dominated by pulverulent ashy, argillaceous matr ix; sublithic to lithic arenite with secondary components of feldspars, greenstone, occasional mafic minerals; there was no stain, odor, fluorescence or cut. Tuffaceous Sandstone/Undifferentiated Sandstone/Sand/Conglomeratic Sandstone/Conglomerate (10850'-11000') = dominant medium dark gray (wet) to olive gray with faint light brownish gray secondary hues, but common shift to higher lightness gray colors in the "ashier" sandstones, and to more olive gray and greenish gray colors in the coarser conglomera tic rocks with increased greenstone lithics; large scale gradual fining upward throughout the interval, but overall poorly sorted; significant mixing of finer and coarser sizes (but also likely bi -modal in local zones); fine upper to pebble, mostly with in medium lower to very coarse lower; finer sands are more angular than conglomeratic sands; largest clasts are often well rounded; note that overall the rocks may be more conglomeratic than logged, with finer sands occupying the large intergrain spaces of the pebbles; overall very diverse group of grains/ clasts, especially the conglomerates; note large moderate hard sedimentary lithic fragments may be bit broken clasts; overall compositional graywacke with very diverse grains and clasts; distinctive greenstone rock fragments, epidote, jasper, citrine. Tuffaceous Sandstone/Sand(11030'-11170') = bulk color is very prominent olive gray to light olive gray with very faint medium gray to medium light gray to greenish gray to yellowish gray to light brow nish gray secondary hues; in illuminated light appears very light gray with pervasive speckled variegated dark spots and micro patches; significant matrix volume, grad to very sandy volcanic ash; fine lower to med lower, moderately well sorted; grains equant to slightly elongated; subangular to angular, discoidal to subspherical; com feldspar grains are prismoidal and tabular; overall slightly calcareous; spotty moderate to rare very calcareous; lithic arenite t to sublithic arenite; estimated 80% pale yellow to marginally bright yellow to slightly whitish yellow sample fluorescence; no prominent staining, but faint brownish yellow color, displays an abundant brittle black solid hydrocarbon, probably gilsonite; instant pale to bright yellow to whitish yellow cut fluorescence that is often milky and increases in intensity with time; pale yellow to gold yellow residual fluorescence; trace pieces with slow streaming; note that the brightest cuts were from sandstone fragments with abundant gilsonite particles. Sand/Sandstone/Conglomeratic Sand/Conglomerate (11170'-11290') = locally near 100% disaggregated grains; light olive gray to pale olive to yellowish gray; moderately well sorted at fine upper to medium lower; range from very fine lower to granule; equant to slightly elongated, subangular to angular, discoidal to subspherical; minor prismoidal, tabular feldspar; trace of well rounded cryptosilica grains; overall slightly calcareous; trace moderate to very calcareous; lithic arenite to sublithic arenite; estimated 65 -75% monocrystalline and polycrystalline quartz, 10-15% feldspar, 15-25% lithics and mafic minerals; lithics dominated by dark gray to grayish black argillite and variegated green -colored low grade metamorphic greenstone rock fragments; abundant grayish black to black mafic minerals and common pale gray to colorless cryptosilica; distinctive rare pinkish red jasper, pink quartzite, epidote, citrine; total sample fluorescence ranges from 80% to 100%; dull to marginally br ight yellow to gold yellow with tiny spots of whitish yellow; instant bright yellow to whitish yellow cut fluorescence that very quickly becomes very bright and milky; spotty bright yellow pieces with very fast bleeding and partial streaming; after a sh ort (5 minute) interval most cuts appear to be of equal intensity; nearly all cuts resulted in pale yellow to gold yellow residual fluorescence. SRU 13-27 32 SRU 13-27 33 Sand/Tuffaceous Sandstone (11290'-11380') = prominent powdery pulverulent supporting matrix that is fragile and disintegrates easily; abundant loose grains with fn loose powder layer; significant fraction of very fn grains are shards winnowed from volcanic ash; transition from light olive gray and pale olive to light gray and very light gray with strong olive hues; com sandstone with mottled white patches; very fine to medium lower; moderately well sorted at fine lower to fine upper; equant, angular -subangular, discoidal to subspherical; matrix is mix of devitrified and vitric ash; very ashy sublithic a renite 100% dull to marginally bright slightly whitish and gold yellow sample fluorescence; note that ash itself appears oil - bearing and fluoresces dull yellow; instant mod bright to bright yellowish white to rare bluish yellowish white cut fluorescence; pale to marginally bright yellow residual fluorescence. Sand/Tuffaceous Sandstone/Minor Tuffaceous Siltstone (11380'-11510') = light olive gray to pale olive to yellowish gray, with light medium gray to light gray as secondary hue; note in part grada tional to tuffaceous siltstone and also light brownish gray in transition; dominantly fine upper to medium lower and commonly well sorted at fine upper boundary; also possible 2nd mode at silt to very fine range (40 -120 microns); equant, angular-subangular, discoidal- subspherical; prominent matrix of devitrified ash and complex matrix that includes tuffaceous silt and calcite cementation; ashy -silty sublithic arenite to lithic arenite; dull to marginally bright yellow to yellowish white sample fluore scence; instant moderately bright yellow to whitish yellow cut fluorescence that increases to bright and milky; all cuts increase in intensity with time; pale yellow to yellowish gold residual fluorescence. Sand/Tuffaceous Sandstone/Non-Differentiated Sandstone/Conglomeratic Sand/Conglomerate (11530'-11690') = light olive gray to pale olive to yellowish gray; range very fine lower to pebble fragments; moderately well sorted at fine upper to medium lower; equant to slightly elongated grain dimensions ; dominantly subangular to angular, discoidal to sub -spherical; minor prismoidal, especially the tabular feldspars; overall slightly calcareous, trace moderate to very calcareous; prominent matrix of devitrified volcanic ash; note increasingly complex matrix when the conglomerate and conglomeratic sand has finer intergrain sand of varying sizes and includes tuffaceous silt -clay and calcite-silica cementation; continued very ashy lithic arenite to sublithic arenite; near 100% marginally dull to modera tely bright gold yellow to whitish yellow sample fluorescence; instant very strong bright to very bright yellowish white cut fluorescence that quickly increases in fluid density "milkiness" and brighter intensity within a short period of time; marginally bright yellow to gold yellow residual fluorescence. Tuffaceous Siltstone/Non-Tuffaceous Siltstone (11690'-11790') =diverse color groups, appears no dominant color; dry primary colors include: medium light gray light brownish gray, light olive gray, olive gray, brownish gray, brownish black; very diverse secondary colors; tuffaceous siltstone is soft and closely gradational to a complex "ash-stone" that has floating particles of silt and sand; textures are equally as diverse as colors; prominent non-tuffaceous micro-micaceous and micaceous siltstone contrasts strongly against all the volcanic ash derived rocks; micro-mica siltstone is several colors but dominantly medium dark gray to dark gray, brittle to moderately hard with micro -mica to microcrystall ine sucrosic textures and often slightly carbonaceous; microsparkly to vitreous lusters; irregular to platy habit. Volcanic Ash/Very Ashy Sandstone (11750' -11835') = actually an "ash-stone" with floating silt particles and sand grains; very unusual color: slightly dominant grayish orange pink to pale red, plus pale yellowish brown to moderate yellowish brown, all mottled with white to pinkish gray to yellowish gray patches. SRU 13-27 34 3.3 Connection Gases 50 units = 1% Methane Equivalent Measured Depth (feet) Subsea Total Vertical Depth (feet) Gas over background (units) Measured Depth (feet) Subsea Total Vertical Depth (feet) Gas over background (units) 8359 -8183 40 9633 -9457 205 8422 -8246 33 9696 -9520 137 8486 -8310 63 9760 -9584 34 8550 8375 54 9886 -9710 770 8613 -8437 43 9949 -9773 87 8676 -8500 44 10011 -9835 130 8739 -8563 24 10075 -9899 118 8802 -8626 30 10138 -9962 108 8876 -8700 18 10201 -10025 212 8939 -8763 14 10264 -10088 131 9001 -8825 16 10327 -10151 330 9064 -8888 20 10391 -10215 151 9128 -8952 17 10455 -10279 315 9191 -9015 23 10520 -10344 347 9254 -9078 25 10580 -10404 158 9317 -9141 36 10645 -10469 216 9381 -9205 34 10770 -10594 187 9443 -9267 37 10835 -10659 166 9506 -9330 77 10900 -10724 102 9570 -9394 176 10960 -10784 116 3.4 Trip Gases 50 units = 1% Methane Equivalent Measured Depth (feet) Trip to (feet) Gas (units) Hours Off Bottom 3688 3000 82 2.0 5204 3600 80 2.1 6215 3550 342 1.9 7787 Surface 345 14.5 8234 6837 897 2.1 8822 Surface 2638 28.7 9822 8700 3443 4.8 10707 8600 3450 3.9 11000 Surface (run 7-5/8” casing) 11835 10980 106 2.0 11835 Surface (wire line logs) 146 33.6 11835 Surface (run 5” liner) 56 27.9 SRU 13-27 35 3.5 Sampling Program / Sample Dispatch Set Type / Purpose Frequency* Interval Dispatched to A W ashed and dried reference samples 30 ft 10 ft 3000 ft – 10980 ft 10980 ft – 11835 ft Hilcorp Alaska LLC 3800 Centerpoint Drive Suite #1000 Anchorage AK 99508 Attn.: Debra Oudean (907) 777-8337 B Washed and dried reference samples 30 ft 10 ft 3000 ft – 10980 ft 10980 ft – 11835 ft Hilcorp Alaska LLC 3800 Centerpoint Drive Suite #1000 Anchorage AK 99508 Attn.: Debra Oudean (907) 777-8337 C Wet unprocessed (1) gallon samples for grain size sieve analysis 5 ft 5830 ft to 5880 ft Schlumberger 6350 W. Sam Houston Parkway North Houston, Texas 77041 Attn: Joe Loman * Sample frequency was locally altered according to drill rate constraints and zones of interest. SRU 13-27 36 4 DRILLING DATA 4.1 Directional Survey Data Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 18.5 0 246.94 18.5 0 0 0 0 268 0.62 246.94 268 -0.53 -1.24 -0.99 0.25 362 0.93 231.73 361.99 -1.20 -2.31 -2.04 0.39 421 1.17 268.85 420.98 -1.51 -3.29 -2.72 1.20 446 1.26 262.54 445.97 -1.55 -3.81 -2.97 0.64 538 2.35 286.93 537.93 -1.13 -6.62 -3.73 1.42 565 2.60 287.44 564.90 -0.79 -7.74 -3.87 0.93 626 3.37 291.54 625.82 0.29 -10.72 -4.10 1.31 721 3.93 305.53 720.63 3.20 -15.97 -3.57 1.10 751 4.11 306.25 750.55 4.44 -17.67 -3.14 0.62 810 4.72 304.62 809.38 7.07 -21.38 -2.25 1.06 870 4.91 305.99 869.17 9.98 -25.49 -1.26 0.37 948 5.07 311.29 946.87 14.21 -30.78 0.46 0.63 997 4.98 303.87 995.68 16.83 -34.17 1.46 1.34 1060 5.15 305.78 1058.44 20.00 -38.73 2.51 0.38 1122 5.38 307.33 1120.17 23.39 -43.30 3.74 0.44 1250 4.73 292.44 1247.68 29.05 -52.95 4.98 1.14 1376 5.06 299.76 1373.22 33.79 -62.58 5.39 0.56 1476 5.14 300.51 1472.83 38.25 -70.27 6.34 0.10 1501 4.89 299.45 1497.73 39.34 -72.16 6.57 1.07 1568 4.24 302.58 1564.52 42.08 -76.73 7.21 1.04 1630 4.09 303.38 1626.36 44.53 -80.51 7.91 0.26 1694 4.21 305.18 1690.19 47.14 -84.34 8.74 0.28 1754 3.61 304.76 1750.05 49.49 -87.69 9.51 1.00 1817 3.50 305.98 1812.93 51.75 -90.87 10.28 0.21 1881 3.13 305.93 1876.82 53.92 -93.87 11.05 0.58 1944 2.33 304.60 1939.75 55.66 -96.32 11.64 1.27 2010 1.60 300.87 2005.71 56.89 -98.21 11.99 1.12 2073 0.56 282.93 2068.70 57.41 -99.27 12.04 1.72 2136 0.10 107.66 2131.69 57.46 -99.51 11.99 1.05 2199 0.22 169.01 2194.69 57.33 -99.44 11.89 0.31 2261 0.23 197.11 2256.69 57.09 -99.45 11.67 0.18 2324 0.18 125.53 2319.69 56.91 -99.41 11.53 0.39 2388 0.40 163.84 2383.69 56.64 -99.26 11.34 0.44 2450 0.38 165.95 2445.69 56.23 -99.15 11.01 0.04 SRU 13-27 37 Survey Data (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 2514 0.34 101.63 2509.69 55.99 -98.92 10.88 0.60 2577 0.37 101.05 2572.69 55.91 -98.53 10.97 0.05 2640 0.43 112.46 2635.69 55.78 -98.12 11.02 0.16 2704 0.54 121.81 2699.69 55.53 -97.64 10.99 0.21 2766 0.38 119.98 2761.68 55.28 -97.21 10.93 0.26 2829 0.59 116.75 2824.68 55.03 -96.74 10.89 0.34 2892 0.44 125.01 2887.68 54.74 -96.25 10.83 0.27 2956 0.69 117.51 2951.68 54.42 -95.71 10.76 0.41 3079 1.31 110.77 3074.66 53.58 -93.74 10.79 0.51 3138 1.57 84.13 3133.64 53.43 -92.30 11.23 1.20 3202 2.19 47.01 3197.61 54.35 -90.54 12.79 2.08 3265 3.60 37.91 3260.52 56.73 -88.44 15.82 2.35 3329 4.37 28.49 3324.37 60.46 -86.04 20.20 1.58 3392 5.13 18.14 3387.15 65.25 -84.02 25.40 1.81 3455 6.43 13.15 3449.83 71.36 -82.34 31.67 2.21 3517 8.17 13.15 3511.33 79.03 -80.55 39.40 2.81 3581 10.07 14.91 3574.52 88.86 -78.08 49.39 3.00 3644 11.64 16.47 3636.39 100.28 -74.86 61.13 2.54 3710 13.06 17.03 3700.86 113.80 -70.78 75.14 2.16 3774 14.71 16.93 3762.99 128.49 -66.30 90.38 2.58 3836 16.04 16.63 3822.77 144.23 -61.56 106.69 2.15 3896 17.30 16.88 3880.24 160.71 -56.59 123.76 2.10 3961 18.08 17.67 3942.17 179.56 -50.73 143.37 1.26 4022 18.99 20.95 4000.01 197.85 -44.30 162.69 2.27 4085 19.06 21.88 4059.56 216.97 -36.80 183.21 0.49 4150 19.47 19.63 4120.93 237.02 -29.21 204.61 1.30 4214 19.79 19.20 4181.21 257.30 -22.06 226.05 0.55 4275 19.69 18.99 4238.62 276.77 -15.32 246.57 0.20 4339 19.96 20.48 4298.83 297.20 -7.990 268.22 0.90 4402 20.29 21.58 4357.98 317.43 -0.210 289.86 0.80 4465 20.12 21.04 4417.11 337.70 7.690 311.60 0.40 4529 20.00 21.09 4477.22 358.19 15.58 333.52 0.19 4591 20.01 21.43 4535.48 377.95 23.28 354.70 0.19 4655 20.03 20.90 4595.61 398.38 31.19 376.59 0.29 4717 20.02 20.20 4653.87 418.26 38.64 397.78 0.39 4780 19.99 19.23 4713.07 438.55 45.91 419.27 0.53 4844 20.17 19.37 4773.17 459.29 53.17 441.17 0.29 4907 20.01 20.14 4832.34 479.66 60.48 462.75 0.49 4969 20.06 19.96 4890.59 499.61 67.77 483.94 0.13 5032 20.08 20.19 4949.76 519.92 75.19 505.51 0.13 SRU 13-27 38 Survey Data (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 5096 20.05 20.14 5009.88 540.53 82.76 527.42 0.05 5160 20.01 20.14 5070.01 561.11 90.30 549.29 0.06 5222 20.05 20.36 5128.26 581.03 97.66 570.48 0.14 5285 19.93 20.24 5187.46 601.23 105.13 591.97 0.20 5348 19.88 20.33 5246.70 621.35 112.56 613.37 0.09 5411 19.68 19.97 5305.98 641.36 119.91 634.64 0.37 5474 19.62 20.05 5365.31 661.27 127.16 655.78 0.10 5538 19.40 20.20 5425.64 681.34 134.51 677.10 0.35 5601 19.94 19.92 5484.96 701.26 141.78 698.26 0.87 5664 19.85 20.13 5544.20 721.40 149.13 719.64 0.18 5727 20.26 20.23 5603.38 741.68 156.58 741.20 0.65 5791 20.28 20.16 5663.42 762.49 164.23 763.32 0.05 5854 20.28 20.36 5722.51 782.97 171.79 785.11 0.11 5917 20.04 20.44 5781.65 803.33 179.36 806.78 0.38 5980 19.91 20.64 5840.86 823.48 186.91 828.26 0.23 6044 19.85 20.73 5901.05 843.84 194.60 849.99 0.11 6107 19.58 20.30 5960.36 863.74 202.05 871.20 0.49 6167 19.56 19.91 6016.89 882.62 208.96 891.25 0.22 6230 19.35 20.12 6076.29 902.33 216.14 912.18 0.35 6296 19.14 20.45 6138.60 922.74 223.68 933.89 0.36 6359 19.43 20.97 6198.07 942.20 231.04 954.66 0.53 6422 19.60 20.95 6257.45 961.85 238.57 975.68 0.27 6485 19.35 21.03 6316.85 981.46 246.09 996.65 0.40 6547 19.54 21.77 6375.31 1000.68 253.62 1017.27 0.50 6610 19.42 21.73 6434.70 1020.19 261.41 1038.26 0.19 6674 19.76 22.05 6495.00 1040.10 269.41 1059.71 0.56 6737 20.64 20.98 6554.12 1060.34 277.38 1081.44 1.51 6801 20.53 19.73 6614.04 1081.44 285.21 1103.89 0.71 6864 20.62 19.16 6673.02 1102.31 292.58 1125.96 0.35 6927 20.39 19.47 6732.03 1123.14 299.88 1147.96 0.40 6990 20.67 19.89 6791.03 1143.94 307.32 1169.99 0.50 7053 20.54 19.14 6850.00 1164.84 314.73 1192.09 0.47 7116 20.47 19.89 6909.00 1185.64 322.10 1214.09 0.43 7180 20.25 19.37 6969.01 1206.61 329.58 1236.29 0.45 7242 20.50 19.66 7027.13 1226.96 336.79 1257.81 0.43 7305 20.23 19.64 7086.19 1247.61 344.16 1279.67 0.43 7368 20.49 19.36 7145.25 1268.27 351.48 1301.52 0.44 7431 20.36 19.29 7204.29 1289.01 358.75 1323.43 0.21 7495 20.33 19.71 7264.30 1309.99 366.18 1345.62 0.23 7558 20.19 19.24 7323.40 1330.56 373.46 1367.36 0.34 SRU 13-27 39 Survey Data (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 7620 20.16 19.06 7381.60 1350.76 380.47 1388.67 0.11 7683 19.89 19.01 7440.79 1371.15 387.51 1410.16 0.43 7746 19.90 19.95 7500.03 1391.36 394.65 1431.53 0.51 7810 19.72 19.64 7560.24 1411.77 402.00 1453.16 0.33 7873 19.77 19.03 7619.54 1431.85 409.05 1474.37 0.34 7936 19.78 18.78 7678.82 1452.02 415.95 1495.60 0.14 7999 19.56 19.59 7738.15 1472.04 422.92 1516.73 0.56 8063 19.52 19.44 7798.46 1492.22 430.07 1538.07 0.10 8126 19.54 18.95 7857.84 1512.11 437.00 1559.06 0.26 8189 19.47 18.74 7917.22 1532.02 443.79 1580.01 0.16 8251 19.21 19.40 7975.72 1551.42 450.50 1600.47 0.55 8313 19.11 20.23 8034.29 1570.57 457.40 1620.76 0.47 8377 19.17 21.01 8094.75 1590.21 464.79 1641.71 0.41 8442 19.31 22.22 8156.12 1610.12 472.68 1663.11 0.65 8505 19.34 22.54 8215.57 1629.40 480.61 1683.94 0.17 8567 19.18 22.21 8274.10 1648.31 488.40 1704.39 0.31 8630 19.72 23.72 8333.50 1667.62 496.59 1725.36 1.17 8693 20.44 25.03 8392.68 1687.32 505.52 1746.99 1.35 8755 21.01 26.51 8450.66 1707.07 515.06 1768.92 1.25 8820 21.24 27.03 8511.29 1727.99 525.61 1792.32 0.46 8883 22.05 27.60 8569.85 1748.63 536.28 1815.51 1.33 8946 23.34 26.32 8627.97 1770.30 547.29 1839.79 2.19 9008 24.16 27.42 8684.72 1792.57 558.58 1864.73 1.50 9072 24.34 30.43 8743.08 1815.57 571.29 1890.91 1.95 9136 24.97 34.36 8801.25 1838.10 585.59 1917.30 2.74 9198 25.28 36.96 8857.38 1859.48 600.94 1943.08 1.85 9262 25.35 37.54 8915.24 1881.26 617.50 1969.72 0.40 9325 25.49 37.96 8972.14 1902.64 634.06 1995.99 0.36 9388 25.53 38.28 9029.00 1923.99 650.81 2022.30 0.23 9451 25.70 37.50 9085.80 1945.48 667.54 2048.75 0.60 9515 25.67 37.57 9143.48 1967.48 684.44 2075.72 0.07 9578 25.60 35.45 9200.28 1989.38 700.65 2102.32 1.46 9641 25.82 35.02 9257.04 2011.71 716.42 2129.13 0.46 9704 25.99 34.75 9313.71 2034.28 732.16 2156.16 0.33 9763 25.94 34.15 9366.76 2055.59 746.77 2181.56 0.45 9827 26.08 34.57 9424.28 2078.75 762.61 2209.17 0.36 9893 26.46 34.33 9483.46 2102.84 779.14 2237.90 0.60 9955 25.60 34.19 9539.17 2125.33 794.45 2264.68 1.39 10020 25.48 34.16 9597.82 2148.51 810.19 2292.26 0.19 10082 25.51 34.31 9653.78 2170.58 825.21 2318.53 0.11 SRU 13-27 40 Survey Data (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 10145 25.55 34.83 9710.63 2192.93 840.61 2345.22 0.36 10208 25.46 35.38 9767.49 2215.13 856.21 2371.84 0.40 10272 25.17 35.57 9825.34 2237.41 872.10 2398.66 0.47 10336 24.76 35.31 9883.36 2259.42 887.76 2425.14 0.66 10399 24.61 35.99 9940.61 2280.80 903.09 2450.91 0.51 10461 24.58 34.95 9996.98 2301.81 918.07 2476.20 0.70 10524 24.61 34.98 10054.27 2323.30 933.09 2501.94 0.05 10588 24.81 34.79 10112.41 2345.25 948.39 2528.21 0.34 10651 24.80 34.54 10169.59 2366.99 963.43 2554.19 0.17 10714 24.72 34.46 10226.80 2388.73 978.37 2580.13 0.14 10776 24.68 34.67 10283.13 2410.07 993.07 2605.60 0.16 10840 24.47 34.94 10341.33 2431.92 1008.26 2631.75 0.37 10904 24.62 34.23 10399.55 2453.81 1023.35 2657.88 0.52 10945 24.78 34.16 10436.80 2467.98 1032.98 2674.75 0.40 11066 25.48 34.81 10546.34 2510.33 1062.08 2725.27 0.62 11128 25.28 35.54 10602.36 2532.06 1077.39 2751.35 0.60 11222 25.06 36.92 10687.44 2564.30 1101.01 2790.42 0.67 11252 25.01 37.11 10714.62 2574.44 1108.65 2802.79 0.32 11315 24.84 36.69 10771.75 2595.67 1124.60 2828.67 0.39 11377 24.58 36.37 10828.07 2616.50 1140.02 2853.97 0.47 11440 24.46 36.60 10885.39 2637.52 1155.57 2879.50 0.24 11503 24.28 36.38 10942.78 2658.42 1171.03 2904.88 0.32 11564 23.88 36.55 10998.47 2678.43 1185.82 2929.19 0.67 11628 23.75 36.23 11057.02 2699.24 1201.15 2954.43 0.29 11691 23.52 35.76 11114.74 2719.67 1216.00 2979.14 0.47 11753 22.96 35.01 11171.70 2739.61 1230.16 3003.12 1.02 11777 22.52 34.88 11193.84 2747.22 1235.48 3012.23 1.85 p. 11835 22.52 34.88 p. 11247.42 2765.44 1248.18 3034.04 0 SRU 13-27 41 4.2 Bit Record Bit Size Make Type/ SN Jets/ TFA Depth In Depth Out Footage Drilled Bit Hours Avg. ROP (ft/hr) Avg. WOB (klbs) Avg. RPM Avg. PP (psi) Grade 1 16” HCC MXL-1X/ 5201092 3x16,1x14/ 0.7392 78’ 3014’ 2936’ 40.13 88.0 10.2 77.2 1772 1-1-WT-A-4-I-NO-TD 2 9-7/8” Smith XR+/ PX5266 3x16,1x12/ 0.6993 3014’ 3124’ 110’ 3.04 40.3 9.3 66.1 1552 1-1-WT-A-E-I-NO-TD 3 9-7/8” HCC QD505FX/ 7143548 7x12/ 0.7782 3124’ 8822’ 5698’ 152.78 60.8 10.3 67.3 2566 2-3-CT-H-X-1/16-PN-PR 4 9-7/8” HCC QD505FXX /7143547 8x12/ 0.8832 8822’ 11000’ 2178’ 118.60 31.1 19.6 89.3 3253 4-4-CT-A-X-I-PN-TD 5 6-3/4” HCC DP505X/ 7034894 5x11/ 0.4640 11000’ 11835’ 835’ 31.73 44.1 3.7 57.8 2221 2-1-CT-N-X-I-BT-TD SRU 13-27 42 4.3 Mud Record Contractor: Baroid Mud Type: Spud Mud Date Depth (ft) MW (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) O/W Ratio Sd (%) MBT pH Cl (mg/L) Ca (mg/L) 01/27/2013 1049 10.10 115 27 44 16/37/78 7.4 2/0 8.8 0.0/91.0 0.50 25.0 8.8 500 20 01/28/2013 2065 10.10 93 31 29 16/48/80 7.6 2/0 9.8 0.0/90.0 0.50 25.0 9.0 500 40 01/29/2013 3014 10.15 70 29 38 17/53/73 8.8 2/0 8.8 0.0/91.0 0.50 25.0 8.8 600 160 01/30/2013 3014 10.10 52 28 17 5/7/9 8.8 2/0 8.8 0.0/91.0 0.50 22.5 8.5 500 140 01/31/2013 3014 10.15 54 27 17 4/6/7 8.8 2/0 8.6 0.0/91.2 0.50 22.5 8.4 500 80 Contractor: Baroid Mud Type: EZ Mud 6% KCl Date Depth (ft) MW (ppg) VIS (s/qt) PV YP Gels FL (cc) Sols (%) O/W Ratio Sd (%) MBT (ppb eq.) pH Alk (Pm) Cl (mg/L) Ca (mg/L) 02/01/2013 3014 11.50 58 15 21 6/9/11 5.8 12.5 0.0/86.0 - - 8.5 0.10 30000 200 02/02/2013 3014 11.50 58 18 18 7/10/11 6.0 12.5 0.0/86.0 - - 9.2 0.15 31000 200 02/03/2013 3124 11.45 50 16 22 6/13/17 4.8 12.4 0.0/86.0 0.10 2.5 8.8 0.10 32000 160 02/04/2013 3976 11.55 44 17 25 6/9/13 4.8 11.5 0.0/86.0 0.75 5.0 10.9 0.60 33000 160 02/05/2013 4881 11.70 47 20 26 7/11/16 4.4 12.7 0.0/85.0 0.75 4.0 10.9 0.65 31000 120 02/06/2013 5256 11.90 47 24 27 7/11/14 4..2 13.8 0.0/84.0 0.25 4.0 10.1 0.40 30000 160 02/07/2013 6082 12.05 51 24 24 6/10/12 4.2 13.7 0.0/84.0 0.25 5.0 9.8 0.35 31000 160 02/08/2013 6745 12.40 50 26 23 5/10/13 4.0 15.9 0.0/82.0 0.25 5.0 9.4 0.35 30000 160 02/09/2013 7224 12.55 50 30 23 5/10/18 3.8 15.9 0.0/82.0 0.25 6.0 9.7 0.60 29500 160 02/10/2013 7649 12.55 57 29 26 5/14/19 3.6 16.1 0.0/82.0 0.25 5.0 9.9 0.45 27000 160 02/11/2013 8249 12.50 54 28 23 5/17/23 4.0 16.3 0.0/81.5 0.10 8.5 9.2 0.40 31000 160 02/12/2013 8596 12.50 51 29 21 5/15/25 4.0 16.2 0.0/81.5 0.10 8.5 9.1 0.30 33000 160 Abbreviations MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Filtrate Loss FC = Filter Cake Sols = Solids O/W = Oil to Water ratio Sd = Sand content Cl = Chlorides Ca = Hardness SRU 13-27 43 Contractor: Baroid Mud Type: EZ Mud 6% KCl Date Depth (ft) MW (ppg) VIS (s/qt) PV YP Gels FL (cc) Sols (%) O/W Ratio Sd (%) MBT (ppb eq.) pH Alk (Pm) Cl (mg/L) Ca (mg/L) 02/13//201 3 8822 12.50 53 31 23 5/17/27 4.4 16.2 0.5/81.0 0.10 8.5 9.8 0.60 33000 120 02/14/2013 8822 12.50 57 30 27 5/13/18 4.4 16.2 0.5/81.0 0.10 8.5 9.3 0.30 32000 120 02/15/2013 9045 12.50 60 32 25 5/18/25 4.0 16.0 1.1/80.6 0.10 9.0 9.1 0.45 33000 200 02/16/2013 9445 12.50 64 31 29 5/21/28 4.2 16.1 1.1/80.5 0.10 9.5 9.3 0.60 33000 120 02/17/2013 9867 12.55 53 27 18 3/12/19 4.6 17.8 1.0/79.2 0.10 8.5 9.0 0.45 29000 160 02/18/2013 10190 12.70 57 29 21 4/19/29 4.0 17.5 0.9/79.5 0.10 8.0 8.7 0.20 31000 200 02/19/2013 10477 12.70 52 26 18 2/20/29 4.2 17.5 1.0/79.4 0.25 7.5 9.3 0.50 31000 120 02/20/2013 10707 12.90 52 25 16 6/363/48 4.4 18.8 1.0/78.0 0.25 6.0 9.5 0.65 32000 120 02/21/2013 10930 12.95 55 27 19 6/24/33 3.8 18.8 1.0/78.0 0.25 6.0 9.5 0.60 32000 120 02/22/2013 11000 13.10 63 27 21 6/21/31 3.6 19.1 1.8/77.0 0.25 9.0 9.0 0.50 32000 120 02/23/2013 11000 13.20 62 29 23 6/20/29 3.6 19.7 1.8/76.4 0.25 9.0 8.8 0.30 32000 120 02/24/2013 11000 13.20 62 26 19 7/22/29 3.8 19.7 1.8/72.4 0.25 10.0 8.0 0.10 31000 200 02/25/2013 11000 13.05 62 24 17 6/17/20 3.6 19.1 1.8/77.0 0.25 7.5 9.6 0.45 31000 200 02/26/2013 11000 13.10 64 29 19 8/20/28 3.6 19.2 1.8/77.0 0.25 10.0 8.6 0.15 29500 200 02/27/2013 11000 13.10 68 29 21 8/21/28 3.8 19.3 1.8/77.0 0.25 9.0 10.5 0.50 28000 280 02/28/2013 11000 9.50 53 13 19 4/14/16 4.4 4.2 0.0/93.5 - 1.5 7.8 - 28000 200 03/01/2013 10988 9.55 54 10 16 6/11/14 4.5 4.5 0.0/93.8 - 2.0 8.5 - 31000 200 03/02/3013 11536 9.65 44 13 19 6/8/11 4.2 5.0 0.0/93.2 - 2.5 10.2 0.80 33000 200 03/03/2013 11835 9.65 44 12 18 6/7/9 4.2 9.8 0.0/93.0 - 2.5 9.7 0.50 32000 180 03/04/2013 11835 9.70 46 13 17 6/7/8 4.2 5.5 0.0/92.8 0.10 2.5 9.8 0.25 32000 200 03/05/2013 11835 9.75 50 13 19 6/8/9 4.4 6.2 0.0/92.2 0.10 2.5 9.5 0.45 30000 200 03/06/2013 11835 9.85 43 12 17 6/8/10 4.4 6.3 0.0/92.0 0.10 2.5 9.0 0.10 32000 200 03/07/2013 Abbreviations MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Filtrate Loss FC = Filter Cake Sols = Solids O/W = Oil to Water ratio Sd = Sand content Cl = Chlorides Ca = Hardness SRU 13-27 44 SCU 44-33 45 5 SHOW REPORTS SCU 44-33 46 SCU 44-33 47 SCU 44-33 48 SCU 44-33 49 SCU 44-33 50 SCU 44-33 51 SCU 44-33 52 6 DAILY REPORTS