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Home My WebLink About220-037Kaitlyn 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: 1/12/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) GPT-PERF 12/09/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 10:50 am, Jan 12, 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: 1/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) Perf 11/01/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 12:36 pm, Jan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ŽĨĂŶŶƵůĂƌ͘^ƉŽƚĂŶĚƌŝŐƵƉͲůŝŶĞƚĞƐƚůƵďƌŝĐĂƚŽƌƚŽϮϱϬůŽǁĂŶĚƉƐŝϯ͕ϬϬϬƉƐŝ͘ͲůŝŶĞZ/,ǁŝƚŚ'ƵŶƐĂŶĚƉĞƌĨĂƚϱ͕ϮϵϬΖƚŽ ϱ͕ϮϵϱΖǁŝƚŚϮĨƚ͘ǆϱĨƚ͘ƚďŐƉƵŶĐŚůŽĂĚĞĚǁŝƚŚϮϬϭͬϮΗƐŚŽƚƐƉŽŽŚĐŚĞĐŬŶĞǆƚƌƵŶ͕ĐŚĂŶŐĞŽƵƚůĞĂŬŝŶŐĨŝƌŝŶŐŚĞĂĚƐ͕Z/, ǁŝƚŚZƵŶηϮĂŶĚƐƉŽƚƚďŐƉƵŶĐŚĂƚϰ͕ϵϯϱΖƚŽϰ͕ϵϰϬĨƚƉƵŶĐŚƚďŐǁŝƚŚϮΗǆϱΖƚďŐƉƵŶĐŚůŽĂĚǁŝƚŚϮϬϭͬϮΗƐŚŽƚƐƉŽŽŚĂůů ƐŚŽƚƐĨŝƌĞĚ͕ƉŝĐŬƵƉƌƵŶηϯ͕ZŝŚĂŶĚƐƉŽƚƚďŐƉƵŶĐŚĂƚϰ͕ϵϯϱĨƚ͘ƚŽϰ͕ϵϰϬĨƚ͘ĨŝƌĞƉƵŶĐŚƉŽŽŚĂůůƐŚŽƚƐĨŝƌĞĚ͘DĂŬĞƵƉĂ DĂŐŶƵŵƐĞƌŝĞƐZĨŽƌϱͲϭͬϮΗϭϳηĐƐŐ͕ƚĞŵƉƌĂƚŝŶŐĂƚϮϱϬĚĞŐǁŝƚŚĂƚϭϬ<ĚŝĨĨĞƌĞŶƚŝĂůůŽŐƐĂŵĞŽŶĚĞƉƚŚĂŶĚƐĞƚĂƚ ϰ͕ϵϱϬΖ>DWŽŽŚ͕ůĂǇĚŽǁŶƌƵŶŶŝŶŐƚŽŽůƐĂŶĚƌŝŐĚŽǁŶͲůŝŶĞ͘ ϭϬͬϭϭͬϮϬϮϭͲDŽŶĚĂǇ ƌĞǁĂƌƌŝǀĞƐĂƚĨĂĐŝůŝƚǇĂŶĚŽďƚĂŝŶƐƉĞƌŵŝƚ͘D/ZhŽŶǁĞůůĂŶĚƉƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϮ͕ϱϬϬƉƐŝŚŝŐŚ͘Z/, ǁŝƚŚϭͲϭϭͬϭϲΗƚƵďŝŶŐƉƵŶĐŚĞƌ͘,ĂǀĞƚƌŽƵďůĞŐĞƚƚŝŶŐĚŽǁŶƉĂƐƚϱϬΖ͘ůĞĚt,WĚŽǁŶƚŽϰϬϬƉƐŝĂŶĚŐĞƚƉĂƐƚ͘ŽƌƌĞůĂƚĞ ǁŝƚŚŽƉĞŶŚŽůĞůŽŐƐĂŶĚƉƵŶĐŚƚƵďŝŶŐĨƌŽŵϱ͕ϮϵϬΖͲϱ͕ϮϵϱΖ͘t,WĚĞĐƌĞĂƐĞĚĨƌŽŵϰϬϬƚŽϯϱϬƉƐŝ͘WKK,͕ĂůůƐŚŽƚƐĨŝƌĞĚ͘ ZDKĞͲůŝŶĞ͘ ϭϬͬϬϳͬϮϬϮϭͲdŚƵƌƐĚĂǇ D/Zh,ŽƚŽŝůƚƌƵĐŬ͘&ůƵŝĚƉĂĐŬƉƌŽĚƵĐƚŝŽŶĐĂƐŝŶŐǁŝƚŚƉƌŽĚƵĐĞĚǁĂƚĞƌ͘ϳϱͲϳϬďďůƐƉƵŵƉĞĚďĞĨŽƌĞĐĂƚĐŚŝŶŐĨůƵŝĚůĞǀĞů͘ tĂůŬƉƌĞƐƐƵƌĞƵƉƚŽϯ͕ϬϬϬƉƐŝ͘ůĞĞĚĚŽǁŶϮƐĞƉĞƌĂƚĞƚŝŵĞƐƚŽĨŝǆůĞĂŬƐŽŶz:K^ĞͲůŝŶĞǁŝƌĞůŝŶĞǀĂůǀĞƐ͘ZĞƉůĂĐĞĚůĞĂŬŝŶŐ ŶĞĞĚůĞǀĂůǀĞŽŶŶŝŐŚƚĐĂƉ͘WƌĞƐƐƵƌĞƚĞƐƚĂŶĚƌĞĐŽƌĚŐƌĂƉŚŽŶŚŽƚŽŝůƚƌƵĐŬ͘'ŽŽĚƚĞƐƚ͘ůĞĞĚĚŽǁŶĂŶĚůĞĂǀĞϭ͕ϬϬϬƉƐŝ ^/dWŽŶƉƌŽĚƵĐƚŝŽŶĐĂƐŝŶŐĂƐƉĞƌƐƵŶĚƌǇ͘ ϭϬͬϭϯͬϮϬϮϭͲtĞĚŶĞƐĚĂǇ ϬϵͬϮϲͬϮϬϮϭͲ^ƵŶĚĂǇ ͲůŝŶĞĐƌĞǁĂƌƌŝǀĞƐĂƚĨĂĐŝůŝƚǇ͕ŽďƚĂŝŶƉĞƌŵŝƚ͘D/ZhƵŶŝƚ͕ǁĂŝƚŽŶĨŝĞůĚƚƌŝƉůĞǆƚŽĂƌƌŝǀĞĂŶĚĂŶĚƉƌĞƐƐƵƌĞƚĞƐƚƚŽϮϱϬƉƐŝůŽǁ ĂŶĚϯϬϬϬƉƐŝŚŝŐŚ͘Z/,ǁŝƚŚϱ͘ϱΗ/W͘ŽƌƌĞůĂƚĞǁŝƚŚĨŝĞůĚĞŶŐŝŶĞĞƌĂŶĚƐĞƚĂƚϱϯϭϬΖ͘Z/,ǁŝƚŚĐĞŵĞŶƚĚƵŵƉďĂŝůĞƌƚĂŐ ƉůƵŐĂŶĚĚƵŵƉϱŐĂůůŽŶƐŽĨĐĞŵĞŶƚĨŽƌĂϱΖĐĞŵĞŶƚĐĂƉ͘ZDKĞͲůŝŶĞ͘ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϮϰͲϯϮ ϱϬͲϭϯϯͲϮϬϲϴϴͲϬϬͲϬϬ ϮϮϬͲϬϯϳ WƵŵƉĚŽǁŶƚďŐĂƚϭďƉŵĂƚϴϱϬƉƐŝƉƵŵƉŝŶŐŝŶ ĂƚϴϱϬƉƐŝ͕ƉƵŵƉϭϯďďůƐϴ͘ϰƉƉŐǁĂƚĞƌ ƉƵŶĐŚƚƵďŝŶŐĨƌŽŵϱ͕ϮϵϬΖͲϱ͕ϮϵϱΖ͘ Only 5' cement atop CIBP so far. -WCB Z/,ǁŝƚŚϱ͘ϱΗ/W͘ŽƌƌĞůĂƚĞǁŝƚŚĨŝĞůĚĞŶŐŝŶĞĞƌĂŶĚƐĞƚĂƚϱϯϭϬΖ͘ Upper tubing punch done where planned. -WCB Z/, ǁŝƚŚZƵŶηϮĂŶĚƐƉŽƚƚďŐƉƵŶĐŚĂƚϰ͕ϵϯϱΖƚŽϰ͕ϵϰϬĨƚ CIBP set at same depth as sundry program. -WCB ůĞĞĚĚŽǁŶĂŶĚůĞĂǀĞϭ͕ϬϬϬƉƐŝ ^/dWŽŶƉƌŽĚƵĐƚŝŽŶĐĂƐŝŶŐĂƐƉĞƌƐƵŶĚƌǇ ͲůŝŶĞZ/,ǁŝƚŚ'ƵŶƐĂŶĚƉĞƌĨĂƚϱ͕ϮϵϬΖƚŽ ϱ͕ϮϵϱΖǁŝƚŚϮĨƚ͘ǆϱĨƚ͘ƚďŐƉƵŶĐŚ WƌĞƐƐƵƌĞƚĞƐƚĂŶĚƌĞĐŽƌĚŐƌĂƉŚŽŶŚŽƚŽŝůƚƌƵĐŬ͘'ŽŽĚƚĞƐƚ͘ Lower tubing punched performed where planned. -WCB Z/,ǁŝƚŚĐĞŵĞŶƚĚƵŵƉďĂŝůĞƌƚĂŐ ƉůƵŐĂŶĚĚƵŵƉϱŐĂůůŽŶƐŽĨĐĞŵĞŶƚĨŽƌĂϱΖĐĞŵĞŶƚĐĂƉ tĂůŬƉƌĞƐƐƵƌĞƵƉƚŽϯ͕ϬϬϬƉƐŝ͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϵͬϮϲͬϮϭ ϭϮͬϭϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϮϰͲϯϮ ϱϬͲϭϯϯͲϮϬϲϴϴͲϬϬͲϬϬ ϮϮϬͲϬϯϳ ,ĞůĚW:^DǁŝƚŚĐƌĞǁƐ͘ŚĞĐŬǁĞůůĨŽƌƉƌĞƐƐƵƌĞΗϬΗƌĞĂŬĐŝƌĐƵůĂƚŝŽŶ͕ĐŽŶƚŝŶƵĞƚŽĚƌŝůůŽŶŵƚƌĞƚĂŝŶĞƌΘĨŝƌŵĐŵƚĨƌŽŵ ϰ͕ϵϰϲĨƚ͘ƚŽϱ͕ϮϮϮĨƚ͘ĚƉŵǁŝƚŚϯͬϱŬǁŽď͕ĂƚϴϬƌƉŵ͕ǁŝƚŚϮϱϬϬƚŽϯϬϬϬĨƚ͘ůďƐ͘ƚŽƌƋƵĞƉƵŵƉŝŶŐĂƚϭ͘ϱďƉŵǁŝƚŚϮϬϬƉƐŝ͘ ŝƌĐƵůĂƚĞĂƚϱ͕ϮϮϮĨƚ͘ĚƉŵĂƚϭ͘ϱďƉŵĂƚϮϬϬƉƐŝ͕ďůŽǁĚŽǁŶƐƵƌĨĂĐĞůŝŶĞƐĂŶĚƐĞĐƵƌĞǁĞůůĨŽƌƚŚĞŶŝŐŚƚ͘ ϭϬͬϭϲͬϮϬϮϭͲ^ĂƚƵƌĚĂǇ ,ĞůĚW:^DͲƌŬĐŝƌĐƵůĂƚŝŽŶǁŝƚŚƌŝŐƉƵŵƉ͕Ăƚ͘ϮϬďƉŵ͕ŝŶĐƌĞĂƐĞĚƌĂƚĞƚŽ͘ϱďƉŵƉƌĞƐƐƵƌĞĚƵƉƚŽϭϬϬϬƉƐŝ͕ΘŚĂĚŶŽ ƌĞƚƵƌŶƐ͕ůĞĞĚŽĨĨƉƌĞƐƐƵƌĞƐĞƚƉƵƉŵĂŶŝĨŽůĚĂŶĚƌŝŐŐŝŶŐƵƉůŝŶĞƐĨŽƌĐŵƚũŽď͘ĞŵĞŶƚĞƌƐĂƌƌŝǀĞĚŽŶůŽĐĂƚŝŽŶ͕^ƉŽƚƚƌƵĐŬƐ ΘZŝŐƵƉĐĞŵĞŶƚĞƌƐ͕ƌŝŐƵƉŽƉĞŶƚŽƉƚĂŶŬ͕ƌŝŐƵƉůŝŶĞƐ͕ƌŝŐƵƉŚŽƐĞƚŽ/͘,ĞůĚW:^DǁŝƚŚĐƌĞǁƐ͕ĨŝůůůŝŶĞƐ͕ǁŝƚŚϮďďůƐ ǁĂƚĞƌĂƚϭďƉŵĂƚϰϯϬƉƐŝ͕ƉƌĞƐƐƵƌĞƚĞƐƚƚŽϮϱϬΘϯϮϬϬƉƐŝŐŽŽĚƚĞƐƚ͕ƐƚĂďůŝƐŚŝŶũĞĐƚŝŽŶƌĂƚĞĂƚ͘ϲďƉŵĂƚϭϮϬϬƉƐŝ͕ϭďƉŵ ĂƚϭϯϱϬƉƐŝ͕ϭ͘ϱďƉŵĂƚϭϰϬϬƉƐŝ͕Ϯ͘ϬďƉŵĂƚϭϳϬϬƉƐŝ͕ΘĂƚϮ͘ϱďƉŵĂƚϭϴϬϬƉƐŝ͕ƐŚƵƚĚŽǁŶƉƵŵƉ͕ŵŝǆĞĚĂŶĚƉƵŵƉĞĚ ϭϰϬƐǆƐŽĨdzWϭͬͬϮĐŵƚϮϴďďůƐůƵƌƌǇŵŝǆĞĚĂƚϭϱ͘ϯƉƉŐǁŝƚŚϭ͘ϮϰǇůĚϱ͘ϬϲŐͬƐǆŵŝǆǁĂƚĞƌƉƵŵƉĞĚĐŵƚĂƚϮ͘ϬďƉŵĂƚ ϭϱϱϬƉƐŝ͘ĚŝƐƉůĂĐĞĐŵƚĂƚĂƚϮ͘ϬďƉŵĂƚϭϳϬϬƉƐŝĂƚϲďďůƐŝŶƚŽĚŝƐƉůĂĐĞŵĞŶƚƉƌĞƐƐƵƌĞŝŶĐƌĞĂƐĞĚƐůŽǁĞĚƌĂƚĞƚŽϭ͘ϱďƉŵĂƚ Ϯϯ͘ϵďďůƐƉƵŵƉƐŚƵƚĚŽǁŶƉƵŵƉƉƌĞƐƐƵƌĞďůĞĞĚƚŽϴϬϬƉƐŝ͕ƉƵůůŽƵƚŽĨƌĞƚĂŝŶĞƌƉŝĐŬƵƉϯϬĨƚ͘ĂŶĚƐƋƵĞĞǌĞĚ͘ϱďďůƐŝŶƚŽ ƚŽƉƉĞƌĨƐĂƚϴϯϬƉƐŝ͕ƐŚƵƚĚŽǁŶƉƵŵƉƉƌĞƐƐƵƌĞďůĞĞĚƚŽϱϯϯŝŶϱŵŝŶƵƚĞƐ͘ƉŝĐŬƵƉƚŽϲϮĨƚ͘ĂďŽǀĞƌĞƚĂŝŶĞƌĂŶĚƌĞǀĞƌƐĞ ŽƵƚĂƚϮ͘ϬďƉŵĂƚϰϰϭƉƐŝŐŽƚďĂĐŬŽŶĞďďůŽĨĐŵƚ͕ĐŽŶƚŝŶƵĞ͘ƚŽƌĞǀĞƌƐĞŽƵƚĂƚϰϬďďůƐƌĞǀĞƌƐĞĚŐĞƚƚŝŶŐďĂĐŬϭϬďďůƐŽĨ ďůĂĐŬǁĂƚĞƌΘŐĂƐ͕ŚĂĚƉĂƌƚŝĂůƌĞƚƵƌŶƐĚƵƌŝŶŐĐŵƚũŽďĨŽƌƚŚĞĨŝƌƐƚϭϭďďůƐĚŝƐƉůĂĐĞĚ͕ŚŽůĞƐƚĂǇĞĚĨƵůůĚƵƌŝŶŐũŽď͕ŚĂĚƚŽ ƌĞǀĞƌƐĞŽƵƚĂŶŶƵůƵƐǀŽůƵŵĞŽĨϳϱďďůƐĚƵĞƚŽŐĂƐŝŶƌĞƚƵƌŶƐ͕ƐŚƵƚĚŽǁŶƉƵŵƉŵŽŶŝƚŽƌǁĞůůƐƚĂƚŝĐ͘ZŝŐĚŽǁŶĐŝƌĐƵůĂƚŝŶŐ ŚŽƐĞƐ͘WŽŽŚƌĂĐŬŝŶŐďĂĐŬǁŽƌŬƐƚƌŝŶŐ͘ůĂǇŽƵƚĐŵƚƌĞƚĂŝŶĞƌ͘ΘϱũƚƐϮͲϳͬϴΗǁŽƌŬƐƚƌŝŶŐ͘ ϭϬͬϭϳͬϮϬϮϭͲ^ƵŶĚĂǇ ,ĞůĚW:^DDĂŬĞƵƉŝƚĂŶĚƉŝĐŬƵƉϯͲϭͬϴĚƌŝůůĐŽůůĂƌƐ͕ƚƌŝƉŝŶŚŽůĞǁŝƚŚƉŝƉĞŽƵƚŽĨĚĞƌƌŝĐŬ͕ƚĂŐŐŝŶŐĂƚϰ͕ϵϬϭĨƚ͕ůĂǇŽƵƚ ƐŝŶŐůĞ͘W:^DǁŝƚŚĐƌĞǁĨŽƌƉŝĐŬŝŶŐƵƉƉŽǁĞƌƐǁŝǀĞů͘ƐƉŽƚƐĂŵĞ͘ZŝŐƵƉĂŶĚƚĞƐƚĐŵƚƚŽϭ͕ϱϬϬƉƐŝ;ŐŽŽĚƚĞƐƚͿ͘ZŝŐƵƉƉŽǁĞƌ ƐǁŝǀĞů͕ŝŶƐƚĂůůd/tǀĂůǀĞ͕ƐĞƚƚŽƌƋƵĞƚŽϰŬ͘DĂŬĞƵƉƐŝŶŐůĞ͕ďƌĞĂŬĐŝƌĐƵůĂƚŝŽŶĂƚϭ͘ϱďƉŵϯϬϬƉƐŝǁŝƚŚϲϬƌƉŵǁŝƚŚϭ͕ϳϬϬĨƚ͘ ůďƐ͘ĨƌĞĞƚŽƌƋƵĞ͕ǁŝƚŚϭ͕ϳϬϬƚŽϮ͕ϮϬϬĨƚ͘ůďƐ͘ŽŶďƚŵĚƌŝůůŝŶŐĐŵƚ͘ĨƌŽŵϰ͕ϵϬϭĨƚ͘ƚŽϰ͕ϵϰϲĨƚ͘ĚƌŝůůŝŶŐŽŶ^sĂƚϰ͕ϵϰϲ͕ĐŝƌĐ͘ ŐĂƐĂƚŶĞĞĚĞĚ͘ůŽǁĚŽǁŶƐƵƌĨĂĐĞůŝŶĞƐ͕ƐĞĐƵƌĞǁĞůůĨŽƌŶŝŐŚƚ͘ ϭϬͬϭϴͬϮϬϮϭͲDŽŶĚĂǇ ϭϬͬϭϱͬϮϬϮϭͲ&ƌŝĚĂǇ ,ĞůĚW:^D͕ZŝŐƵƉƚŽƉŝĐŬƵƉǁŽƌŬƐƚƌŝŶŐ͕ƐĞƚƌĂĐŬŝŶŐŵĂƚĂŶĚĐƌŽƐƐďĞĂŵƐ͕ƉŝĐŬƵƉŚĂŶĚůŝŶŐĞƋƵŝƉŵĞŶƚ͕ůĂǇŽƵƚůŝŶĞƌ͕ƐĞƚ ƵƉůĂǇĚŽǁŶŵĂĐŚŝŶĞ͕ůŽĂĚƉŝƉĞŚĂŶĚůĞƌƉŝƉĞƌĂĐŬ͕ŚĞĐŬǁĞůů^/dWΗϬΗ͘DĂŬĞƵƉĐŵƚƌĞƚĂŝŶĞƌƐƚŝŶŐĞƌΘƚƌŝƉŝŶŚŽůĞ ƉŝĐŬŝŶŐƵƉϮͲϳͬϴΗW,ϲǁŽƌŬƐƚƌŝŶŐƚĂŐŐŝŶŐĂƚϰϵϰϲĚƉŵ͕ƐĞƚϭϬŬŽŶƐĂŵĞƉͬƵƉϯϬŬ^ͬŽϮϮŬ͘ZŝŐƵƉƚŽĐŝƌĐƵůĂƚĞ͘ƌĞĂŬ ĐŝƌĐƵůĂƚŝŽŶĂƚϭďƉŵĂƚϯϲϬƉƐŝĐŽŶƚŝŶƵĞƚŽƉƵŵƉĂƚϭďƉŵĨŽƌϮϱŵŝŶƵƚĞƐ͕ŝŶĐƌĞĂƐĞƌĂƚĞƚŽϭ͘ϮϯďƉŵĂƚϱϱϬƉƐŝůĞƚ ƉƌĞƐƐƵƌĞƐƚĂďŝůŝǌĞĂƚϭ͘ϮϯďƉŵƉƌĞƐƐƵƌĞŝŶĐƌĞĂƐĞĚƚŽϵϴϬƉƐŝ͕ƌĞƚƵƌŶƐƐůŽǁŝŶŐ͕ůŝŶĞƵƉĂŶĚƌĞǀĞƌƐĞĐŝƌĐƵůĂƚĞ͘ϱϱďƉŵĂƚ ϭ͕ϬϬϲƉƐŝ͘ĐŽŶƚŝŶƵĞƚŽƌŽĐŬƌĞƚƵƌŶƐĨƌŽŵƌĞǀĞƌƐĞƚŽƉƵŵƉŝŶŐůŽŶŐǁĂǇĂƚƚĞŵƉƚŝŶŐƚŽĞƐƚĂďůŝƐŚĐŝƌĐƵůĂƚŝŶŐƉĂƚŚĂĐƌŽƐƐƚďŐ ƉƵŶĐŚĞƐĨƌŽŵϱ͕ϮϵϱΖΘϰ͕ϵϯϱĨƚ͘&ŝŶĂůĐŝƌĐƵůĂƚŝŽŶƌĂƚĞ͘ϮϴďƉŵ͘ĂƚϰϲϬƉƐŝŚĞůĚƚŚŝƐƌĂƚĞĨŽƌϭŚƌ͘ƚŽƚĂůůŽƐƐĞƐϱϭďďůƐǁŚŝůĞ ĞƐƚĂďůŝƐŚŝŶŐĐŝƌĐƵůĂƚŝŶŐƉĂƚŚ͕ǁŚŝůĞƉƵŵƉŝŶŐĂƚ͘ϮϴďƉŵĂƚϰϲϬŶŽůŽŽƐĞƐ͘^ĞĐƵƌĞǁĞůůĨŽƌŶŝŐŚƚĂŶĚůŽǁĚŽǁŶůŝŶĞƐ͘ ĐŽŶƚŝŶƵĞƚŽƌŽĐŬƌĞƚƵƌŶƐĨƌŽŵƌĞǀĞƌƐĞƚŽƉƵŵƉŝŶŐůŽŶŐǁĂǇĂƚƚĞŵƉƚŝŶŐƚŽĞƐƚĂďůŝƐŚĐŝƌĐƵůĂƚŝŶŐƉĂƚŚĂĐƌŽƐƐƚďŐ ƉƵŶĐŚĞƐĨƌŽŵϱ͕ϮϵϱΖΘϰ͕ϵϯϱĨƚ͘&ŝŶĂůĐŝƌĐƵůĂƚŝŽŶƌĂƚĞ͘ϮϴďƉŵ͘ĂƚϰϲϬƉƐŝŚĞůĚƚŚŝƐƌĂƚĞĨŽƌϭŚƌ ĞŵĞŶƚĞƌƐĂƌƌŝǀĞĚŽŶůŽĐĂƚŝŽŶ Cement retainer set just 4' shallower than planned. -WCB Forward and reverse circulating to ensure good circ through upper punched holes. -WCB ŽŶďƚŵĚƌŝůůŝŶŐ Đŵƚ͘ĨƌŽŵϰ͕ϵϬϭĨƚ͘ƚŽϰ͕ϵϰϲĨƚ͘ ƚƌŝƉŝŶŚŽůĞǁŝƚŚƉŝƉĞŽƵƚŽĨĚĞƌƌŝĐŬ͕ƚĂŐŐŝŶŐĂƚϰ͕ϵϬϭĨƚ ĐŽŶƚŝŶƵĞƚŽĚƌŝůůŽŶŵƚƌĞƚĂŝŶĞƌΘĨŝƌŵĐŵƚĨƌŽŵ ϰ͕ϵϰϲĨƚ͘ƚŽϱ͕ϮϮϮĨƚ͘ Ăƚ Ϯϯ͘ϵďďůƐƉƵŵƉƐŚƵƚĚŽǁŶƉƵŵƉƉƌĞƐƐƵƌĞďůĞĞĚƚŽϴϬϬƉƐŝ͕ƉƵůůŽƵƚŽĨƌĞƚĂŝŶĞƌƉŝĐŬƵƉϯϬĨƚ͘ĂŶĚƐƋƵĞĞǌĞĚ͘ϱďďůƐŝŶƚŽ ƚŽƉƉĞƌĨƐĂƚϴϯϬƉƐŝ ŵŝǆĞĚĂŶĚƉƵŵƉĞĚ ϭϰϬƐǆƐŽĨdzWϭͬͬϮĐŵƚϮϴďďůƐůƵƌƌǇ DĂŬĞƵƉĐŵƚƌĞƚĂŝŶĞƌƐƚŝŶŐĞƌΘƚƌŝƉŝŶŚŽůĞ ƉŝĐŬŝŶŐƵƉϮͲϳͬϴΗW,ϲǁŽƌŬƐƚƌŝŶŐƚĂŐŐŝŶŐĂƚϰϵϰϲĚƉŵ͕ƐĞƚϭϬŬŽŶƐĂŵĞ The cement retainer was above all open perfs. No cement was squeezed into them, only atop the retainer, as planned. -WCB ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϵͬϮϲͬϮϭ ϭϮͬϭϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϮϰͲϯϮ ϱϬͲϭϯϯͲϮϬϲϴϴͲϬϬͲϬϬ ϮϮϬͲϬϯϳ ϭϬͬϮϭͬϮϬϮϭͲdŚƵƌƐĚĂǇ ŽŶƚŝŶƵĞƚŽƌŝŐĚŽǁŶϰϬϭŽĨĨǁĞůů͘^ĐŽƉĞĂŶĚůĂǇĚŽǁŶĚĞƌƌŝĐŬ͕ůŽĂĚŝŶŐŽƵƚƚƌĂŝůĞƌƐŵŽǀĞƌŝŐƚŽƉĂĚϮŝŶ<ĞŶĂŝ'ĂƐĨŝĞůĚ͘ ůĞĂŶŽĨĨŝĐĞƚƌĂŝůĞƌ͕ŽƌŐĂŶŝǌĞĚƉĂƌƚƐƚƌĂŝůĞƌ͘ ϭϬͬϮϮͬϮϬϮϭͲ&ƌŝĚĂǇ <ͲůŝŶĞĐƌĞǁĂƌƌŝǀĞƐĂƚĨĂĐŝůŝƚǇĂŶĚŽďƚĂŝŶƐƉĞƌŵŝƚ͘D/ZhĞͲůŝŶĞĂŶĚƉƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁĂŶĚϮϱϬϬƉƐŝ ŚŝŐŚ͘Z/,ǁŝƚŚϰ͘ϴϬΗŐĂƵŐĞƌŝŶŐĂŶĚũƵŶŬďĂƐŬĞƚƚŽϵϬϬΖĂŶĚůŽƐĞůŝŶĞƚĞŶƐŝŽŶ͘WƵůůƵƉƚŽϮϱϬϬηĂŶĚƚŽŽůƐĂƌĞƐƚƵĐŬ͘ tŽƌŬĞĚƚŽŽůƐĂŶĚŚĂŶĚͲƐƉĂŶŐĞĚĨƌĞĞ͘WKK,͘Z/,ǁŝƚŚĂƐƐĞŵďůǇŝŶĐůƵĚŝŶŐƐƉĂŶŐƐĂŶĚϰ͘ϳϱΗŐĂƵŐĞƌŝŶŐ͘ƌŝĨƚƚŽWdĂƚ ϱϯϬϬΖ͘WKK,͘ĂůůŽƵƚĂĚĚŝƚŝŽŶĂůϭϬΖŽĨƉĂƚĐŚĂƐƐĞŵďůǇ͘ƐƐĞŵďůĞϮϬΖƉĂƚĐŚĂƐƐĞŵďůǇŽŶŐƌŽƵŶĚŝŶůƵďƌŝĐĂƚŽƌĂŶĚƐƚĂďŽŶ ǁĞůů͘Z/,ĂŶĚĐŽƌƌĞůĂƚĞƉĂƚĐŚŽŶĚĞƉƚŚ;ϰϵϯϱͲϰϵϱϱΖͿ͘&ŝƌĞŽĨĨƉĂƚĐŚ͕ƉĂƚĐŚƐĞƚƐŝŶϮŵŝŶƵƚĞƐϱϱƐĞĐŽŶĚƐ͘WKK,͘WKK, ĂŶĚZDKĞͲůŝŶĞ͘WĞƌĨŽƌŵD/dͲdƚŽϭϱϬϬƉƐŝǁŝƚŚĨŝĞůĚƚƌŝƉůĞǆ͘dĞƐƚƉĂƐƐĞĚ͘ ϭϬͬϭϵͬϮϬϮϭͲdƵĞƐĚĂǇ ,ĞůĚW:^D͕ĐŚĞĐŬǁĞůůĨŽƌƉƌĞƐƐƵƌĞΗϬΗ͕ƉƌĞƉƉŽǁĞƌƚŽĐŽŶƚŝŶƵĞĚƌŝůůŝŶŐĐŵƚ͘ƌŝůůŝŶŐĐŵƚĨͬϱ͕ϮϮϮƚŽϱ͕ϯϬϬĨƚ͘ĚƉŵǁŝƚŚϯͲ ϱŬǁŽď͕ĂƚϴϬƌƉŵ͕ǁŝƚŚϮϱϬϬƚŽϯϬϬϬĨƚͬůďƐ͕ƉƵŵƉŝŶŐĂƚϭ͘ϱďƉŵĂƚϮϬϬƉƐŝ͘ŝƌŚŽůĞĐůĞĂŶĂƚϭ͘ϱďƉŵĂƚϮϬϬƉƐŝĂƚƚĞŵƉƚ ƚŽƉƌĞƐƐƵƌĞƚĞƐƚƐƋƵĞĞǌĞƉĞƌĨƐĂƚϰϵϯϱƚŽϰϵϰϬΘϱϮϵϬƚŽϱϮϵϱƚŽϭϱϬϬƉƐŝ͕ďůĞĞĚĚŽǁŶƚŽϮϬϬƉƐŝŝŶϭϯŵŝŶƵƚĞƐ͘>ĂǇŽƵƚ ƐŝŶŐůĞĂŶĚƌŝŐĚŽǁŶƉŽǁĞƌƐǁŝǀĞů͕ůĂǇŽƵƚƐĂŵĞ͘ZŝŐƵƉƚŽůĂǇĚŽǁŶƉŝƉĞ͘WŽŽŚůĂǇŝŶŐĚŽǁŶǁŽƌŬƐƚƌŝŶŐĨͬϱϯϬϬĨƚ͘ƚŽ ,͘ŚĂŶŐĞŽƵƚŚĂŶĚůŝŶŐĞƋƵŝƉŵĞŶƚ͘WƵůůĂŶĚůĂǇŽƵƚ,͘ZŝŐĚŽǁŶŚĂŶĚůŝŶŐĞƋƵŝƉŵĞŶƚ͘ZŝŐƵƉĂŶĚD/dϱͲϭͬϮĐƐŐĂŶĚ ƐƋƵĞĞǌĞƉĞƌĨƐĂƚϰϵϯϱƚŽϰϵϰϬĨƚ͘ΘϱϮϵϬĨƚƚŽϱϮϵϱĨƚ͘ƚŽϭϱϬϬƉƐŝ͕ƉƌĞƐƐƵƌĞďůĞĞĚŽĨĨƚŽϭϮϱƉƐŝŝŶϯϬŵŝŶƵƚĞƐ͘EŝƉƉůĞƵƉ ůƵďƌŝĐĂƚŽƌĨůĂŶŐĞŽŶĂŶŶƵůĂƌ͕ďůŽǁĚŽǁŶƐƵƌĨĂĐĞůŝŶĞƐ͕ƐĞĐƵƌĞǁĞůůĨŽƌŶŝŐŚƚ͘ ϭϬͬϮϬͬϮϬϮϭͲtĞĚŶĞƐĚĂǇ ,ĞůĚW:^D͘ZŝŐƵƉůĂƐŬĂͲůŝŶĞ͘ZŝŐƵƉůƵďƌŝĐĂƚŽƌǁŝƚŚƵŵŵǇƚŽŽů͕ŵĂŬĞƵƉůƵďƌŝĐĂƚŽƌƚĞƐƚƐĂŵĞƚŽϮϱϬΘϯϬϬϬƉƐŝ͕ůĂǇ ŽƵƚĚƵŵŵǇƚŽŽů͘DĂŬĞƵƉ>ƚŽŽůǁŝƚŚdŚĞƌŵŽ^ĞŶƐŽƌ͘ͲůŝŶĞZ/,ǁŝƚŚ>͕ƐĞƚƵƉƚŽŽůŝŶĨƌĞĞƉŝƉĞƌĂŶĨƌĞĞƉŝƉĞƉĂƐƐĨͬ ϭϱϬĨƚ͘ƚŽϯϱϬĨƚ͘ĐŽŶƚŝŶƵĞŝŶŚŽůĞƚĂŐŐŝŶŐďŽƚƚŽŵĂƚϱϯϬϬĨƚ͘>D͘ZĞƉĞĂƚƉĂƐƐƵƉƚŽϰϵϬϬĨƚ͘>D͘Z/,ďĂĐŬŝŶŚŽůĞƚŽ ϱϯϬϬĨƚ͘ůŽŐƵƉƚŽϰϯϬϬĨƚ͘WƵůůƵƉƚŽϰϬϬϬĨƚ͘ƉƵŵƉϭϱďďůƐϴ͘ϰƉƉŐĨůƵŝĚ͕Ăƚ͘ϮϱďƉŵǁŝƚŚϭϲϬϬƉƐŝ͘WƌĞƐƐƵƌĞŝŶĐƌĞĂƐĞĚƚŽ ϭϳϱϬƉƐŝƐůŽǁƌĂƚĞƚŽ͘ϭϰďƉŵƐŚƵƚĚŽǁŶƉƵŵƉĂŶĚZ/,ǁŝƚŚZ>ƚŽŽůĨͬϰϬϬϬĨƚ͘ƚŽϱϮϬϬĨƚ͘^ĂǁƚĞŵƉĞƌĂƚƵƌĞĐŚĂŶŐĞĂƚ ϰϵϰϬĨƚ͘ůĞĞĚŽĨĨƌĞŵĂŝŶŝŶŐƉƌĞƐƐƵƌĞ͕WKK,ǁŝƚŚůŽŐŐŝŶŐƚŽŽůƐ͘ZŝŐĚŽǁŶͲůŝŶĞĂŶĚůŽĂĚŽƵƚƐĂŵĞ͘,ĞůĚW:^DǁŝƚŚ ĐƌĞǁƐŽŶƌŝŐŐŝŶŐĚŽǁŶ͘ZŝŐĚŽǁŶŵƵĚƉƵŵƉĂŶĚƉŝĐŬůĞƐĂŵĞ͕ƌĞŵŽǀŝŶŐďĞƌŵĨƌŽŵĂƌŽƵŶĚƌŝŐ͘ZŝŐĚŽǁŶƌŝŐĨůŽŽƌ͕ůĞĞĚ ĚŽǁŶ<ŽŽŵĞǇĂŶĚƵŶŚŽŽŬůŝŶĞƐ͘ůĞĂŶƉŝƚƐ͕ůŽĂĚŝŶŐƚƌĂŝůĞƌƐ͕ƵŶŚŽŽŬƐƵƌĨĂĐĞŚŽƐĞƐĂŶĚƐĞƚWs͘EͬĚŽǁŶKW͕EŝƉƉůĞ ƵƉϱͲϭͬϴϱŵƚƌĞĞ͕ƚĞƐƚǀŽŝĚƚŽϱϬϬϬƉƐŝ͘ŽŶƚŝŶƵĞƚŽůŽĂĚŽƵƚƚƌĂŝůĞƌƐ͕ƌŝŐŐŝŶŐĚŽǁŶĞůĞĐƚƌŝĐůŝŶĞƐ͕ƉƵƚĂǁĂǇŚŽƐĞƐ͕WŝĐŬůĞ ƚĞƐƚƉƵŵƉƉƵůůWs͘ŽŶƚŝŶƵĞƌŝŐŐŝŶŐĚŽǁŶ͘ <ͲůŝŶĞĐƌĞǁĂƌƌŝǀĞƐ Milled cement just 5' shallower than planned. -WCB MIT passed. Squeezed punches held. -WCB CBL saw TOC between 5-1/2x6-3/4 open hole @4900'. -WCB The rig rigged down. -WCB ƌŝůůŝŶŐĐŵƚĨͬϱ͕ϮϮϮƚŽϱ͕ϯϬϬĨƚ͘ ZŝŐƵƉĂŶĚD/dϱͲϭͬϮĐƐŐĂŶĚ ƐƋƵĞĞǌĞƉĞƌĨƐĂƚϰϵϯϱƚŽϰϵϰϬĨƚ͘ΘϱϮϵϬĨƚƚŽϱϮϵϱĨƚ͘ƚŽϭϱϬϬƉƐŝ͕ƉƌĞƐƐƵƌĞďůĞĞĚŽĨĨƚŽϭϮϱ ƉƐŝŝŶϯϬŵŝŶƵƚĞƐ͘ ZĞƉĞĂƚƉĂƐƐƵƉƚŽϰϵϬϬĨƚ͘>D͘Z/,ďĂĐŬŝŶŚŽůĞƚŽ ϱϯϬϬĨƚ͘ůŽŐƵƉƚŽϰϯϬϬĨƚ͘WƵůůƵƉƚŽϰϬϬϬĨƚ DĂŬĞƵƉ>ƚŽŽůǁŝƚŚdŚĞƌŵŽ^ĞŶƐŽƌ ͲůŝŶĞZ/,ǁŝƚŚ> ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϵͬϮϲͬϮϭ ϭϮͬϭϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϮϰͲϯϮ ϱϬͲϭϯϯͲϮϬϲϴϴͲϬϬͲϬϬ ϮϮϬͲϬϯϳ ϭϬͬϮϲͬϮϬϮϭͲdƵĞƐĚĂǇ &ŽǆŶĞƌŐǇdĐƌĞǁĂƌƌŝǀĞƐĂƚĨĂĐŝůŝƚǇĂŶĚŽďƚĂŝŶƐƉĞƌŵŝƚ͘tĂƌŵƵƉĞƋƵŝƉŵĞŶƚ͘Dh,ŝŶĐůƵĚŝŶŐ&sĂŶĚũĞƚƐǁŝƌů ŶŽǌǌůĞĂŶĚƐƚĂďŽŶǁĞůů͘WƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϰϬϬϬƉƐŝŚŝŐŚ͘KƉĞŶǁĞůůĂŶĚďĞŐŝŶƚŽZ/,͘WƌŽďůĞŵǁŝƚŚ ƌĞĞůŵŽƚŽƌĂůŝŐŶŵĞŶƚ͘ƌŝǀĞĐŚĂŝŶƐůŝƉƉŝŶŐ͘ZĞͲĂůŝŐŶĞĚƌĞĞůŵŽƚŽƌĂŶĚZ/,͘>ŽƐĞǁĞŝŐŚƚĂƚϲϱϬΖ͘ƚƚĞŵƉƚƚŽWKK,ĂŶĚ ƌĞĞůŵŽƚŽƌŝƐŶŽƚĂďůĞƚŽŬĞĞƉƵƉǁŝƚŚŝŶũĞĐƚŽƌ͘dĞƐƚƌĞĞůŵŽƚŽƌŵĂǆƉƌĞƐƐƵƌĞĂŶĚŽŶůǇĂďůĞƚŽĂĐŚŝĞǀĞϭϵϬϬƉƐŝĐŚĂƌŐĞ ƉƌĞƐƐƵƌĞ;ϮϱϬϬƉƐŝŶŽƌŵĂůƉƌĞƐƐƵƌĞͿ͘>ŝŵƉKK,ĂƚϭϬĨƉŵĂŶĚƐĞĐƵƌĞǁĞůů͘ƌĞĂŬŽĨĨ,͕ĐƵƚƉŝƉĞĂŶĚŝŶƐƚĂůůŶĞǁƌŽůůͲ ŽŶĐŽŶŶĞĐƚŽƌ͘WĞƌĨŽƌŵƉƵůůƚĞƐƚƚŽϭϱŬ͘WƵƌŐĞůŽĂĚĐĞůůŚǇĚƌĂƵůŝĐůŝŶĞƐ͘'ƌĞĂƚEŽƌƚŚĞƌŶ,ǇĚƌĂƵůŝĐƐĂƌƌŝǀĞƐŽŶůŽĐĂƚŝŽŶ͘ dƌŽƵďůĞƐŚŽŽƚƌĞĞůŵŽƚŽƌĂŶĚĨŝŶĚďĂĚŚǇĚƌĂƵůŝĐĂĐƚƵĂƚŽƌ͕ƌĞƉĂŝƌƐĂŵĞ͘/ƐŽůĂƚĞŝŶũĞĐƚŽƌďƌĂŬĞĂŶĚĚĞƚĞƌŵŝŶĞƚŚĂƚďƌĂŬĞ ĐŽŶƚƌŽůďƵƚƚŽŶŝŶŽƉƐĐĂďŝƐŶŽƚĨƵŶĐƚŝŽŶŝŶŐ͘^ĞŶĚ'ƌĞĂƚEŽƌƚŚĞƌŶŚĂŶĚƚŽƐŚŽƉĨŽƌƚŚƌĞĞͲǁĂǇǀĂůǀĞ͘dĞƐƚƌĞĞůŵŽƚŽƌͲ ŐŽŽĚdĞƐƚ͘>ĂǇĚŽǁŶůƵďƌŝĐĂƚŽƌĂŶĚŝŶũĞĐƚŽƌ͘'ƌĞĂƚEŽƌƚŚĞƌŶƌĞƚƵƌŶƐƚŽůŽĐĂƚŝŽŶǁŝƚŚƚŚƌĞĞͲǁĂǇŚǇĚƌĂƵůŝĐǀĂůǀĞ͘/ŶƐƚĂůů ǀĂůǀĞŝŶŝŶũĞĐƚŽƌďƌĂŬĞŚǇĚƌĂƵůŝĐĐŝƌĐƵŝƚ͘dĞƐƚŝŶũĞĐƚŽƌďƌĂŬĞͲŐŽŽĚƚĞƐƚ͘^&E͘ ϭϬͬϮϰͬϮϬϮϭͲ^ƵŶĚĂǇ ŽŶĚƵĐƚ:^ĂŶĚĂƉƉƌŽǀĞWdtĨŽƌ&ŽǆŶĞƌŐǇŽŝůĞĚdƵďŝŶŐ͘^ƉŽƚĞƋƵŝƉŵĞŶƚ͘D/Zh͘&ƵŶĐƚŝŽŶƚĞƐƚKWƌĂŵƐ͘;ƵĂů ŽŵďŝƌĂŵƐͿEhKWƐŽŶƚƌĞĞ͘ZhŚĂƌĚůŝŶĞĨƌŽŵĨůŽǁĐƌŽƐƐƚŽĐŚŽŬĞƐŬŝĚĂŶĚŽƵƚƚŽƌĞƚƵƌŶƚĂŶŬ͘Dhd͕ĚƵĂůĐŚĞĐŬ ǀĂůǀĞƐĂŶĚϮ͘ϬϴΗŶŽǌǌůĞ͘DhŝŶũĞĐƚŽƌŽŶƚŽƉŽĨKWƐ͘tĂŝƚŽŶǁĂƚĞƌƚŽƵƐĞĨŽƌƉƌĞƐƐƵƌĞƚĞƐƚŝŶŐKWΖƐŝŶƐƚĞĂĚŽĨƵƐŝŶŐ ϲϬͬϰϬƉĞƌK'ƌĞƉ͘KWdĞƐƚǁŝƚŶĞƐƐĞĚďǇ:ĞĨĨ:ŽŶĞƐ͘ůŽƐĞďůŝŶĚͬƐŚĞĂƌƌĂŵĂŶĚWdƚŽϮϱϬƉƐŝůŽǁ͘'ŽĨŽƌŚŝŐŚƚĞƐƚ ĂŶĚĨůĂŶŐĞůĞĂŬĂƚKWΖƐ͘dŝŐŚƚĞŶĨůĂŶŐĞĂŶĚĂŶĚĐŽŶƚŝŶƵĞ͘^ƚĂƌƚƚĞƐƚĂŐĂŝŶƐƚďůŝŶĚͬƐŚĞĂƌ͘WdůŽǁϮϱϬƉƐŝĂŶĚŚŝŐŚWdϰϬϬϬ ƉƐŝ͘ZĞĐŽƌĚĞĚƉƌĞƐƐƵƌĞƐŝŶĐŽŝůƵŶŝƚƐŽĨƚǁĂƌĞĂŶĚŶŽƚŵĂƚĐŚŝŶŐƉƌĞƐƐƵƌĞƐŽŶŵĞĐŚĂŶŝĐĂůŐĂƵŐĞƐ͘dƌŽƵďůĞƐŚŽŽƚƉƌĞƐƐƵƌĞ ƌĞĂĚŝŶŐĚŝƐĐƌĞƉĂŶĐŝĞƐ͘tŝůůŚĂǀĞ,ŝůĐŽƌƉĐĂůŝďƌĂƚĞĚƚĞƐƚŐĂƵŐĞĂǀĂŝůĂďůĞŝŶƚŚĞŵŽƌŶŝŶŐƚŽƵƐĞĨŽƌĐĂůŝďƌĂƚŝŶŐĐŽŝůƉƌĞƐƐƵƌĞ ƌĞĐŽƌĚŝŶŐƐŽĨƚǁĂƌĞ͘>&E͘ ϭϬͬϮϱͬϮϬϮϭͲDŽŶĚĂǇ &ŽǆŶĞƌŐǇdĐƌĞǁĂƌƌŝǀĞƐĂƚĨĂĐŝůŝƚǇĂŶĚŽďƚĂŝŶƐƉĞƌŵŝƚ͘tĂƌŵƵƉĞƋƵŝƉŵĞŶƚ͕ƉŝĐŬƵƉŝŶũĞĐƚŽƌĂŶĚƐƉŽƚŝŶƉƌĞƉĂƌĂƚŝŽŶ ĨŽƌƉƌĞƐƐƵƌĞƚĞƐƚ͘ZŝŐƵƉŚŽƚŽŝůĞƌĂŶĚƚŽƉǁĞůůŽĨĨǁŝƚŚǁĂƚĞƌ͘^ƚĂďŝŶũĞĐƚŽƌ͘,ŽŽŬƵƉĐƌǇƐƚĂůƚĞƐƚŐĂƵŐĞĂŶĚĞŶƐƵƌĞƚŚĂƚ ƉƵŵƉƚƌƵĐŬ͕dhĂŶĚĐƌǇƐƚĂůŐĂƵŐĞƐĂƌĞƌĞĂĚŝŶŐƚŚĞƐĂŵĞƉƌĞƐƐƵƌĞ͘WƌĞƐƐƵƌĞƚĞƐƚůŝŶĞƐƚŽϮϱϬƉƐŝůŽǁͬϰϬϬϬƉƐŝŚŝŐŚ͘ EŽƚŝĨǇK'ĂŶĚŝŶƐƉĞĐƚŽƌ;:ĞĨĨ:ŽŶĞƐͿĂƌƌŝǀĞƐŽŶůŽĐĂƚŝŽŶ͘WĞƌĨŽƌŵďŽĚǇĂŶĚŽƵƚĞƌĐŚŽŬĞŵĂŶŝĨŽůĚƚĞƐƚƚŽϮϱϬƉƐŝůŽǁͬ ϰϬϬϬƉƐŝŚŝŐŚͲŐŽŽĚƚĞƐƚ͘WĞƌĨŽƌŵďůŝŶĚƐŚĞĂƌĂŶĚŝŶŶĞƌĐŚŽŬĞŵĂŶŝĨŽůĚǀĂůǀĞƐƚŽϮϱϬƉƐŝůŽǁͬϰϬϬϬƉƐŝͲŐŽŽĚƚĞƐƚ͘&ŝůů dǁŝƚŚǁĂƚĞƌƚŽƚĞƐƚŝŶŶĞƌƌĞĞůǀĂůǀĞ͘WĞƌĨŽƌŵƉŝƉĞƐůŝƉĂŶĚŽƵƚĞƌĨůŽǁĐƌŽƐƐǀĂůǀĞƐƚĞƐƚƚŽϮϱϬƉƐŝůŽǁͬϰϬϬϬƉƐŝŚŝŐŚͲ ŐŽŽĚƚĞƐƚ͘WĞƌĨŽƌŵŝŶŶĞƌĨůŽǁĐƌŽƐƐǀĂůǀĞƐƚĞƐƚƚŽϮϱϬƉƐŝůŽǁͬϰϬϬϬƉƐŝŚŝŐŚͲŐŽŽĚƚĞƐƚ͕ďůĞĞĚĚŽǁŶŚŽƚŽŝůĞƌƚŽƚĞƐƚ ŝŶŶĞƌƌĞĞůǀĂůǀĞͲŐŽŽĚƚĞƐƚ͘KWƚĞƐƚĐŽŵƉůĞƚĞ͕ŶŽĨĂŝůƵƌĞƐ͘ZDKŚŽƚŽŝůĞƌĂŶĚďůŽǁĚŽǁŶĐŽŝůƌĞĞůǁŝƚŚEϮ͘>ĂǇĚŽǁŶ ŝŶũĞĐƚŽƌĂŶĚĐƌĂŶĞ͘^&E͘ dĐƌĞǁĂƌƌŝǀĞƐĂƚĨĂĐŝůŝƚǇĂŶĚŽďƚĂŝŶƐƉĞƌŵŝƚ͘tĂƌŵƵƉĞƋƵŝƉŵĞŶƚ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϵͬϮϲͬϮϭ ϭϮͬϭϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϮϰͲϯϮ ϱϬͲϭϯϯͲϮϬϲϴϴͲϬϬͲϬϬ ϮϮϬͲϬϯϳ ϭϭͬϬϭͬϮϬϮϭͲDŽŶĚĂǇ ^ŝŐŶŝŶ͘DŽďĞƚŽůŽĐĂƚŝŽŶ͘Wdtͬ:^ͬdĂŝůŐĂƚĞ͘^ƉŽƚĞƋƵŝƉŵĞŶƚĂŶĚƌŝŐƵƉůƵďƌŝĐĂƚŽƌ͘WdƚŽϮϱϬƉƐŝůŽǁĂŶĚϮ͕ϱϬϬƉƐŝŚŝŐŚ͘ Z/,ǁͬ'WdƚŽŽůĂŶĚƚŝĞŝŶƚŽZ>͕ĨŝŶĚ&>Ăƚϰ͕ϮϯϬΖ͕ŚĂĚƚƌŽƵďůĞŐĞƚƚŝŶŐƚŚƌƵƚŽƉŽĨƉĂƚĐŚĂƚϰ͕ϵϯϱΖ;dŚŝŶŬŝŶŐƐĞƚƚŝŶŐĚŽǁŶ ŽŶƐŚŽƵůĚĞƌŽĨƉĂƚĐŚͿĂŶĚƚĂŐŽďƐƚƌƵĐƚŝŽŶĂƚϱ͕ϮϱϴΖ͘WKK,ƵƉƉĂƐƚƚŽƉŽĨƉĂƚĐŚ͘dƌŝĞĚƚŽŐŽƚŚƌƵĂŶĚƐƚŝůůŚĂĚƚƌŽƵďůĞďƵƚ ǁĞŶƚƚŚƌƵ͘^ĞŶĚůŽŐƐƚŽƚŽǁŶ͘WKK,͘Z/,ǁͬϮͲϳͬϴΗǆϮϱΖ,͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽZ>͘ŝĚŶΖƚŚĂǀĞĂŶǇ ƚƌŽƵďůĞŐĞƚƚŝŶŐƚŚƌƵƉĂƚĐŚ͘'ƵŶƐĞƚĚŽǁŶĂƚϱ͕ϮϱϴΖ͘WhϱϬΖ͕ŐŽďĂĐŬĚŽǁŶƌĞŐƵůĂƌƐƉĞĞĚĂŶĚŐƵŶƐůŽǁĞĚĚŽǁŶĂƚϱ͕ϮϱϴΖ ďƵƚǁĞŶƚĚŽǁŶƚŽϱ͕ϮϲϰΖ͘ŝĚƚŚĞƐĂŵĞƚŚŝŶŐĂŶĚŐƵŶƐƚŽƉƉĞĚŝŶƐƚĂŐĞƐĨƌŽŵϱ͕ϮϲϴΖ͕ϱ͕ϮϴϵΖĂŶĚϱ͕ϮϵϱΖ͘'ƵŶǁŽƵůĚũƵƐƚ ƐůŽǁĚŽǁŶĂƚĞĂĐŚƐƚĂŐĞŝƚƐƚŽƉƉĞĚĂƚďĞĨŽƌĞ͘WKK,͘ŝƐͲĂƌŵŐƵŶ͘ĂůůĨŽƌϯΖďĂŝůĞƌƚŽĐŽŵĞŽƵƚ͘tKďĂŝůĞƌ͘DhĂŝĞƌ ĂŶĚĨŝůůǁŝƚŚĐĞŵĞŶƚ͘Z/,ǁͬϯΗǆϯϬΖĞŵĞŶƚĚƵŵƉďĂŝůĞƌĨŝůůĞĚǁͬϭϲƉƉŐĐĞŵĞŶƚ;ϭϬŐĂůƐсϭϬΖͿĂŶĚƚŝĞŝŶƚŽZ>͘ĂŝůĞƌ ƐĞƚĚŽǁŶĂƚϱ͕ϮϵϬΖ͘WŝĐŬƵƉϭϬΖĂŶĚĚƵŵƉĐĞŵĞŶƚ͘tŽƌŬďĂŝůĞƌƚŽŝŶƐƵƌĞĐĞŵĞŶƚ͘>ŽƐƚϳϬƚŽϭϬϬůďƐ͘,ĂĚƚƌŽƵďůĞŐŽŝŶŐ ƚŚƌƵƉĂƚĐŚĂƚϰ͕ϵϯϱΖĂŶĚĐŽŵŝŶŐďĂĐŬƚŚƌƵĂƚϰ͕ϵϱϱΖ͘WKK,͘'ŽŽĚĚƵŵƉ͘;ƐƚdKϱ͕ϮϴϬΖ͕/WϭϱϬϬŚƌƐͿ͘Z/,ǁͬϯΗǆϯϬΖ ĞŵĞŶƚĚƵŵƉďĂŝůĞƌĨŝůůĞĚǁͬϭϲƉƉŐĐĞŵĞŶƚ͘,ĂĚƚƌŽƵďůĞŐĞƚƚŝŶŐƚŚƌƵƉĂƚĐŚ͘Z/,ĚŽǁŶƚŽϱ͕ϮϳϬΖ͘ƵŵƉĐĞŵĞŶƚϭϬ ŐĂůƐͬϭϬΖŽĨĐĞŵĞŶƚ͘>ŽƐƚϳϬůďǁƚ͘,ĂĚĂůŝƚƚůĞďŝƚŽĨƚƌŽƵďůĞŐĞƚƚŝŶŐďĂĐŬƚŚƌƵƉĂƚĐŚ͘KƵƚŽĨŚŽůĞ͘'ŽŽĚĚƵŵƉ͘ƐƚdK ϱ͕ϮϳϬΖͬ/WϭϲϮϬŚƌƐ͘Z/,ǁͬϯΗǆϮϬΖĞŵĞŶƚĚƵŵƉďĂŝůĞƌĨŝůůĞĚǁͬϱŐĂůŽĨϭϲƉƉŐĐĞŵĞŶƚ͘^ĞƚĚŽǁŶŽŶĐĞĂŶĚƚŚĞŶǁĞŶƚ ƚŚƌƵƉĂƚĐŚĚŽǁŶƚŽϱ͕ϮϲϱΖ͘ƵŵƉďĂŝůϱŐĂůͬϱΖŽĨĐĞŵĞŶƚ͘^ƚŝůůŚĂĚĂůŝƚƚůĞƚƌŽƵďůĞďĂĐŬƵƉƚŚƌƵƉĂƚĐŚďƵƚϮϬΖǁĂƐĂůŽƚ ĞĂƐŝĞƌƚŽŐĞƚƚŚƌƵ͘WKK,͘'ŽŽĚƵŵƉ͘/WĂƚϭϳϭϬŚƌƐ͘ĞƐƚdKϱ͕ϮϲϱΖ;dŽƚĂůŽĨϮϱŐĂůͬϮϱΖͿ͘ZŝŐĚŽǁŶ>ƵďƌŝĐĂƚŽƌ͘^ĞĐƵƌĞ ǁĞůů͘ĞďĂĐŬŝŶĂŵƚŽƚĂŐĂŶĚƉĞƌĨ͘ ϭϬͬϮϵͬϮϬϮϭͲ&ƌŝĚĂǇ WƌĞǀŝŽƵƐĚĂǇŽŶϭϬͬϮϴͬϮϬϮϭ&ŽǆŶĞƌŐǇƚƌŽƵďůĞƐŚŽƚƚŚĞƌĞĞůĐŝƌĐƵŝƚĂŶĚŝŶũĞĐƚŽƌŚĞĂĚďƌĂŬĞĐŝƌĐƵŝƚ͘ZĞƉůĂĐĞĚWŝůŽƚǀĂůǀĞ ŝŶŽƉƐĐĂďĂŶĚŝŶƐƚĂůůĞĚŶĞǁ/ŶũĞĐƚŽƌďƌĂŬĞŽŶďĂĐŬƐŝĚĞŝŶũĞĐƚŽƌŵŽƚŽƌ͘&ƵŶĐƚŝŽŶƚĞƐƚĞĚĐŝƌĐƵŝƚƐ͘Wdt͕:^ǁŝƚŚĐƌĞǁ͘ WŝĐŬŝŶũĞĐƚŽƌŚĞĂĚ͘^ƚĂďϭϬΖůƵďƌŝĐĂƚŽƌ͘^ƉŽƚŝŶ͕ƌŝŐƵƉ,<ŚŽƚŽŝůƚƌƵĐŬ͘DĂŬĞƵƉ,͘ϭ͘ϳϱΗĐŽůĚƌŽůů͕Ϯ͘ϭϮϱΗ&s͕ Ϯ͘ϭϮϱΗƐƚŝŶŐĞƌ͕Ϯ͘ϭϮϱΗĚŽǁŶũĞƚŶŽǌǌůĞ͘^ƚĂďŽŶǁĞůů͘&ůƵŝĚƉĂĐŬƚŽƌĞƚƵƌŶƚĂŶŬǁŝƚŚϲϬͬϰϬŵĞƚŚĂŶŽůǁĂƚĞƌŵŝǆ͘ůŽƐĞ ĐŚŽŬĞĂŶĚWdƐƚĂĐŬϮϱϬͬϯ͕ϱϬϬƉƐŝ͘ŽŶĨŝƌŵŶŽůĞĂŬƐ͘KƉĞŶǁĞůůĂŶĚZ/,͘KƉƐŝ͘WĞƌĨŽƌŵǁĞŝŐŚƚĐŚĞĐŬƐĂŶĚĐŽŶĨŝƌŵ ŚǇĚƌĂƵůŝĐĐĂůĐƵůĂƚŝŽŶƐĂŶĚŐĞĂƌƌĂƚŝŽƐŵĂƚĐŚǁĞŝŐŚƚĐĞůů͘^ƚĂƌƚĐŽŽůŝŶŐĚŽǁŶEϮůŝŶĞƐ͘EϮƉƵŵƉĂŝƌůŝŶĞƐĨŽƌĂŝƌĂĐƚƵĂƚĞĚ ǀĂůǀĞƐŚĂǀĞŝĐĞƉůƵŐ͘dĂŬĞŽĨĨĂŝƌĂĐƚƵĂƚŽƌĂŶĚŽƉĞŶŵĂŶƵĂůůǇ͘EϮĐŽŽůĞĚĚŽǁŶ͘dZ/,Ăƚϯ͕ϲϰϴΖdD͘KŶůŝŶĞĚŽǁŶd ǁŝƚŚEϮƌĂƚĞŽĨϭ͕ϬϬϬƐĐĨͬŵŝŶ͘ŽŝůƵŶŝƚĐŽƵŶƚĞƌŚĂƐďĞĞŶƉĞƌŝŽĚŝĐĂůůǇƐůŝƉƉŝŶŐǁŚŝůĞZ/,͘dŚĞŽŶůǇĐŽƵŶƚĞƌŝƐŽŶdhƌĞĞů͘ EŽĞůĞĐƚƌŽŶŝĐĐŽƵŶƚĞƌďĞůŽǁĐŚĂŝŶƐŽŶŝŶũĞĐƚŽƌŚĞĂĚ͘dĂŐŐĞĚϰ͕ϴϳϵΖdD͘WŝĐŬĞĚƵƉĂŶĚƚĂŐŐĞĚŚĂƌĚϰŵŽƌĞƚŝŵĞƐĂƚ ĚĞƉƚŚ͘>ŽŽŬƐůŝŬĞWd͘WŝĐŬƵƉŽĨĨďŽƚƚŽŵϮΖĂŶĚďůŽǁǁĞůůĚƌǇ͘Ϯ͕ϰϴϬƉƐŝŵĂǆƉƌĞƐƐƵƌĞďĞĨŽƌĞďƌĞĂŬŽǀĞƌ͘ϭϮϱďďůƐ ƌĞƚƵƌŶĞĚĨƌŽŵǁĞůů͘ZĞƚƵƌŶƐĂƌĞŵŽƐƚůǇEϮǁŝƚŚůŝŐŚƚŵŝƐƚ͘^ƚĂƌƚWKK,ĂŶĚƌĞĚƵĐĞEϮƌĂƚĞĨƌŽŵϭ͕ϬϬϬƐĐĨͬŵŝŶƚŽϴϬϬ ƐĐĨͬŵŝŶ͘ϰ͕ϱϬϬΖdD͕ĂůůEϮĂƚƌĞƚƵƌŶƚĂŶŬ͘ŽǁŶŽŶEϮ͘ŽŶƚŝŶƵĞƚŽƐƵƌĨĂĐĞ͘^ůŽǁůǇǁŽƌŬĐŽŝůƵƉĨŽƌƚĂŐĚƵĞƚŽĚĞƉƚŚ ĚŝƐĐƌĞƉĂŶĐŝĞƐ͘dĂŐŐĞĚƵƉǁŝƚŚĐŽƵŶƚĞƌƌĞĂĚŝŶŐͲϮϬϬΖ͘t,WϬƉƐŝ͘EŽEϮƉƌĞƐƐƵƌĞƌĞƋƵŝƌĞĚŽŶǁĞůůĨŽƌƉůĂŶŶĞĚƉĞƌĨ ŝŶƚĞƌǀĂůƐ͘ůŽƐĞŵĂƐƚĞƌĂŶĚƐǁĂďϮϯ͘ϱƚƵƌŶƐ͘WŽƉŽĨĨǁĞůůĂŶĚďƌĞĂŬĚŽǁŶ,͘>ĂǇĚŽǁŶůƵďƌŝĐĂƚŽƌĂŶĚŝŶũĞĐƚŽƌŚĞĂĚ͘ ŽŶƚŝŶƵĞƚŽƌŝŐĚŽǁŶĂŶĚĚĞͲŵŽďĞ&ŽǆĞŶĞƌŐǇĞƋƵŝƉŵĞŶƚ͘ϭϮϱďďůƐƌĞƚƵƌŶĞĚĨƌŽŵǁĞůů͘ϭϭϬ͕ϬϬϲƐĐĨƉƵŵƉĞĚ;ϭ͕ϮϬϬ ŐĂůůŽŶƐͿ͘dhƌŝŐŐĞĚĚŽǁŶ͘>ŽĐĂƚŝŽŶǁĂůŬĂƌŽƵŶĚĐŽŵƉůĞƚĞ͘ůŽƐĞŽƵƚĂŶĚƚƵƌŶŝŶWdt͘WƌŽĚƵĐƚŝŽŶǁŝůůŝŶƐƚĂůůƐƵƌĨĂĐĞ ĨůŽǁůŝŶĞƐĂŶĚ^ĂĐƋƵŝƐŝƚŝŽŶŐĂƵŐĞƐŽǀĞƌƚŚĞǁĞĞŬĞŶĚ͘ ĂŝůĞƌ ƐĞƚĚŽǁŶĂƚϱ͕ϮϵϬΖ͘WŝĐŬƵƉϭϬΖĂŶĚĚƵŵƉĐĞŵĞŶƚ͘ Z/,ǁͬϯΗǆϯϬΖ ĞŵĞŶƚĚƵŵƉďĂŝůĞƌĨŝůůĞĚǁͬϭϲƉƉŐĐĞŵĞŶƚ͘,ĂĚƚƌŽƵďůĞŐĞƚƚŝŶŐ ƚŚƌƵƉĂƚĐŚ͘Z/,ĚŽǁŶƚŽϱ͕ϮϳϬΖ͘ƵŵƉĐĞŵĞŶƚϭϬ ŐĂůƐͬϭϬΖŽĨĐĞŵĞŶƚ͘>ŽƐƚϳϬůďǁƚ͘,ĂĚĂůŝƚƚůĞďŝƚŽĨƚƌŽƵďůĞŐĞƚƚŝŶŐďĂĐŬƚŚƌƵƉĂƚĐŚ͘KƵƚŽĨŚŽůĞ͘'ŽŽĚĚƵŵƉ͘ƐƚdK ϱ͕ϮϳϬΖͬZ/,ǁͬϯΗǆϮϬΖĞŵĞŶƚĚƵŵƉďĂŝůĞƌĨŝůůĞĚǁͬϱŐĂůŽĨϭϲƉƉŐĐĞŵĞŶƚ͘^ĞƚĚŽǁŶŽŶĐĞĂŶĚƚŚĞŶǁĞŶƚ ƚŚƌƵƉĂƚĐŚĚŽǁŶƚŽϱ͕ϮϲϱΖ͘ƵŵƉďĂŝůϱŐĂůͬϱΖŽĨĐĞŵĞŶƚ͘^ƚŝůů ŚĂĚĂůŝƚƚůĞƚƌŽƵďůĞďĂĐŬƵƉƚŚƌƵƉĂƚĐŚďƵƚϮϬΖǁĂƐĂůŽƚ ĞĂƐŝĞƌƚŽŐĞƚƚŚƌƵ͘WKK,͘'ŽŽĚƵŵƉ͘/WĂƚϭϳϭϬŚƌƐ͘ĞƐƚdKϱ͕ϮϲϱΖ;dŽƚĂůŽĨϮϱŐĂůͬϮϱΖͿ͘ So 25' + initial 5' of cement atop CIBP. -WCB dĂŐŐĞĚϰ͕ϴϳϵΖdD͘WŝĐŬĞĚƵƉĂŶĚƚĂŐŐĞĚŚĂƌĚϰŵŽƌĞƚŝŵĞƐĂƚ ĚĞƉƚŚ͘>ŽŽŬƐůŝŬĞWd͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϵͬϮϲͬϮϭ ϭϮͬϭϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϮϰͲϯϮ ϱϬͲϭϯϯͲϮϬϲϴϴͲϬϬͲϬϬ ϮϮϬͲϬϯϳ ϭϭͬϬϮͬϮϬϮϭͲdƵĞƐĚĂǇ zĞůůŽǁũĂĐŬĞƚƐŝŐŶŝŶ͕WdtĂŶĚ:^͘ZŝŐƵƉůƵďƌŝĐĂƚŽƌ͘WdƚŽϮϱϬƉƐŝůŽǁĂŶĚϮ͕ϱϬϬƉƐŝŚŝŐŚ͘dWͲϬƉƐŝ͘ ĞŵĞŶƚƐĂŵƉůĞƐŚĂǀĞƐĞƚƵƉŐŽŽĚ͘Z/,ǁͬ'ƵŶηϭ͕ϮͲϳͬϴΗǆϮϱΖ,͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽZ>͘dĂŐŐĞĚdKĂƚ ϱ͕ϮϲϱΖ͘ZƵŶŽƌƌĞůĂƚŝŽŶĂŶĚƐĞŶĚƚŽƚŽǁŶ͘dŽůĚƚŽĂĚĚϭΖĂŶĚƉĞƌĨ;dKƚĂŐŝƐĂĨƚĞƌĂĚũƵƐƚŵĞŶƚͿ͘^ƉŽƚĂŶĚĨŝƌĞŐƵŶĨƌŽŵ ϱ͕ϮϮϵΖƚŽϱ͕ϮϱϰΖ͘>ŽƐƚϴϬϬůďŽĨůŝŶĞƚĞŶƐŝŽŶǁŚĞŶĨŝƌĞĚ͘'ŽƚŝƚďĂĐŬŝŶĂĨƚĞƌƉŝĐŬŝŶŐƵƉϭϬΖ͘KƉƐŝďĞĨŽƌĞĂŶĚĂĨƚĞƌƐŚŽƚ͘ WKK,ͬůůƐŚŽƚƐĨŝƌĞĚͬŐƵŶǁĞƚ͘Z/,ǁͬ'ƵŶηϮ͕ϮͲϳͬϴΗǆϮϰΖ,͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽZ>͘'ŽŝŶŐŝŶŚŽůĞǁĞƐĞƚ ĚŽǁŶϱ͕ϭϴϰΖ͕WŝĐŬƵƉ͕ŐŽďĂĐŬĚŽǁŶƚŽϱ͕ϭϴϬΖ͘ĂůůƚŽǁŶĂŶĚĚŝƐĐƵƐƐĞĚ͘dŚĞǇƐĂŝĚƚŽƉĞƌĨŶĞǆƚǌŽŶĞƵƉǁͬϮϰΖŐƵŶǁĞ ŚĂǀĞŝŶŚŽůĞ͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘dŽůĚƚŽĂĚĚϭΖĂŶĚƉĞƌĨĨƌŽŵϱ͕ϭϰϭΖƚŽϱ͕ϭϲϱΖ͘^ƉŽƚƚĞĚĂŶĚĨŝƌĞĚŐƵŶ͘ >ŽƐƚϯϬϬůďůŝŶĞƚĞŶƐŝŽŶ͘ŝĚŶΖƚƐĞĞĂŶǇƉƌĞƐƐƵƌĞŐĂŝŶ͘WKK,͘ůůƐŚŽƚƐ&ŝƌĞĚͬŐƵŶǁĞƚ͘ZŝŐĚŽǁŶůƵďƌŝĐĂƚŽƌĂŶĚƐĞĐƵƌĞ ǁĞůů͘ZŝŐz:ĐŽŵƉůĞƚĞůǇĚŽǁŶĂŶĚƐĞŶĚŚŽŵĞ͘:ƵƐƚƐǁĂďŝƐĐůŽƐĞĚ͘ ƵůůƉůƵŐǁĂƐĨƵůůŽĨƐĂŶĚŽŶďŽƚŚŐƵŶƐ͘^ƉĞŶƚŐƵŶƐĚŝĚŶΖƚŚĂǀĞŵƵĐŚŝŶƚŚĞŵ͘ ϭϮͬϭϬͬϮϭͲ&ƌŝĚĂǇ ^ŝŐŶŝŶ͘WdtĂŶĚ:^͘z:ŵŽďĞƚŽůŽĐĂƚŝŽŶ͘ZŝŐƵƉĞƋƵŝƉĂŶĚůƵďƌŝĐĂƚŽƌ͘WdƚŽϮϱϬƉƐŝůŽǁĂŶĚϮϱϬϬƉƐŝŚŝŐŚ͘dWͲϭϲϱϬƉƐŝ͘ Z/,ǁͬϯͲϭͬϮΗǆϯϬΖĨŝůůĞĚǁŝƚŚϭϲ͘ϰƉƉŐĂŶĚƚĂŐĨŝůůϱϭϯϰΖ͘ƵŵƉĐĞŵĞŶƚ;ϭϰΖ;ϭϯŐĂůƐͿŽĨĐĞŵĞŶƚŽŶŽďƐƚƌƵĐƚŝŽŶĂƚ ϱϭϯϰΖ͘>ŽƐƚϭϬϬůďƐŽĨůŝŶĞǁƚĂĨƚĞƌĚƵŵƉ͘WKK,͘ĂŝůĞƌůŽŽŬŐŽŽĚĂŶĚǁĂƐĞŵƉƚǇ͘'ŽŽĚĚƵŵƉ͘ĞŵĞŶƚŝŶƉůĂĐĞĂƚϭϭϬϬ ŚƌƐ͘ƵŵƉďĂŝůĐĞŵĞŶƚĨƌŽŵϱϭϯϰΖƚŽϱϭϮϬΖ͘dKͲϱϭϮϬΖ͘ZŝŐĚŽǁŶĞƋƵŝƉŵĞŶƚƐĞĐƵƌĞǁĞůů͕tKĂŶĚĐŽŵĞďĂĐŬ ƚŽŵŽƌƌŽǁƚŽƉĞƌĨ͘ ϭϮͬϬϵͬϮϬϮϭͲdŚƵƌƐĚĂǇ ^ŝŐŶŝŶĂŶĚ:^͘DŽďĞƚŽůŽĐĂƚŝŽŶ͘ƋƵŝƉĂůƌĞĂĚǇƚŚĞƌĞ͘ZŝŐƵƉůƵďƌŝĐĂƚŽƌĂŶĚǁĂŝƚŽŶƚƌŝͲƉůĞǆƉƵŵƉ͘WdƚŽϮϱϬƉƐŝůŽǁĂŶĚ ϮϱϬϬƉƐŝŚŝŐŚ͘dWͲϭϲϱϬƉƐŝ͘Z/,ǁͬ'Wd͕ƚŝĞĚŝŶƚŽK,>ĂŶĚƚĂŐŐĞĚĂƚϱϭϰϬΖ͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘dŽůĚƚŽ ƐƵďƚƌĂĐƚϲΖ͘^ƵďƚƌĂĐƚϲΖ͕ŵĂĚĞƚĂŐĚĞƉƚŚϱϭϯϰΖ͕&>ͲϰϭϱϰΖ͘ZĞƐĞŶĚĐŽƌƌĞĐƚĞĚůŽŐĂŶĚŐŽƚŽŬƚŽĚƵŵƉĐĞŵĞŶƚĂŶĚƵƐĞůŽŐ ĂƐƚŝĞŝŶůŽŐĨŽƌƉĞƌĨ͘WKK,͘ĂůůĞĚƚŽǁŶĂŶĚĚŝƐĐƵƐƐĞĚǁĞůůĐŽŶĚŝƚŝŽŶƐĂŶĚǁŝŶĚŐƵƐƚŝŶŐƚŽϰϬŵƉŚďĞĨŽƌĞǁĞŐŽƚŽĨĨ ǁĞůů͘tĂŝƚŝŶŐĨŽƌǁŝŶĚƚŽĚŝĞĚŽǁŶƐŽŵĞƚŽŐĞƚŽĨĨǁĞůů͘ŝƐĐƵƐƐĞĚĂƉůĂŶƚŽŐĞƚůƵďƌŝĐĂƚŽƌŽĨĨǁĞůůĂŶĚĐƌĂŶĞďŽŽŵĞĚ ĚŽǁŶǁŝƚŚǁŝŶĚŐƵƐƚŝŶŐϯϬƚŽϯϱŵƉŚ͘WƵƚƉůĂŶŽŶWdtĂŶĚĚŝƐĐƵƐƐĞĚǁŝƚŚ&ŝĞůĚ&ŽƌĞŵĂŶ͘^ƵŵŵĂƌǇŽĨƉůĂŶŝƐ͗WƵƚƚĂŐ ůŝŶĞŽŶůƵďƌŝĐĂƚŽƌ͘ƌĞĂŬďŽǁĞŶƵŶŝŽŶŽĨĨĂďŽǀĞǁŝƌĞůŝŶĞǀĂůǀĞ͘WŝĐŬƵƉůƵďƌŝĐĂƚŽƌ͕ƐǁŝŶŐďŽŽŵŽǀĞƌĂŶĚƐĐŽƉĞĚŽǁŶ ďŽŽŵĂƐǁĞůĂǇůƵďƌŝĐĂƚŽƌ͘>ĂǇďŽŽŵŽŶƚŚĞƌĂĐŬŽĨƚƌƵĐŬĂŶĚƐĞĐƵƌĞǁĞůůĨŽƌƚŚĞŶŝŐŚƚ͘tŝůůďĞďĂĐŬŝŶĂŵŝĨǁŝŶĚŚĂƐ ůĂŝĚĚŽǁŶ͘ƵƚƉůĂŶŝŶĂĐƚŝŽŶĂŶĚŝƚǁŽƌŬĞĚƉĞƌĨĞĐƚ͘KĨĨǁĞůů͕ǁĞůůƐĞĐƵƌĞĚĂŶĚĐƌĂŶĞƉƵƚŝŶƚƌƵĐŬƌĂĐŬ͘ dĂŐŐĞĚdKĂƚ ϱ͕ϮϲϱΖ͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϵͬϮϲͬϮϭ ϭϮͬϭϭͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϮϰͲϯϮ ϱϬͲϭϯϯͲϮϬϲϴϴͲϬϬͲϬϬ ϮϮϬͲϬϯϳ Wdtͬ:^͘DŽďĞƚŽůŽĐĂƚŝŽŶĂŶĚƐƉŽƚĞƋƵŝƉ͘dĂŝůŐĂƚĞŵĞĞƚŝŶŐ͘ZŝŐƵƉůƵďƌŝĐĂƚŽƌ͘>ŝŶĞǁĂƐŵĂƐŚĞĚ͘WƵƚŶĞǁĐĂďůĞŚĞĂĚ 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ϱϮϵϬ͛ͲϱϮϵϱ͛ ϭϬͬϭϭͬϮϭΘ ϭϬͬϭϰͬϮϭ KǀĞƌƚŽƌƋƵĞĚ ĐŽŶŶĞĐƚŝŽŶŝŶ ϱ͘ϱ͟ĐĂƐŝŶŐĂƚ ϵϬϬ͛;ϰ͘ϴϬǁŝůů ŶŽƚƉĂƐƐ͕ ϰ͘ϳϱ͟ǁŝůůͿ dKΛϱϮϲϱ͛ Ϯ ϯ WϯͲϵ WϯͲϭϭ WϯͲϭϬ dŽƉŽĨ&ŝůůϱϭϯϰ͛ ;Ϳ ;Ϳ ;Ϳ ;Ϳ Wϯͺϵϱ͕Ϭϰϵ͛ϱ͕Ϭϲϲ͛ϯ͕ϳϯϭ͛ϯ͕ϳϰϴ͛ϭϳ͛ϭϮͬϭϭͬϮϭ ϮͲϳͬϴ͟,ϲƐƉĨ WϯͺϭϬϱ͕Ϭϵϴ͛ϱ͕ϭϬϰ͛ϯ͕ϳϲϯ͛ϯ͕ϳϲϵ͛ϲ͛ϭϮͬϭϭͬϮϭ ϮͲϳͬϴ͟,ϲƐƉĨ WϯͺϭϬϱ͕ϭϭϰ͛ϱ͕ϭϭϵ͛ϯ͕ϳϳϯ͛ϯ͕ϳϳϴ͛ϱ͛ϭϮͬϭϭͬϮϭ ϮͲϳͬϴ͟,ϲƐƉĨ WϯͺϭϬϱ͕ϭϰϭ͛ϱ͕ϭϲϱ͛ϯ͕ϳϵϭ͛ϯ͕ϴϬϳ͛Ϯϰ͛ϭϭͬϮͬϮϭ /^KϮͲϳͬϴ͟,ϲƐƉĨ Wϯͺϭϭϱ͕ϮϮϵ͛ϱ͕Ϯϱϰ͛ϯ͕ϴϰϵ͛ϯ͕ϴϴϯ͛Ϯϱ͛ϭϭͬϮͬϮϭ /^KϮͲϳͬϴ͟,ϲƐƉĨ ;DͿ;DͿ ;dsͿ ;dsͿ ͺ Ɖ 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: 12/28/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) Patch Setting Record 10/22/2021 Please include current contact information if different from above. 37' (6HW Received By: 12/30/2021 By Abby Bell at 8:56 am, Dec 29, 2021 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: 11/10/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) Gamma Gun Correlation Log 10/06/2021 Please include current contact information if different from above. Received By: 11/10/2021 37' (6HW By Abby Bell at 2:04 pm, Nov 10, 2021 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: 11/09/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) Perf 10/11/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/09/2021 By Abby Bell at 4:58 pm, Nov 09, 2021 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: 11/08/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) RBCL/GPT 10/19/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/09/2021 By Abby Bell at 8:43 am, Nov 09, 2021 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: 11/08/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) Punch/Cement Retainer 10/14/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/09/2021 By Abby Bell at 8:43 am, Nov 09, 2021 STATE OF ALASKA Reviewed By: JTZ OIL AND GAS CONSERVATION COMMISSION P.I. Supry 1I 4 -en BOPE Test Report for: KENAI UNIT 24-32 , Comm Contractor/Rig No.: Fox 8 Operator: Hilcorp Alaska, LLC Type Operation: WRKOV Sundry No: Type Test: INIT 321-473 - PTD#: 2200370 DATE: 10/25/2021 ' Inspector JeffJones - Insp Source Operator Rep: C. Bartlewski /T. Sidoti Rig Rep: L. Lynn Inspector Test Pressures: Inspection No: bopJJ2I 1102083650 Rams: Annular: Valves: v1ASP: 250/4000 ✓ 250/4000 1365 • Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: Upper Kelly 0 P/F Lower Kelly Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank NA NA System Pressure -2900 P Housekeeping: P Pit Level Indicators _NA NA Pressure After Closure --2.1.00 _ _ P _ PTD On Location P Flow Indicator NA NA 200 PSI Attained 4 P Standing Order Posted P Meth Gas Detector NA -NA Full Pressure Attained 16 _- P Well Sign P_ H2S Gas Detector NA NA Blind Switch Covers: All P Drl. Rig P -' MS Misc 0 NA Nitgn. Bottles (avg): 2 NA Hazard Sec. P P/F HCR Valves 0 ACC Misc 0 NA Misc NA 2 2" P Check Valve FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly 0 NA Lower Kelly 0 NA Ball Type _ 0 NA Inside BOP 0 NA FSV Misc 0 NA BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 1 1 3/4" P No. Valves 5 - P Annular Preventer 0 NA Manual Chokes 2 P #1 Rams 1 - 1 3/4" B/S -P Hydraulic Chokes 0 NA 42 Rams 1 l 3/4" P/S P CH 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 2 _ _ _ 2" P Quantity P/F HCR Valves 0 NA Inside Reel Valves I - - - - P ` — Kill Line Valves 2 2" P Check Valve 0 P BOP Misc 0 NA Number of Failures: 0 Test Results Test Time 12 Remarks: October 24, 2021: 1 traveled to Hilcorp's KU 24-32 well to witness an initial BOPE test on the Fox Energy Services coil tubing uniLLCTU) that is starting operations in Alaska. As the testing began it was apparent that the test pressure values indicated on the BOPE stack were not corresponding with the test pressure values on a laptop computer being used to record the test. Because there was no way to determine if the test recording equipment was in calibration, BOPE testing was delayed until the next day. I returned on 10/25/21 and the testing equipment had been calibrated and pressure values for each test were verified with a calibrated Crystal gauge on the BOPE stack. This CTU is preparing to perform a nitrogen clean out procedure on this well. The rig and surrounding location appeared clean, orderly and in good condition. ✓ I From:McLellan, Bryan J (CED) To:Todd Sidoti - (C) Subject:RE: KU 24-32 (PTD 220-037) Date:Thursday, October 21, 2021 9:03:00 AM Todd, I agree with your interpretation of the cementing results. You have approval to proceed with the patch and the remaining work under Sundry 321-473. Bryan Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Sent: Wednesday, October 20, 2021 12:39 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: KU 24-32 (PTD 220-037) Hi Bryan, We performed a squeeze on well KU 24-32 this week and attached are the CBL and a temperature log that we ran today. The bond log agrees with how the job went. We stung into the cement retainer and pumped 28 bbls of 15.3ppg slurry. With 24 bbls away we unstung from the retainer and squeezed ½ bbl into the top perfs. We left about 1.25 bbls on top of the retainer and POOH reversing. We had partial returns for the first 11 barrels of cement behind pipe. The log shows overall low bond amplitude but there is definite change between good and bad cement. All three measurements (CBL, VDL and MAP) track correctly and are in agreement. The log shows good cement from 4780-5300’ with poorer bond between 5020-5220’. The well failed an MIT-IA to 1500 psi bleeding down to 500 psi over 15 minutes. We logged a baseline temperature, injected 5 bbls of produced water into the well and logged a second temperature pass. The suspected leaky upper tubing punches are confirmed on the attached temperature log. We would like to set a patch across the leaky perfs using e-line and continue with the Sundried work (MIT-T, N2 blowdown, perforating). Please let me know if you would like to discuss. Thanks, Todd Todd Sidoti | Kenai Ops Engineer | Hilcorp Alaska | 907-632-4113 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: Rig 401 Cement IA 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): 8,155'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 8,730psi Liner 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 Dan Marlowe (907) 283-1329 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 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 todd.sidoti@hilcorp.com 6,375'5,350'3,928'1365 psi N/A Swell Pkr ; N/A 1,397'MD / 1,334'TVD; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: 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 ADL392668, FEE AA093808 220-037 50-133-20688-00-00 Kenai Unit (KU) 24-32 Kenai Gas Field / Kenai Sterling Gas Pool 3 Length Size 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 10,600psi MD 2,980psi 6,890psi 120' 1,695' 120' 1,784' 7,027'5-1/2" 16" 7-5/8" 120' 1,784' 8,120' Perforation Depth MD (ft): See Attached Schematic 8,120' 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: October 1, 2021 N/A Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 2:53 pm, Sep 14, 2021 321-473 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.14 14:34:09 -08'00' Dan Marlowe (1267) 10-404 BOP test to 3000 psi, annular test to 2500 psi. DLB 09/14/2021 BJM 9/24/21 X X Review choke manifold DSR-9/14/21 dts 9/24/2021 JLC 9/24/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.24 16:19:01 -08'00' RBDMS HEW 9/27/2021 Well Prognosis Well: KU 24-32 Date: 9/13/2021 Well Name: KU 24-32 API Number: 50-133-20688-00-00 Current Status: Gas Well Leg: Estimated Start Date: 10/1/2021 Rig: HAK 401 Reg. Approval Req’d? Yes: 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-037 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907)-632-4113 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720)-988-5375 (C) AFE Number: 2011534C Max. Expected BHP: ~1775 psi @ 3900’ TVD Based on normal gradient Max. Potential Surface Pressure: ~1365 psi (0.1 psi/ft gas gradient to surface) Brief Well Summary KU 24-32 is a grass roots development well targeting gas sands in the Upper Tyonek and Middle and Upper Beluga formations. TD was reached on 5-11-2020. Hilcorp has been perforating the sands approved in Sundry 320-225, and has not yet found commercial hydrocarbons. A remedial cement squeeze job was performed with coiled tubing in an attempt to squeeze off the P4 B1 interval and get cement up as high into the annulus as possible. A CBL was ran indicating good annular isolation and top of cement at 5300’. With cement in place in the annulus we are now in a good position to move a workover rig in and perform a suicide cement squeeze to place cement across all proposed perforation intervals. We will then drill out, log and perforate. Well Condition - Well is currently plugged back @ 5,350’ MD with cement. Procedure E-line 1. MIRU e-line with pressure control equipment. 2. PT lubricator to 250 psi low and 3000 psi high. 3. Set CIBP at 5310’. 4. Dump 5’ cement on top of plug. 5. WOC 6. MIRU pump truck. 7. Test casing and cement to 3000 psi for 15 minutes. a. Leave 1000 psi trapped on casing to verify puncher shots. 8. RIH with 5’ tubing punch & tag cement. 9. Pick up 15’ off cement and fire puncher from 5290’-5295’. 10. Pump 5 bbls produced water down tubing with field triplex and establish injectivity into punches. a. Do not exceed 3000 psi treating pressure. 11. RDMO e-line. Rig 401 1. MIRU rig 401. MIT-T Place 25' on CIBP at some point before perforating. bjm Well Prognosis Well: KU 24-32 Date: 9/13/2021 2. Load well with produced water. 3. Set TWC in 5-1/2” casing hanger. 4. ND production tree, NU 11” x 7-1/16” tubing head and test to 250 psi low & 5000 psi high. 5. NU 7-1/16” BOP and test to 250 psi low & 3000 psi high, annular to 250 psi low & 2500 psi high. a) Notify AOGCC 24 hours in advance of test to extend the opportunity to witness. b) Test rams on 3-1/2” test joint. c) Record accumulator pre-charge pressures and chart tests. d) Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 6. Pull TWC. 7. MIRU e-line unit with pressure control equipment. PT lubricator to 250 psi low / 3000 psi high. a) Set 5-1/2” composite cement retainer at 4950’. b) RIH with 5’ tubing punch loaded with & tag retainer. c) Pick up 15’ off of retainer and fire puncher from 4935’-4940’. 8. RDMO e-line. 9. MIRU cementers. PT lines to 250 psi low / 3000 psi high. a) It is critical that we are able to start pulling the workstring immediately after we have 90% of our cement displaced through the retainer. This will not be possible with a cementing head so we need to be able to rig a 2” cementing hose to a TIW valve once we are spaced out and stung in. b) We need the rig pump hooked up to the backside for an injectivity test and to rock the well. 10. MU cement retainer stinger and RIH with 3.5” workstring. 11. Space out and sting in to retainer. Mechanically establish that we are stung in per vendor procedure. 12. Establish communication through top set of punches by pumping down the backside. 13. Circulate produced water down pipe taking returns from the backside. a) Pump water with cementing pump so that we can swap to cement once we have established stable rate and returns. b) We may have to rock the well multiple times (both down the worksting and down the backside) in order to establish a flow path. c) If we are able to pump at a good rate keep circulating until returns clean up as much as possible. d) Acceptance criteria will be determined by Operations Engineer on location. 14. Once we are happy with our circulation path swap to cement. 15. With 2 bbls of cement remaining in the pipe IMMEDIATELY unsting from retainer and pick up 5’. a) We need to work quickly here so keep the (open) TIW valve attached to the workstring. 16. Hesitate for 2 minutes to allow cement to fall out of pipe. Pull the first four stands of pipe very slowly. 17. Trip out of hole. a) We are not going to reverse to clean out the pipe, we don’t want to apply any pressure to our cement on top of the retainer. b) We can rabbit the pipe at surface if necessary. 18. WOC until next morning – check samples. 19. MU PDC bit and prepare to mill cement. a) Rig up an open top cleanup tank if possible so that we can monitor returns. 20. Mill up cement and composite retainer down to 5305’. a) There will be a small column of water between the bottom of the new cement job and the top of the cement capped CIBP. It should not swap out so getting our depth right should be easy. 21. POOH laying down workstring. Well Prognosis Well: KU 24-32 Date: 9/13/2021 22. Perform MIT-T to 1500 psi for 30 minutes and chart results. 23. Set TWC. 24. ND BOPE/ NU production tree and test to 5000 psi for 30 minutes. 25. Pull TWC. 26. RDMO rig 401. Slickline (Braided) 1) MIRU braided line unit and pressure test lubricator to 250 psi low / 2500 psi high. 2) Drift to PBTD for 3-3/8” guns. 3) Log memory CBL from PBTD to 1300’. a) Send log to OE for review prior to swabbing. 4) Attempt to swab well dry. 5) RDMO. Contingent Coiled Tubing – If unable to swab well 1. MIRU CT and N2 units. Pressure test BOPs to 250 psi low / 4000 psi high. a) Notify AOGCC 24 hours prior to extend opportunity to witness test. 2. MU blowdown BHA including nozzle. 3. Blow down well to PBTD with N2. 4. RDMO N2 and CT. E-line 1) MIRU e-line Unit and pressure control equipment. PT lubricator to 250 psi Low / 2500 psi High. 2) Perforate the following sand intervals per table below with 3-3/8” HSC guns loaded at 6 SPF with 22.7g charges: a) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist (Ben Siks) and Reservoir Engineer (Trudi Hallet) for confirmation. b) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5, 10 and 15 minute intervals. c) Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug capped with 25’ of cement or an isolation patch may be set prior to moving up to the next sand interval. N2 may be employed to depress the fluid level prior to plugging work. 3) Turn well over to production. Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P3_A8 ±4,986’ ±5,013’ ±3,690’ ±3,717’ ±27’ TBD Proposed P3_A9 ±5,049’ ±5,066’ ±3,731’ ±3,748’ ±17’ TBD Proposed P3_A10 ±5,098’ ±5,104’ ±3,763’ ±3,769’ ±6’ TBD Proposed P3_A10 ±5,114’ ±5,119’ ±3,773’ ±3,778’ ±5’ TBD Proposed P3_A10 ±5,141’ ±5,166’ ±3,791’ ±3,816’ ±25’ TBD Proposed P3_A11 ±5,205’ ±5,254’ ±3,834’ ±3,883’ ±49’ TBD Proposed Before perforating, place 25' of cement on top of the bridge plug at 5310' md to isolate pool 4. bjm Well Prognosis Well: KU 24-32 Date: 9/13/2021 Attachments 1. Current Schematic 2. Proposed Schematic 3. Rig 401 BOP Diagram 4. CTU BOP Diagram 5. 660’ Radius SSSV Requirement Map 6. Hilcorp Standard Nitrogen Procedure Updated by DMA 03-05-21 SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = 5,350’ MD / TVD = 3,928’ TD = 8,155’ MD / TVD = 6,375’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P4 B1 5,315’ 5,335’ 3,905’ 3,918’ 20’ 2/24/2021 Open 2-7/8” P4 B1 5,325’ 5,345’ 3,911’ 3,926’ 20’ 12/11/2020 Open 3-3/8” P4 B1 5,360’ 5,380’ 3,934’ 3,947’ 20’ 6/26/2020 Squeezed 3-3/8” UB 1X 6,556' 6,562' 4,842’ 4,847’ 6' 6/24/2020 Isolated 3-3/8” 6,573' 6,579' 4,857’ 4,862’ 6' 6/24/2020 Isolated 3-3/8” UB 2 6,632' 6,640' 4,909’ 4,917’ 8' 6/23/2020 Isolated 3-3/8” 6,666' 6,686' 4,940’ 4,957’ 20' 6/11/2020 Isolated 3-3/8” MB 6 7,685' 7,695' 5,912’ 5,922’ 10' 6/11/2020 Isolated 3-3/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 Hyd 563 6.875” Surf 1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf 8,121’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,397’ 4.892” 6.35” Swell Packer 2 5,355’ 5-1/2” CIBP (12/9/2020) w/ 5’ of cement (TOC @ 5,350’) 3 5,450’ 5-1/2” CIBP (9/10/20) 4 6,532’ 5-1/2” CIBP (6/26/20) 5 6,610’ 5-1/2” CIBP (6/24/20) 6 6,655’ 5-1/2” CIBP (6/22/20) 7 7,600’ 5-1/2” Evo-Trieve Plug (6/15/20) OPEN HOLE / CEMENT DETAIL 7-5/8" 160 BBLs of cement in 9-7/8” hole – 24 bbls Returns to surface 5-1/2” 146 BBLs of cement in 6-3/4” hole. CBL TOC @ 5,300’ 5-1/2” x 7-5/8” Downsqueezed 16 BBLs of cement down IA and displaced TOC to 1000’. 6-3/4” hole UB 2 MB 6 UB 1X TOC @ 5300’ from CBL P4 B1 UB 2 P4 B1 2 3 4 5 6 7 Cement Packer TOC @ 1000’ (Volumetric) Updated by TCS 09-14-21 PROPOSED SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = 5,350’ MD / TVD = 3,928’ TD = 8,155’ MD / TVD = 6,375’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P3_A8 ±4,986’ ±5,013’ ±3,690’ ±3,717’ ±27’ TBD Proposed P3_A9 ±5,049’ ±5,066’ ±3,731’ ±3,748’ ±17’ TBD Proposed P3_A10 ±5,098’ ±5,104’ ±3,763’ ±3,769’ ±6’ TBD Proposed P3_A10 ±5,114’ ±5,119’ ±3,773’ ±3,778’ ±5’ TBD Proposed P3_A10 ±5,141’ ±5,166’ ±3,791’ ±3,816’ ±25’ TBD Proposed P3_A11 ±5,205’ ±5,254’ ±3,834’ ±3,883’ ±49’ TBD Proposed P4 B1 5,315’ 5,335’ 3,905’ 3,918’ 20’ 2/24/2021 Open 2-7/8” P4 B1 5,325’ 5,345’ 3,911’ 3,926’ 20’ 12/11/2020 Open 3-3/8” P4 B1 5,360’ 5,380’ 3,934’ 3,947’ 20’ 6/26/2020 Squeezed 3-3/8” UB 1X 6,556' 6,562' 4,842’ 4,847’ 6' 6/24/2020 Isolated 3-3/8” 6,573' 6,579' 4,857’ 4,862’ 6' 6/24/2020 Isolated 3-3/8” UB 2 6,632' 6,640' 4,909’ 4,917’ 8' 6/23/2020 Isolated 3-3/8” 6,666' 6,686' 4,940’ 4,957’ 20' 6/11/2020 Isolated 3-3/8” MB 6 7,685' 7,695' 5,912’ 5,922’ 10' 6/11/2020 Isolated 3-3/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 Hyd 563 6.875” Surf 1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf 8,121’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,397’ 4.892” 6.35” Swell Packer 2 ±5,310’ 5-1/2” CIBP with 5’ cement cap (TOC @ ±5,305’) 3 5,355’ 5-1/2” CIBP (12/9/2020) w/ 5’ of cement (TOC @ 5,350’) 4 5,450’ 5-1/2” CIBP (9/10/20) 5 6,532’ 5-1/2” CIBP (6/26/20) 6 6,610’ 5-1/2” CIBP (6/24/20) 7 6,655’ 5-1/2” CIBP (6/22/20) 8 7,600’ 5-1/2” Evo-Trieve Plug (6/15/20) OPEN HOLE / CEMENT DETAIL 7-5/8" 160 BBLs of cement in 9-7/8” hole – 24 bbls Returns to surface 5-1/2” 146 BBLs of cement in 6-3/4” hole. CBL TOC @ 5,300’ 5-1/2” x 7-5/8” Downsqueezed 16 BBLs of cement down IA and displaced TOC to 1000’. 6-3/4” hole UB 2 MB 6 UB 1X TOC @ 5300’ from CBL P4 B1 UB 2 P4 B1 3 4 5 6 7 8 Cement Packer TOC @ 1000’ (Volumetric) New Sterling Perfs 2 TOC @ ~4900’ from CBL Tbg punched 4935’-4940’ 5290’-5295’ !""#$%#&’()*!’"+),-*!.(!$/.’*(#/0& )*1(2!()&’//0"’*# $.#’,,)& "23#,(0++)+#($.#4#%"5# (&3#!,’4#’ $.#6#7879:;<<<#&=.3#.*7>;:<6<;:<<<7?77(* $.#’,,)& "23#* $.#6#7879:;<<<#&=.3#.*73#,(0++)+# $(($&#4#($.3#=!(@#A?B#C#7879:;D#&=.3#,(0++)+#$0(")(6<:<6<;:<<<C>7C77CC??EE;;9966FF’’ --++0/"),,#$(@)*=!,)#,.)-!%!)++=5#,!G)+/’&) +’()+=/-@D’D,H!/’2F8F8C<7>F8F8C<7>+),-*!.(!$/&’()*!’"I###,))# $&*)H($")*’/-)%*’-(!$/ 7879J4J44J444 J<? J<7; J<<;’/5"),4!4J4! ?<K 7;K%!/!,@#############*&,C;<(@!,#+$-0&)/(#’/+#’""#(@)#!/%$*&’(!$/#-$/(’!/)+#@)*)!/#!,#(@)#,$")#’/+#)4-"0,!H)#.*$.)*(2#$%#!/()5*’()+#)10!.&)/(#’/+#,@’""#/$(# )#0,)+3#+!,-"$,)+3#$*#-$.!)+#=!(@$0(#(@)#)4.*),,#=*!(()/#.)*&!,,!$/#$%#!/()5*’()+#)10!.&)/(J#(@!,#+$-0&)/(#!,#"$’/)+.0*,0’/(#($#’5*))&)/(#($#(@)#%$*)5$!/5#’/+#,@’""# )#*)(0*/)+#($#!/()5*’()+#)10!.&)/(J#0.$/#+)&’/+3#!/()5*’()+#)10!.&)/(#*),)*H),#(@)#*!5@(#($#-@’/5)#+),!5/,3#&’()*!’",3#’/+#,.)-!%!-’(!$/,#=!(@$0(#/$(!-)J*)H:#:,@))(7#87# !"#$%&"#’)10!.&)/()-//$J,(’-D# $.3#6#7879L:#;D####J<?<#&!/!&0&#J<7;#&’4!&0&-$/-)/(*!-!(2-$*/)*#*’+!! *)’D#,@’*.#)+5),#J<7<#!/#7<LJ.’*’"")"!,&#J<7<#!/#7<LJ#J<7<#(J!J*J,10’*)/),,+$#/$(#,-’")#(@!,#+*’=!/5J’""#+!&)/,!$/,#!/#!/-@),J’""#%"’/5)#+*!""!/5#&0,(#,(*’++")#-$&&$/#-)/()*"!/)J*%,#)4-).(#=@)/###&###&$+!%!)+J+*’=!/5#!,#’#(@!*+’/5")#.*$M)-(!$/J 2)-/#+),-*!.(!$/+’().’*(#/$J?7:<<77E6A9;J?BA?<J>BAC>JFB77C7 KU 24-32 SHL SEC. 32 SEC. 31 SEC. 6 SEC. 1 5N11W 4N12W 4N11WPIPELINE STSPUR CT WATSJ OLD LN BYPASS RDKALIFORNSKY BEACH RDKENAI UNIT Kenai Gas Field Pad No. 34-31 COOK INLET REGION INC KIZER STUART CHIVERS EMILY J KRAMER KEITH LOCKE JEFFERY & NANCY LOCKE JEFFREY D & NANCY LOCKE JEFFREY D & NANCY COOK INLET REGION INC KENAI PENINSULA BOROUGH COOK INLET REGION INC KEENER TIMOTHY BRUCE KEENER TIMOTHY B & MARILYN SCHMIDT MICHAEL RSCHMIDT MICHAEL R HENRIE MORGAN E KEENER TIMOTHY BRUCE MACIK STEVE M & EDI B KENAI PENINSULA BOROUGH KENAI PENINSULA BOROUGH KEENER SAND AND GRAVEL LLC KEENER SAND AND GRAVEL LLC HENRIE MORGAN E HENRIE AARON KENAI PENINSULA BOROUGH SALAMATOF NATIVE ASSN INC SALAMATOF NATIVE ASSN INC 151°15'40"W151°15'50"W151°16'0"W151°16'10"W151°16'20"W151°16'30"W151°16'40"W151°16'50"W 60°29'5"N60°29'0"N60°29'0"N60°28'55"N60°28'55"N60°28'50"N60°28'50"N60°28'45"N60°28'45"N60°28'40"N60°28'40"N60°28'35"N60°28'35"N60°28'30"N60°28'30"N60°28'25"N60°28'25"N60°28'20"N60°28'20"N60°28'15"N60°28'15"N60°28'10"N60°28'10"NKenaiUnit KGF 34-31 Pad Well: KU 24-32 660 ft Radius 0 200 400 600 800 Feet Legend Surface Well Location Existing Gas Pipelines MHW Line (NOAA) KGF 34-31 Pad - 660ft Buffers Well: KU 24-32 SHL KPB Parcels Cook Inlet Oil and Gas Units 1 inch = 400 feet @ 11x17 page size Map Date: 9/13/2021 Document Path: O:\Alaska\GIS\cook_inlet\fields\KenaiUnit\mxds\Kenai_Unit_KU_24-32_Well_660ftBuffer_11x17_TSidoti.mxd STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE : 03/05/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) PERFORATING RECORD 02/24/2021 Please include current contact information if different from above. PTD: 2200370 E-Set: 34748 Received by the AOGCC 03/08/2021 03/09/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Re-Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 8,155 feet 6655; 7600 feet true vertical 6,375 feet N/A feet Effective Depth measured 5,350 feet 1,397 feet true vertical 3,928 feet 1,334 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 1,397' MD 1,334' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 2,980psi 10,600psi 120' 1,629'6,890psi Collapse 1,410psi 4,790psi 8,730psi Casing Structural 16" 7-5/8" Length 120' 1,784' 8,121' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 0 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-083 74 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-037 50-133-20688-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 700 Kenai Unit (KU) 24-32 N/A ADL392668, FEE AA093808 Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field - Kenai Sterling Gas Pool 3N/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 5-1/2"8,121'5,342' 5355; 5450; 6532; 6610; WINJ WAG 0 Water-Bbl MD 120' 1,784' 0 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:54 am, Mar 08, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.03.08 08:31:14 -09'00' Taylor Wellman (2143) RBDMS HEW 3/8/2021 BJM 4/26/21 DSR-3/8/21 SFD 3/16/2021 Rig Start Date End Date E-Line 2/24/21 2/24/21 02/24/2021 - Wednesday Travel to location. Contact DSO, inspect location, PTW, PJSM. Spot equipment. MIRU AK Eline, Make up GR/CCL, test wire for communication. Good Test. Make up 20' 2-7/8", 6 spf, 60° phase, 15gram razor gun, Stab on well, Pt low/high 250/2,500. Open well, WHP 100, IA valve is closed, OA 0 RIH, Tag at 5,307' CCL Depth, Pull log up to 3,870'. Send log to town for approval to shoot 5,315'-5,335'. Got approval to shoot 5,315'-5335' ( Trudi Hallett). Make -2' correction, RIH to 5,335' PU getting on CCL depth @ 5,307.1'. CCL t/top shot 7.9', CCL t/bottom shot 27.9'. Shoot 5,315'-5,335', ITP 100 psi, 5 MIN no change 100 PSI. 10 min, no change.100 PSI, 15 min no change, FTP 100. POOH. Tagged up, swab shut, Bleed down, Pop off well, All shots fired, Wet gun, RDMO Eline, Turn well over to operations. Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name KU 24-32 50-133-20688-00-00 220-037 Shoot 5,315'-5,335', Updated by DMA 03-05-21 SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = 5,350’ MD / TVD = 3,928’ TD = 8,155’ MD / TVD = 6,375’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P4 B1 5,315’ 5,335’ 3,905’ 3,918’ 20’ 2/24/2021 Open 2-7/8” P4 B1 5,325’ 5,345’ 3,911’ 3,926’ 20’ 12/11/2020 Open 3-3/8” P4 B1 5,360’ 5,380’ 3,934’ 3,947’ 20’ 6/26/2020 Squeezed 3-3/8” UB 1X 6,556' 6,562' 4,842’ 4,847’ 6' 6/24/2020 Isolated 3-3/8” 6,573' 6,579' 4,857’ 4,862’ 6' 6/24/2020 Isolated 3-3/8” UB 2 6,632' 6,640' 4,909’ 4,917’ 8' 6/23/2020 Isolated 3-3/8” 6,666' 6,686' 4,940’ 4,957’ 20' 6/11/2020 Isolated 3-3/8” MB 6 7,685' 7,695' 5,912’ 5,922’ 10' 6/11/2020 Isolated 3-3/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 Hyd 563 6.875” Surf 1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf 8,121’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,397’ 4.892” 6.35” Swell Packer 2 5,355’ 5-1/2” CIBP (12/9/2020) w/ 5’ of cement (TOC @ 5,350’) 3 5,450’ 5-1/2” CIBP (9/10/20) 4 6,532’ 5-1/2” CIBP (6/26/20) 5 6,610’ 5-1/2” CIBP (6/24/20) 6 6,655’ 5-1/2” CIBP (6/22/20) 7 7,600’ 5-1/2” Evo-Trieve Plug (6/15/20) OPEN HOLE / CEMENT DETAIL 7-5/8" 160 BBLs of cement in 9-7/8” hole – 24 bbls Returns to surface 5-1/2” 146 BBLs of cement in 6-3/4” hole. CBL TOC @ 5,300’ 5-1/2” x 7-5/8” Downsqueezed 16 BBLs of cement down IA and displaced TOC to 1000’. 6-3/4” hole UB 2 MB 6 UB 1X TOC @ 5300’ from CBL P4 B1 UB 2 P4 B1 2 3 4 5 6 7 Cement Packer TOC @ 1000’ (Volumetric) ()()()() P4 B1 5,315’ 5,335’3,905’3,918’20’2/24/2021 Open 2-7/8” (M )(M )(TV )(TV ) 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): 8,155'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 8,730psi Liner 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: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 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 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: February 25, 2021 N/A 8,120' Perforation Depth MD (ft): See Attached Schematic 8,120' 7,027'5-1/2" 16" 7-5/8" 120' 1,784' 2,980psi 6,890psi 120' 1,695' 120' 1,784' N/A TVD Burst N/A 10,600psi MDLength Size 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL392668, FEE AA093808 220-037 50-133-20688-00-00 Kenai Unit (KU) 24-32 Kenai Gas Field / Kenai Sterling Gas Pool 3 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com 6,375'5,350'3,928'1365 psi N/A Swell Pkr ; N/A 1,397'MD / 1,334'TVD; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 5:46 pm, Feb 12, 2021 321-083 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.02.12 15:40:01 -09'00' Taylor Wellman (2143) GLS 2/15/21 X (reperf) 10-404 GAS DLB 02/16/2021 Perforate DSR-2/16/21Comm. 2/16/21 dts 2/16/2021 JLC 2/16/2021 RBDMS HEW 2/17/2021 Well Prognosis Well: KU 24-32 Date: 1/20/2021 Well Name: KU 24-32 API Number: 50-133-20688-00-00 Current Status: Gas Well Leg: Estimated Start Date: 2/25/2021 Rig: EL Reg. Approval Req’d? Yes: 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-037 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907)-632-4113 (C) Second Call Engineer: Jake Flora (907) 777-8420 (O) (985)-867-0665 (C) AFE Number: 201-01534 Max. Expected BHP: ~1775 psi @ 3900’ TVD Based on normal gradient Max. Potential Surface Pressure: ~1365 psi (0.1 psi/ft gas gradient to surface) Brief Well Summary KU 24-32 is a grass roots development well targeting gas sands in the Upper Tyonek and Middle and Upper Beluga formations. TD was reached on 5-11-2020. A remedial cement squeeze job was performed with coiled tubing in an attempt to squeeze off the P4 B1 interval and get cement up as high into the annulus as possible. A CBL was ran indicating good annular isolation and top of cement at 5300’. The P4B1 was shot from 5,325’-5,345’ and the well came on making an erratic rate averaging about 200 mscfd. The purpose of this work is to re-perforate the B1 from 5315’-5335’. Procedure 1. MIRU e-line with pressure control equipment. 2. PT lubricator to 250 psi low and 2500 psi high. 3. RIH with 3-3/8” guns loaded at 6 SPF 60 degree phasing. 4. Perforate the following sand interval: Sand MD Top MD Bottom Total Footage (MD) P4_B1 ±5,315' ±5,335' 20' a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist (Ben Siks) and Reservoir Engineer (Trudi Hallet) for confirmation. b. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5, 10 and 15 minute intervals. 5. RDMO e-line. Attachments: x Current Schematic x Proposed Schematic (sundry 320-516)IA downsqueeze done in Jan. 2021 Note: Updated by DMA 01-07-21 SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = 5,350’ MD / TVD = 3,928’ TD = 8,155’ MD / TVD = 6,375’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P4 B1 5,325 5,345 3,911 3,926’ 20’ 12/11/2020 Open 3-3/8” P4 B1 5,360’ 5,380’ 3,934’ 3,947’ 20’ 6/26/2020 Squeezed 3-3/8” UB 1X 6,556' 6,562' 4,842’ 4,847’ 6' 6/24/2020 Isolated 3-3/8” 6,573' 6,579' 4,857’ 4,862’ 6' 6/24/2020 Isolated 3-3/8” UB 2 6,632' 6,640' 4,909’ 4,917’ 8' 6/23/2020 Isolated 3-3/8” 6,666' 6,686' 4,940’ 4,957’ 20' 6/11/2020 Isolated 3-3/8” MB 6 7,685' 7,695' 5,912’ 5,922’ 10' 6/11/2020 Isolated 3-3/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 Hyd 563 6.875” Surf 1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf 8,121’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,397’ 4.892” 6.35” Swell Packer 2 5,355’ 5-1/2” CIBP (12/9/2020) w/ 5’ of cement (TOC @ 5,350’) 3 5,450’ 5-1/2” CIBP (9/10/20) 4 6,532’ 5-1/2” CIBP (6/26/20) 5 6,610’ 5-1/2” CIBP (6/24/20) 6 6,655’ 5-1/2” CIBP (6/22/20) 7 7,600’ 5-1/2” Evo-Trieve Plug (6/15/20) OPEN HOLE / CEMENT DETAIL 7-5/8" 160 BBL’s of cement in 9-7/8” hole – 24 bbls Returns to surface 5-1/2” 146 BBL’s of cement in 6-3/4” hole. CBL TOC @ 5,300’ 6-3/4” hole UB 2 MB 6 UB 1X TOC @ 5300’ from CBL P4 B1 UB 2 P4 B1 2 3 4 5 6 7 Cement Packer TOC @ 1000’ (Volumetric) Updated by TCS 01-20-21 PROPOSED SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = 5,350’ MD / TVD = 3,928’ TD = 8,155’ MD / TVD = 6,375’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P4B1 5,315’ 5,335’ 3,905’ 3,918’ 20’ - - P4 B1 5,325’ 5,345’ 3,911’ 3,926’ 20’ 12/11/2020 Open 3-3/8” P4 B1 5,360’ 5,380’ 3,934’ 3,947’ 20’ 6/26/2020 Squeezed 3-3/8” UB 1X 6,556' 6,562' 4,842’ 4,847’ 6' 6/24/2020 Isolated 3-3/8” 6,573' 6,579' 4,857’ 4,862’ 6' 6/24/2020 Isolated 3-3/8” UB 2 6,632' 6,640' 4,909’ 4,917’ 8' 6/23/2020 Isolated 3-3/8” 6,666' 6,686' 4,940’ 4,957’ 20' 6/11/2020 Isolated 3-3/8” MB 6 7,685' 7,695' 5,912’ 5,922’ 10' 6/11/2020 Isolated 3-3/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 Hyd 563 6.875” Surf 1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf 8,121’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,397’ 4.892” 6.35” Swell Packer 2 5,355’ 5-1/2” CIBP (12/9/2020) w/ 5’ of cement (TOC @ 5,350’) 3 5,450’ 5-1/2” CIBP (9/10/20) 4 6,532’ 5-1/2” CIBP (6/26/20) 5 6,610’ 5-1/2” CIBP (6/24/20) 6 6,655’ 5-1/2” CIBP (6/22/20) 7 7,600’ 5-1/2” Evo-Trieve Plug (6/15/20) OPEN HOLE / CEMENT DETAIL 7-5/8" 160 BBL’s of cement in 9-7/8” hole – 24 bbls Returns to surface 5-1/2” 146 BBL’s of cement in 6-3/4” hole. CBL TOC @ 5,300’ 6-3/4” hole UB 2 MB 6 UB 1X TOC @ 5300’ from CBL P4 B1 UB 2 P4 B1 2 3 4 5 6 7 Cement Packer TOC @ 1000’ (Volumetric) IA Down squeeze data is missing. re-perf 5315-5335' Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 01/15/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) RCBL Radial Cement Bond Log 11/05/2020 Please include current contact information if different from above. 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(5.5" x 7.625") Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 12/23/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KDU 24-32 (PTD 220-037) FINAL GR, Cement, Pressure, Temperature, Plug, and Perforation log 12/10/2020 Please include current contact information if different from above. 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ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚϴϰyͲϱϲtĞůĚ ϭϱ͘Ϭϭ͟^ƵƌĨϭϮϬΖ ϳͲϱͬϴΗ^ƵƌĨƐŐϮϵ͘ϳ>ͲϴϬ,ǇĚϱϲϯϲ͘ϴϳϱ͟^ƵƌĨϭ͕ϳϴϰ͛ ϱͲϭͬϮΗWƌŽĚƐŐϭϳ>ͲϴϬ,dYϰ͘ϴϵϮ͟^ƵƌĨϴ͕ϭϮϭ͛ ϭ ϭϲ͟ ϳͲϱͬϴ͟ ϵͲϳͬϴ͟ ŚŽůĞ ϱͲϭͬϮ͟ :t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϭ͕ϯϵϳ͛ϰ͘ϴϵϮ͟ϲ͘ϯϱ͟^ǁĞůůWĂĐŬĞƌ KWE,K>ͬDEdd/> ϳͲϱͬϴΗϭϲϬ>͛ƐŽĨĐĞŵĞŶƚŝŶϵͲϳͬϴ͟ŚŽůĞʹϮϰďďůƐZĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞ ϱͲϭͬϮ͟ϭϰϲ>͛ƐŽĨĐĞŵĞŶƚŝŶϲͲϯͬϰ͟ŚŽůĞ͘>dKΛΕϱ͕ϲϬϬ͛ ϲͲϯͬϰ͟ ŚŽůĞ hϮ Dϲ ϱͲϭͬϮ͟ǀŽͲ dƌŝĞǀĞƉůƵŐ ƐĞƚĂƚϳϲϬϬ͛ hϭy dKΛϱϯϬϬ͛ ĨƌŽŵ> Wϰϭ ϱͲϭͬϮ͟/W ƐĞƚĂƚϲϲϱϱ͛ ϱͲϭͬϮ͟/W ƐĞƚĂƚϲϲϭϬ͛ hϮ ϱͲϭͬϮ͟/W ƐĞƚĂƚϲϱϯϮ͛ ϱͲϭͬϮ͟/W ƐĞƚĂƚϱ͕ϰϱϬ͛ Wϰϭ ϱͲϭͬϮ͟/WƐĞƚĂƚϱ͕ϯϱϱ͛ ĂƉƉĞĚǁŝƚŚϱ͛ŽĨĞŵĞŶƚ (leaking) .0165 bbl/ft = IA 16.5bbl 1784 ft hƉĚĂƚĞĚďǇd^ϭϮͲϴͲϮϬ WZKWK^^,Dd/ <ĞŶĂŝ'ĂƐ&ŝĞůĚ <hϮϰͲϯϮ Wd͗ϮϮϬͲϬϯϳ W/͗ϱϬͲϭϯϯͲϮϬϲϴϴͲϬϬͲϬϬ Wdсϱ͕ϯϱϬ͛Dͬdsсϯ͕ϵϮϲ͛ dсϴ͕ϭϱϱ͛Dͬdsсϲ͕ϯϳϱ͛ Z<ƚŽ'>сϭϴ͛ WZ&KZd/KEd/> ^ĂŶĚƐdŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ&dĂƚĞ ^ƚĂƚƵƐͬ^ŝǌĞ Wϰϭϱ͕ϯϮϱϱ͕ϯϰϱϯ͕ϵϭϭϯ͕ϵϮϲ͛ϮϬ͛ϭϮͬϭϬͬϮϬϮϬKƉĞŶϯͲϯͬϴ͟ Wϰϭϱ͕ϯϲϬ͛ϱ͕ϯϴϬ͛ϯ͕ϵϯϰ͛ϯ͕ϵϰϳ͛ϮϬ͛ϲͬϮϲͬϮϬϮϬ^ƋƵĞĞǌĞĚϯͲϯͬϴ͟ hϭyϲ͕ϱϱϲΖϲ͕ϱϲϮΖϰ͕ϴϰϮ͛ϰ͕ϴϰϳ͛ϲΖϲͬϮϰͬϮϬϮϬ/ƐŽůĂƚĞĚϯͲϯͬϴ͟ ϲ͕ϱϳϯΖϲ͕ϱϳϵΖϰ͕ϴϱϳ͛ϰ͕ϴϲϮ͛ϲΖϲͬϮϰͬϮϬϮϬ/ƐŽůĂƚĞĚϯͲϯͬϴ͟ hϮϲ͕ϲϯϮΖϲ͕ϲϰϬΖϰ͕ϵϬϵ͛ϰ͕ϵϭϳ͛ϴΖϲͬϮϯͬϮϬϮϬ/ƐŽůĂƚĞĚϯͲϯͬϴ͟ ϲ͕ϲϲϲΖϲ͕ϲϴϲΖϰ͕ϵϰϬ͛ϰ͕ϵϱϳ͛ϮϬΖϲͬϭϭͬϮϬϮϬ/ƐŽůĂƚĞĚϯͲϯͬϴ͟ Dϲϳ͕ϲϴϱΖϳ͕ϲϵϱΖϱ͕ϵϭϮ͛ϱ͕ϵϮϮ͛ϭϬΖϲͬϭϭͬϮϬϮϬ/ƐŽůĂƚĞĚϯͲϯͬϴ͟ ^/E'd/> ^ŝǌĞdǇƉĞtƚ'ƌĂĚĞŽŶŶ͘/dŽƉƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚϴϰyͲϱϲtĞůĚ ϭϱ͘Ϭϭ͟^ƵƌĨϭϮϬΖ ϳͲϱͬϴΗ^ƵƌĨƐŐϮϵ͘ϳ>ͲϴϬ,ǇĚϱϲϯϲ͘ϴϳϱ͟^ƵƌĨϭ͕ϳϴϰ͛ ϱͲϭͬϮΗWƌŽĚƐŐϭϳ>ͲϴϬ,dYϰ͘ϴϵϮ͟^ƵƌĨϴ͕ϭϮϭ͛ ϭ ϭϲ͟ ϳͲϱͬϴ͟ ϵͲϳͬϴ͟ ŚŽůĞ ϱͲϭͬϮ͟ :t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϭ͕ϯϵϳ͛ϰ͘ϴϵϮ͟ϲ͘ϯϱ͟^ǁĞůůWĂĐŬĞƌ KWE,K>ͬDEdd/> ϳͲϱͬϴΗϭϲϬ>͛ƐŽĨĐĞŵĞŶƚŝŶϵͲϳͬϴ͟ŚŽůĞʹϮϰďďůƐZĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞ ϱͲϭͬϮ͟ϭϰϲ>͛ƐŽĨĐĞŵĞŶƚŝŶϲͲϯͬϰ͟ŚŽůĞ͘>dKΛΕϱ͕ϲϬϬ͛ ϲͲϯͬϰ͟ ŚŽůĞ hϮ Dϲ ϱͲϭͬϮ͟ǀŽͲ dƌŝĞǀĞƉůƵŐ ƐĞƚĂƚϳϲϬϬ͛ hϭy dKΛϱϯϬϬ͛ ĨƌŽŵ> Wϰϭ ϱͲϭͬϮ͟/W ƐĞƚĂƚϲϲϱϱ͛ ϱͲϭͬϮ͟/W ƐĞƚĂƚϲϲϭϬ͛ hϮ ϱͲϭͬϮ͟/W ƐĞƚĂƚϲϱϯϮ͛ ϱͲϭͬϮ͟/W ƐĞƚĂƚϱ͕ϰϱϬ͛ Wϰϭ ϱͲϭͬϮ͟/WƐĞƚĂƚϱ͕ϯϱϱ͛ ĂƉƉĞĚǁŝƚŚϱ͛ŽĨĞŵĞŶƚ dKΛϭϬϬϬ͛ ;sŽůƵŵĞƚƌŝĐͿ 16.5bbl Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 11/12/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) ACX 08/04/2019 Please include current contact information if different from above. Received by the AOGCC 11/13/2020 PTD: 2200370 E-Set: 34241 Abby Bell 11/13/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 11/03/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) PRESSURE TEMPERATURE 06-12-2020 PRESSURE TEMPERATURE 06-15-2020 Please include current contact information if different from above. Received by the AOGCC 11/03/2020 Abby Bell 11/03/2020 PTD: 2200370 E-Set: 34177 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 11/03/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) PRESSURE TEMPERATURE 06-12-2020 PRESSURE TEMPERATURE 06-15-2020 Please include current contact information if different from above. Received by the AOGCC 11/03/2020 Abby Bell 11/03/2020 PTD: 2200370 E-Set: 34176 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 11/03/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (PTD 220-037) PLUG SET RECORD 06/15/2020 Please include current contact information if different from above. Received by the AOGCC 11/03/2020 Abby Bell 11/03/2020 PTD: 2200370 E-Set: 34175 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-133-20688-00-00Well Name/No. KENAI UNIT 24-32Completion Status1-GASCompletion Date6/11/2020Permit to Drill2200370OperatorHilcorp Alaska, LLCMD8155TVD6375Current Status1-GAS10/15/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, DGR, AGR, ABG, ADR, EWR MD & TVD, Mudlog, Geotap CBL 5-24-20NoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF7/20/202095 8156 Electronic Data Set, Filename: KU 24-32 LWD Final.las33562EDDigital DataDF7/20/2020################Electronic Data Set, Filename: KU 24-32 Run 300 Geotap Test 1.las33562EDDigital DataDF7/20/2020################Electronic Data Set, Filename: KU 24-32 Run 300 Geotap Test 2.las33562EDDigital DataDF7/20/2020################Electronic Data Set, Filename: KU 24-32 Run 300 Geotap Test 3.las33562EDDigital DataDF7/20/2020################Electronic Data Set, Filename: KU 24-32 Run 300 Geotap Test 4.las33562EDDigital DataDF7/20/2020################Electronic Data Set, Filename: KU 24-32 Run 300 Geotap Test 5.las33562EDDigital DataDF7/20/2020################Electronic Data Set, Filename: KU 24-32 Run 300 Geotap Test 6.las33562EDDigital DataDF7/20/2020################Electronic Data Set, Filename: KU 24-32 Run 300 Geotap Test 7.las33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 LWD Final MD.cgm33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 LWD Final TVD.cgm33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Run 300 GeoTap Recorded Pressure Tests.cgm33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 DSR-Plan.pdf33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 DSR-VSec.pdf33562EDDigital DataThursday, October 15, 2020AOGCCPage 1 of 8Supplied byOPSupplied by OPKU 24-32 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-133-20688-00-00Well Name/No. KENAI UNIT 24-32Completion Status1-GASCompletion Date6/11/2020Permit to Drill2200370OperatorHilcorp Alaska, LLCMD8155TVD6375Current Status1-GAS10/15/2020UICNoDF7/20/2020 Electronic File: KU 24-32 DSR.xlsx33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32_Definitive Survey Report.pdf33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32_DSR.txt33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32_GIS.txt33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 LWD Final MD.pdf33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 LWD Final TVD.pdf33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Run 300 GeoTap Recorded Pressure Tests.pdf33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 LWD Final MD.tif33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 LWD Final TVD.tif33562EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Run 300 GeoTap Recorded Pressure Tests.tif33562EDDigital DataDF7/20/2020 Electronic File: EMFView3_1.zip33562EDDigital DataDF7/20/2020 Electronic File: Readme.txt33562EDDigital Data0 0 2200370 KENAI UNIT 24-32 LOG HEADERS33562LogLog Header Scans0 0 2200370 KENAI UNIT 24-32 LOG HEADERS33563LogLog Header ScansDF7/20/202010 8200 Electronic Data Set, Filename: KU 24-32.las33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 04-30-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-01-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-02-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-03-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-04-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-05-2020.pdf33563EDDigital DataThursday, October 15, 2020AOGCCPage 2 of 8KU 24-32.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-133-20688-00-00Well Name/No. KENAI UNIT 24-32Completion Status1-GASCompletion Date6/11/2020Permit to Drill2200370OperatorHilcorp Alaska, LLCMD8155TVD6375Current Status1-GAS10/15/2020UICNoDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-06-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-07-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-08-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-09-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-10-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-11-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-12-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-13-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-14-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-15-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-16-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-17-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-18-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: Hilcorp KU 24-32 Geolog AM Report 05-19-2020.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Final Well Report.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Drilling Dynamics Log MD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Drilling Dynamics Log TVD.pdf33563EDDigital DataThursday, October 15, 2020AOGCCPage 3 of 8 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-133-20688-00-00Well Name/No. KENAI UNIT 24-32Completion Status1-GASCompletion Date6/11/2020Permit to Drill2200370OperatorHilcorp Alaska, LLCMD8155TVD6375Current Status1-GAS10/15/2020UICNoDF7/20/2020 Electronic File: KU 24-32 - 5in Formation Log MD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Formation Log TVD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Gas Ratio Log MD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Gas Ratio Log TVD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in LWD Combo Log MD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in LWD Combo Log TVD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Drilling Dynamics Log MD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Drilling Dynamics Log TVD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Formation Log MD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Formation Log TVD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Gas Ratio Log MD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Gas Ratio Log TVD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - LWD Combo Log MD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - LWD Combo Log TVD.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Drilling Dynamics Log MD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Drilling Dynamics Log TVD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Formation Log MD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Formation Log TVD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in Gas Ratio Log MD.tif33563EDDigital DataThursday, October 15, 2020AOGCCPage 4 of 8 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-133-20688-00-00Well Name/No. KENAI UNIT 24-32Completion Status1-GASCompletion Date6/11/2020Permit to Drill2200370OperatorHilcorp Alaska, LLCMD8155TVD6375Current Status1-GAS10/15/2020UICNoDF7/20/2020 Electronic File: KU 24-32 - 5in Gas Ratio Log TVD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in LWD Combo Log MD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - 5in LWD Combo Log TVD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Drilling Dynamics Log MD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Drilling Dynamics Log TVD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Formation Log MD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Formation Log TVD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Gas Ratio Log MD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - Gas Ratio Log TVD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - LWD Combo Log MD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 - LWD Combo Log TVD.tif33563EDDigital DataDF7/20/2020 Electronic File: KU_24-32.dbf33563EDDigital DataDF7/20/2020 Electronic File: ku_24-32.hdr33563EDDigital DataDF7/20/2020 Electronic File: KU_24-32.mdx33563EDDigital DataDF7/20/2020 Electronic File: ku_24-32r.dbf33563EDDigital DataDF7/20/2020 Electronic File: ku_24-32r.mdx33563EDDigital DataDF7/20/2020 Electronic File: KU_24-32_SCL.DBF33563EDDigital DataDF7/20/2020 Electronic File: KU_24-32_SCL.MDX33563EDDigital DataDF7/20/2020 Electronic File: KU_24-32_tvd.dbf33563EDDigital DataDF7/20/2020 Electronic File: KU_24-32_tvd.mdx33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 7700a.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 7740-7770.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 7820.jpg33563EDDigital DataThursday, October 15, 2020AOGCCPage 5 of 8 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-133-20688-00-00Well Name/No. KENAI UNIT 24-32Completion Status1-GASCompletion Date6/11/2020Permit to Drill2200370OperatorHilcorp Alaska, LLCMD8155TVD6375Current Status1-GAS10/15/2020UICNoDF7/20/2020 Electronic File: KU 24-32 7820a.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 7860.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 sterling.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32_7950.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32_7950b.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32_7953.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32_7954.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 1792b.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 1792c.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 3000a.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 3000b.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 3000c.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 4290.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 4290a.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 4290b.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 4680.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 7660.jpg33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Gas Show Report 1 6975-7000.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Gas Show Report 2 7120-7145.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Gas Show Report 3 7170-7200.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Gas Show Report 4 7458-7472.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Gas Show Report 5 7605-7625.pdf33563EDDigital DataDF7/20/2020 Electronic File: KU 24-32 Gas Show Report 6 7675-7720.pdf33563EDDigital DataThursday, October 15, 2020AOGCCPage 6 of 8 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-133-20688-00-00Well Name/No. KENAI UNIT 24-32Completion Status1-GASCompletion Date6/11/2020Permit to Drill2200370OperatorHilcorp Alaska, LLCMD8155TVD6375Current Status1-GAS10/15/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:6/11/2020Release Date:4/17/2020DF7/20/2020 Electronic File: KU 24-32 Gas Show Report 7 7800-7820.pdf33563EDDigital DataDF9/10/20208052 1147 Electronic Data Set, Filename: KU_24-32_RBT_29MAY20_main.las33820EDDigital DataDF9/10/20208057 7764 Electronic Data Set, Filename: KU_24-32_RBT_29MAY20_repeat.las33820EDDigital DataDF9/10/2020 Electronic File: KU_24-32_RBT_29MAY20.pdf33820EDDigital DataDF9/10/2020 Electronic File: KU_24-32_RBT_29MAY20_img.tiff33820EDDigital DataDF9/10/2020 Electronic File: KU_24-32_RBT_29MAY20_main.dlis33820EDDigital DataDF9/10/2020 Electronic File: KU_24-32_RBT_29MAY20_repeat.dlis33820EDDigital Data0 0 2200370 KENAI UNIT 24-32 LOG HEADERS33820LogLog Header Scans7/6/20201800 81541745CuttingsThursday, October 15, 2020AOGCCPage 7 of 8 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-133-20688-00-00Well Name/No. KENAI UNIT 24-32Completion Status1-GASCompletion Date6/11/2020Permit to Drill2200370OperatorHilcorp Alaska, LLCMD8155TVD6375Current Status1-GAS10/15/2020UICNoComments:Compliance Reviewed By:Date:Thursday, October 15, 2020AOGCCPage 8 of 8M. Guhl10/15/2020 1 Winston, Hugh E (CED) From:Carlisle, Samantha J (CED) Sent:Wednesday, October 7, 2020 1:41 PM To:Winston, Hugh E (CED) Subject:FW: KU 24-32 (PTD 220-037) RBDMS please From: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Sent: Wednesday, October 7, 2020 1:39 PM To: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Cc: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov> Subject: RE: KU 24‐32 (PTD 220‐037) Todd, The AOGCC will withdraw sundry 320‐276 as requested. We are still vetting the new sundry you submitted a few days ago. The new sundry for KU 24‐32 has number 320‐416. Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Sent: Monday, October 5, 2020 8:50 AM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: KU 24‐32 (PTD 220‐037) Hello Guy, The AOGCC has just received for processing another sundry request for well KU 24‐32. Hilcorp requests to withdraw the current sundry for this well (320‐276) and replace it with this new submission. This new sundry includes the contents of 320‐276 along with a detailed CT remedial cement procedure and the addition of new lower Beluga intervals for perforating. Please let me know if you require any further information. Thanks, Todd Todd Sidoti | Kenai Ops Engineer | Hilcorp Alaska | 907‐632‐4113 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: CT, N2 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): Sterling 3 Gas & Sterling 4 Gas 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,155'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 8,730psi Liner 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: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 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 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: October 16, 2020 N/A 8,120' Perforation Depth MD (ft): See Attached Schematic 8,120' 7,027'5-1/2" 16" 7-5/8" 120' 1,784' 2,980psi 6,890psi 120' 1,695' 120' 1,784' N/A TVD Burst N/A 10,600psi MDLength Size 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL392668, FEE AA093808 220-037 50-133-20688-00-00 Kenai Unit (KU) 24-32 Kenai Gas Field - Beluga/Upper Tyonek Gas Pool - Tyonek Gas Pool 1 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com 7,057' 8,120' 7,027' 1365 psi N/A Swell Pkr, Perm Packer ; N/A ~1,400'MD / 1,361'TVD; ~6300'MD/4620'TVD; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:06 am, Oct 05, 2020 320-416 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.10.02 16:04:26 -08'00' Taylor Wellman Perforate Other: CT, N2 6,341 SFD 10/5/2020 SFD 10/5/20206.375 DSR-10/12/2020 SFD 10/5/2020 10-404 Plug Perforations gls 10/8/20 Change Approved Program X GAS (close sundry 320-225 also) * forward CBL results to AOGCC for review before perforating * 4000 psi BOPE test (CTU) * conditions set forth in sundry 320-225 still apply (14 day flow period limit without packer/tbg) CT Comm 10/13/2020 dts 10/12/2020 JLC 10/13/2020 Well Prognosis Well: KU 24-32 Date: 10-2-2020 Well Name: KU 24-32 API Number: 50-133-20688-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: 10/16/2020 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-037 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: 2011534C Maximum Expected BHP: ~ 1,755 psi @ 3,900’ TVD (Based on 0.45psi/ft gradient) Max. Potential Surface Pressure: ~ 1,365 psi @ 3,900’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KU 24-32 is a grass roots development well targeting gas sands in the Upper Tyonek and Middle and Upper Beluga formations. This new well TD was reached on 5-11-2020. Hilcorp has been perforating the sands approved in Sundry 320-225, and has not yet found commercial hydrocarbons. In addition, the CBL indicates that top of cement is at ~5600’. In order to continue moving uphole adding perforations it will be necessary to perform a remedial cement squeeze job with coiled tubing. The purpose of this work/sundry is to perform a remedial cement job with coiled tubing, add two additional zones in the Beluga pool 5 interval, and add contingency perforation intervals in the Sterling sands. These zones would be tested for up to 14 days per zone to confirm commercial zones are encountered before running the completion approved in Sundry 320-225, with the 2-7/8” tubing packer moved above these new perforations and set at +/- 4800’ MD. Notes Regarding Wellbore Condition x Well has been blown down with N2. x CIBP’s have been set above non-commercial sands as approved in 320-225. x AOGCC has a CBL on file. Coiled Tubing Remedial Cement 1. MIRU CTU Unit. Pressure test BOPs to 250 psi low / 4,000 psi high. 2. RIH with BHA including 4.4” JSN (setting tool OD is 4.380” and retainer OD is 4.30”) and drift to CIBP. Paint flag on coil for retainer set. 3. RIH with BHA including one-trip 5-1/2” cement retainer. Set retainer at ~5,330’. 4. Fill up CT x TBG backside and test retainer to 500 psi. 5. With the CT x TBG backside shut in and the IA (casing valve) open to tanks, establish baseline injectivity pressures and rates down the CT. If injectivity is lower than 0.5 BPM at 2500 psi contact Operations Engineer. 6. Pump the following down CT: a) 5 bbl freshwater spacer b) 30 bbls 13 ppg FineCem c) 5 bbl freshwater spacer d) Displacement fluid to get cement to the perforations 7. Once cement is at the perforations and before attempting to attain squeeze pressure on the well, attempt to circulate 7 bbls of cement behind pipe. Monitor IA return tank during the initial 7 bbls in order to determine if there is any IA displacement. 8. Once 7 bbls are away attempt for a squeeze pressure of 1000 psi for 30 minutes. cement sqz (IA pressure test still failing ... gls) (top perf 5360 ft md) (TOC approx 5600 ft) Hilcorp has been perforating the sands approved in Sundry 320-225, and has not yet found commercial hydrocarbons. In addition, the CBL indicates that top of cement is at ~5600’. In order to continue moving uphole adding perforations it will be necessary to perform a remedial cement squeeze job with coiled tubing. (Swell packer still leaks per Hilcorp) New packer depth... NOTE---> Well Prognosis Well: KU 24-32 Date: 10-2-2020 9. If after 20 bbls away formation seems to be drinking all of the cement and we are unable to establish any returns contact operations engineer to discuss hesitation parameters. 10. Once squeeze is achieved, un-sting from retainer and lay in remaining volume of cement in tubing. 11. Open CT x TBG backside and circulate gel for contamination to the stinger. Contaminate cement to top of retainer and POOH. 12. WOC until next morning, check field blend report and samples to ensure that cement has reached at least 500 psi of compressive strength. 13. RIH with BHA including motor and junk mill. Mill up composite cement retainer, cement and CIBP @ 5450’ and push to plug at 6532’. Flag pipe for logging run and POOH. 14. RIH with BHA including memory CBL and log from 6000’ to 1000’. 15. Blow down tubing with N2. 16. POOH W/ coil. Leave 1,000 psi trapped on tubing. RDMO CT. E-Line Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 3000 psi Hi 250 Low. 2. PU RIH W/perf guns. Perforate each interval with 3-1/8” or 3-3/8” Perf guns 6 SPF 60 degree phasing. 3. Proposed Perforated Intervals: 4. Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom P3_A8 ±4,987' ±5,033' 46' ±3,691' ±3,737' P3_A9 ±5,050' ±5,065' 15' ±3,732' ±3,747' P3_A10 ±5,100' ±5,165' 65' ±3,765' ±3,830' P3_A 11 ±5,204' ±5,264' 60' ±3,832' ±3,892' P4_B1 ±5,306' ±5,394' 88' ±3,900' ±3,988' P5_B3 ±5,515’ ±5,532’ 17’ ±4,034’ ±4,051’ P5_B4 ±5,739’ ±5,769’ 30’ ±4,188’ ±4,218’ a) Final Perfs tie-in sheet will be provided in the field for exact perf intervals. b) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c) Use Gamma/CCL to correlate. d) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. e) These sands are governed by Conservation Order 510A. f) Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. N2 may be employed to depress the fluid level prior to plugging work. 5. POOH. RD e-line. 6. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing). 7. Completion approved in Sundry 320-225 must be ran after no more than 14 days of testing to confirm commercial hydrocarbons. governed by Conservation Order 510A. CBL (memory) (forward CBL log to AOGCC. ) Note new packer depth at 4800 ft , gls 10-12-20 Well Prognosis Well: KU 24-32 Date: 10-2-2020 Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil Tubing BOP 4. SOP for Nitrogen Operations Updated by CJD 09-22-20 SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = 5,450’ MD / TVD = 3,993’ TD = 8,155’ MD / TVD = 6,375’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P4 B1 5,360’ 5,380’ 3,934’ 3,947’ 20’ 6/26/2020 Open 3-3/8” UB 1X 6,556' 6,562' 4,842’ 4,847’ 6' 6/24/2020 Isolated 3-3/8” 6,573' 6,579' 4,857’ 4,862’ 6' 6/24/2020 Isolated 3-3/8” UB 2 6,632' 6,640' 4,909’ 4,917’ 8' 6/23/2020 Isolated 3-3/8” 6,666' 6,686' 4,940’ 4,957’ 20' 6/11/2020 Isolated 3-3/8” MB 6 7,685' 7,695' 5,912’ 5,922’ 10' 6/11/2020 Isolated 3-3/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 Hyd 563 6.875” Surf 1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf 8,121’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,397’ 4.892” 6.35” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 160 BBL’s of cement in 9-7/8” hole – 24 bbls Returns to surface 5-1/2” 146 BBL’s of cement in 6-3/4” hole. CBL TOC @ ~5,600’ 6-3/4” hole UB 2 MB 6 5-1/2” Evo- Trieve plug set at 7600’ UB 1X TOC @ 5600’ from CBL P4 B1 5-1/2” CIBP set at 6655’ 5-1/2” CIBP set at 6610’ UB 2 5-1/2” CIBP set at 6532’ 5-1/2” CIBP set at 5,450’ retainercmt sqz Updated by TCS 09-24-20 PROPOSED SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = 5,450’ MD / TVD = 3,993’ TD = 8,155’ MD / TVD = 6,375’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P3 A8 ~4,987’ ~5,033’ ~3,691’ ~3,737’ 46’ TBD - P3 A9 ~5,050’ ~5,065’ ~3,732’ ~3,747’ 15’ TBD - P3 A10 ~5,100’ ~5,165’ ~3,765’ ~3,830’ 65’ TBD - P3 A11 ~5,204’ ~5,264’ ~3,832’ ~3,892’ 60’ TBD - P4 B1 5,360’ 5,380’ 3,934’ 3,947’ 20’ 6/26/2020 Squeezed P5 B3 ~5,515’ ~5,532’ ~4,034’ ~4,051’ 17’ TBD - P5 B4 ~5,739’ ~5,769’ ~4,188 ~4,218’ 30’ TBD - UB 1X 6,556' 6,562' 4,842’ 4,847’ 6' 6/24/2020 Isolated 3-3/8” 6,573' 6,579' 4,857’ 4,862’ 6' 6/24/2020 Isolated 3-3/8” UB 2 6,632' 6,640' 4,909’ 4,917’ 8' 6/23/2020 Isolated 3-3/8” 6,666' 6,686' 4,940’ 4,957’ 20' 6/11/2020 Isolated 3-3/8” MB 6 7,685' 7,695' 5,912’ 5,922’ 10' 6/11/2020 Isolated 3-3/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 Hyd 563 6.875” Surf 1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf 8,121’ TUBING DETAIL 2-7/8” Production 6.4 L-80 8 RD EUE 2.441” Surf ±4,830’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,397’ 4.892” 6.35” Swell Packer 2 ~4,800 2.33” - 5-1/2” Production Packer 3 ~4,810 2.313” - 2-7/8” X-Nipple OPEN HOLE / CEMENT DETAIL 7-5/8" 160 BBL’s of cement in 9-7/8” hole – 24 bbls Returns to surface 5-1/2” 146 BBL’s of cement in 6-3/4” hole. CBL TOC @ ~5,600’ 6-3/4” hole UB 2 MB 6 5-1/2” Evo- Trieve plug set at 7600’ UB 1X TOC @ 5600’ from CBL P4 B1 5-1/2” CIBP set at 6655’ 5-1/2” CIBP set at 6610’ UB 2 5-1/2” CIBP set at 6532’ Remedial TOC P5 B4 P5 B3 P3 A11 P3 A10 P3 A9 P3 A8 X 2 3 cement sqz (sqz'd) (sqz'd) relog CBL from 6532 ft (post sqz) Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Swanson River Field SRU 241-33 6/10/2020 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or Aband.: 3. Address: 7.Date Spudded: 4a. Location of Well (Governmental Section): 8. Date TD Reached: Surface: Top of Productive Interval: 9.Ref Elevations: KB: 17.Field / Pool(s): Kenai Gas Field GL: 59.3' BF: 59.3' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 16" X-56 120' 7-5/8" L-80 1,629' 5-1/2" L-80 6,342' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour RateN/A May 10, 2020 May 1, 2020 ADL392668, FEE AA093808 N/A N/A N/AN/A N/A 8,155' MD / 6,375' TVD ROP, DGR, AGR, ABG, ADR, EWR MD & TVD, Mudlog, Geotap CBL 5-24-20 Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: N/A N/AN/A Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/AN/A N/A ** Please see attached schematic for perforation detail ** N/A Water-Bbl: PRODUCTION TEST N/A Date of Test: N/A N/A N/A Flow Tubing N/A 84# 29.7# 120' Surface 8,121' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 17#Surface DEPTH SET (MD) 1,397' Swell Pkr (5-1/2") PACKER SET (MD/TVD) Surface CASING WT. PER FT.GRADE 274096 275266 TOP SETTING DEPTH MD Surface SETTING DEPTH TVD 2368465 BOTTOM TOP 6-3/4" 24 bbls Surface 9-7/8" HOLE SIZE AMOUNT PULLED KU 24-32 270794 2368250 1098' FSL, 1457' FWL, Sec 32, T5N, R11W, SM, AK CEMENTING RECORD 2368390 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 6/11/2020 898' FSL, 1835' FEL, Sec 31, T5N, R11W, SM, AK 1195' FSL, 2626' FWL, Sec 32, T5N, R11W, SM, AK Permit to Drill Number / Sundry: 037 / 320-225 API Number: 133-20688-00-00 Well Name and Number: ΋ϋϒϛύχͿΞϖϖϋϘΝϟϕϔϋϑΐΙͥΜϚϋϘϒϏϔύΞϔϊϋόͥΝϟϕϔϋϑΐχϙ 77.3' 5,450' MD / 3,993' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas Driven Surface 1,784' L- 275 sx / T - 175 sx Driven L - 295 sx / T - 85 sx N/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD WINJ SPLUGOther Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 9:32 am, Sep 22, 2020 Completion Date 6/11/2020 HEW RBDMS HEW 9/23/2020 GSFD 9/24/2020 DSR-9/24/2020gls 10/15/20 / 320-276 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval 5,360' (Top Perf Non- productive) 3,978' (ST P4 B1) 4,422' 3,323' 5,296' 3,892' 6,590' 4,871' 6,627' 4,904' 6,715' 4,982' 6,967' 5,214' 7,452' 5,681' 7,636' 5,862' 7,767' 5,991' 7,908' 6,131' Mid Beluga 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange 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. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). MB 7 MB 9 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. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. MB 6 Formation at total depth: UB 1X Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports. Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS 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. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME MB 4 UB 2 ST P3 A3 ST P4 B1 This form and the required attachments provide a complete and concise record for each well drilled 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. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager UB 3A UB 6 Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 9.22.2020Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.09.22 09:25:39 -08'00' Monty M Myers Updated by CJD 09-22-20 SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = 5,450’ MD / TVD = 3,993’ TD = 8,155’ MD / TVD = 6,375’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status/Size P4 B1 5,360’ 5,380’ 3,934’ 3,947’ 20’ 6/26/2020 Open 3-3/8” UB 1X 6,556' 6,562' 4,842’ 4,847’ 6' 6/24/2020 Isolated 3-3/8” 6,573' 6,579' 4,857’ 4,862’ 6' 6/24/2020 Isolated 3-3/8” UB 2 6,632' 6,640' 4,909’ 4,917’ 8' 6/23/2020 Isolated 3-3/8” 6,666' 6,686' 4,940’ 4,957’ 20' 6/11/2020 Isolated 3-3/8” MB 6 7,685' 7,695' 5,912’ 5,922’ 10' 6/11/2020 Isolated 3-3/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 Hyd 563 6.875” Surf 1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf 8,121’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,397’ 4.892” 6.35” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 160 BBL’s of cement in 9-7/8” hole – 24 bbls Returns to surface 5-1/2” 146 BBL’s of cement in 6-3/4” hole. CBL TOC @ ~5,600’ 6-3/4” hole UB 2 MB 6 5-1/2” Evo- Trieve plug set at 7600’ UB 1X TOC @ 5600’ from CBL P4 B1 5-1/2” CIBP set at 6655’ 5-1/2” CIBP set at 6610’ UB 2 5-1/2” CIBP set at 6532’ 5-1/2” CIBP set at 5,450’ IA will not test set 6/26/20 set 9/10/20 NOTE: packer /tubing not run yet due to no commercial gas yet. See sundry 320-416 NOTE: lost 318 bbls during 5 1/2" cement job. Activity Date Ops Summary 4/26/2020 No activity / Accept Rig on restricted rig move f/ CLU-15 AFE# 2010186D t/ KU-24-32 AFE# 2011534D @ 1200 hrs;Continue R/dn TDS / Fold over skate remove Bops w/ crane and secure in transport (Inspect annular elemont) continue work crane and start removing wind walls. R/D stand pipe manifold, removed centrifuge from stand w/ crane, disconnected HYD lines from rig floor, R/D electrical cables in;derrick, unbolted T-bar from TQ tube& removed bottom section of TQ tube, removed spools from sub & cleaned, R/D utility hoses from rig. Continue build load move stage @ KGF.;R/D steam heater around rig, secure derrick & scoped down, R/D jumper lines, lights, & static line. lowered roof on module #3 and secured, R/D cuttings box & removed 10'x10' conex off pit module #3, R/D choke manifold to pits, Gai tronics, & equalizer lines between mud pits.;R/D electrical lines cables between sub & dog house, removed tarps around pits, R/D Total Safety gas alarm equip. unspooled drill line from DWK, secured drill line, service loop, Geronimo line, derrick assist to derrick, held PJSM, laid derrick over, R/D dead man, koomey lines, and blew down;boiler, R/D boiler, water line, & fuel lines to MP. R/D electrical cables in pits, R/U pressure washer in sub base & cleaned cellar, R/D lift winches & removed from sub, R/D Pason cables, R/D drive line between dog house & sub, and brake linkage. Cont. to build loads and stage @ KGF.;Held PTSM, crew change, worked on general housekeeping in prep for trucks, washed down mast, houses, and pit sides, R/D vibrator lines & TD HPU lines. R/D catwalk & Handy berm, lower roof on pit module #2, raised pit to pump walkways, bleed off 7 disconnected all air lines,;disconnected HYD & electrical lines from mast and secured, disconnected MP suctions lines. R/D & tied up TD HPU.;Hauled 0 bbls solids to KGFG&I Cumulative 0 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 0 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 0 bbl 4/27/2020 Continue demobe / lay felt and liner and set few mats we have to hold liner in place @ KU-24-32 / Spot cranes Remove cat walk and load out @ 85% w/ jeep and booster and move and stage same to t/ KGF pad 34-31 , Load out, move and stage pre-mix tank @ same 85% Load out move gas buster & misc;Move pit module #2 and stage same , remove derrick board and dog house move HPU module remove choke house remove excess fuel from rig / remove pit# 1 roof section remove shaker beds and load move stage same / remove load out stage gen set module / remove boiler and stage for repair;Load out need rig matts / Remove and load out stage pit #1 / remove and stage both mud pumps / clean liner dress new shaker bed./ stick pick and police location / welder remove air boot and install hammer seal on mud pump suction.;Un-pined derrick, picked w/ crane & loaded on trailer w/ drill line spool & sent to KU 24-31, picked carrier from sub w/ crane, load on trailer & hauled to KU 24-31, picked sub base w/ crane & loaded on trailer, parked trailer at edge of location to be moved @ 04:00 hrs.;Loaded remaining rig mats & pony subs & hauled to KU 24-31, cleaned & disposed liner & felt, back bladed pad, hand rig hand clean up trash & sticks on edge of road into pad. Cont. cleaning around pad & loading misc. equip. & items.;Held PTSM, crew change, cont. w/ location & entrance road walk around P/U trash, inspected drilling, screen, rig, & spill conexs, staged, loaded & hauled to KGF. made template gaskets for possum belly ditch, cleaned safety shack & production meeting room,;Sent most of crew to KU 24-32 to spot & squared pony subs on mats over well KU 24-31, set iron roughneck HPU inside pony sub, removed grating & installed 13.5" test plug , stood hand rails on sundeck & choke house.;Had Peak rig moving crew on location @ 04:00 hr. hauled of sub to KU 24-32, cont. working on loading misc. items and cleaning around pad w/ most of the rig crew working on KGF pad 34-31.;Hauled 0 bbls solids to KGFG&I Cumulative 0 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 0 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 0 bbl 4/28/2020 Continue rig move : R/up / spot cranes and set sub / set dwk skid / Set pin derrick and board / Set koomey/water tank module / Set pit #1,#2 & #3 modules / Set Dog house / Re-hang bridge cranes / Set gen/MCC module / Set TDS HPU module and work on r/up of all;Move Both MP modules from CLU Pad #3 @ 85% w/ jeep and booster and move and set same @ 24-32 / Set old shaker and new shaker bed and work on dressing out other new shaker bed and set same continue r/up modules and re assemble shaker possum bellys;Raise and pin derrick / Set choke house / Set gen #3 / Move Boiler from CLU Pad #3 and stage same / Set out building X3 / Hang wind walls / set both MP modules / Set gas buster skid / set boiler / set axillary fuel tank / Continue r/up all modules;Continue R/U modules, Spool on drilling line, prep to scope derrick, secure torque tube, Install vent line and raise gas buster, organize pad and connexes, build docks and pipe laydown area;Make up second section of torque tube and scope derrick, prep top drive, sling to floor M/U t/ blocks remove from shipping cradle, hang in derrick, continue R/U modules, continue hooking up modules, take on water to rig tank;Hauled 0 bbls solids to KGFG&I Cumulative 0 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 0 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 0 bbl n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: KEU KU 24-32 Kenai Gas Field Hilcorp Energy Company Composite Report Kenai, Alaska Contractor AFE #: AFE $: Hilcorp 169 Job Name:2011534D KU 24-32 Drilling Spud Date: 4/29/2020 Finish R/U top drive and service lines, orient service loop, welders working on cellar grating, N/U 16'' riser flow nipple, R/U flow line, welder working on suction lines between hopper house and pump room, also shakers extensions / Move camp trailers, offices chg room and mech shack f/ CLU pad #3.;t/ KGF- pad 34- 31 Spot same r/up and power up and establish commutations / Berm in rig and take on fuel / continue pad organization / set water tank and cmt silo / Re load pump room w/ parts tools and equipment / r/up hurricane vacuum / Take on water to test valves suction and PVTs.;Continue R/U modules, Work on rig acceptance checklist, continue rolling water through pits checking function of valves, hook up suction lines to pumps, flood lines check for leaks, organize connexes and c cans.;Continue working on rig acceptance checklist, function test mud pumps, flush through lines, test mud lines t/ 2500 psi, function test top drive, continue cleaning and organizing pad and rig, rebuild 4'' valve on MP#2, change out pop off on #1.;Hauled 0 bbls solids to KGFG&I Cumulative 0 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 0 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 0 bbl 4/30/2020 Continue working on rig acceptance checklist, Continue cleaning and organizing pad and rig, finish rebuild 4'' valve on MP#2, change out pop off on #1/ finish welding API rings on suctions of tanks of Pit modules #1.;Lost bearing in trip tank pump, pull pump and rebuild same / #1 pulsation dampener bladder flat, pull same, poor boy screen broken again / set crane and pull complete pulsation dampener body and remove old ate out screen attempt install new screen (loose body ate out).;Retrieve Hak #1 pulsation dampener / R/up Sperry / R/up mud loggers / r/up tested total safety gas detection system / Took on fuel / Installed Hak#1 pulsation dampener and charge same while testing trip tank pump (ok).;Test Mud line and pulsation damper t/ 2500 psi with both mud pumps, Blow down top drive, Pull test plug set wear ring, install wrap around riser to keep splash down.;P/U 4.5'' Dp Stand back in the derrick total footage 2604', P/U HWDP and Jar Stand, P/U 6'' Flex Collars.;M/U BHA as per detail t/120', Upload MWD, load sources.;Hauled 0 bbls solids to KGFG&I Cumulative 0 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 0 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 0 bbl 5/1/2020 Continue Upload MWD @ 120' and M/up XO Spud well @ 07:00 hrs / drill f/ 130' t/ 180' survey on btm / pooh rack back Hwdp ./ PJSM p/up load sources / P/up flex collars / chase shaker power issue and centrifuge feed pump issue.;Drill f/ 180' t/ 302' ease up flow rate getting bad data from ADR attempt mode switch.;start Kick off and drill f/ 302' t/363' (still getting bad real time data) from ADR attempt mode switch again w/ no luck ( discuss options w/ town) Production Mike Morgan preformed Visible emission of boiler #1 Hak rig #169, R/up other centrifuge feed pump.;Pooh f/ 363' L/dn Bha #1 / PJSM pull sources / crew change / l/dn flex collar / dn load and l/dn ADR/ PWD/ DGR / chk bit (green) trouble shoot trip tank pump issue / pull trip tank pump found impeller case bolts stripped tap and install next sized larger bolts reinstalled tested ok.;P/up Bha #2 w/ RR bit 1 and new ADR/ PWD/DGR Up load tools rih and test tools @ 150' air boot failed on flow nipple and chg out same Test tools SPP 650 psi @ 370 GPM ok / load nukes.;RIH w/ BHA#2 t/ 321' Wash and ream last stand to bottom @ 363' Establish Parameters 450 gpm 1150 psi.;Drill Ahead f/ 363' t/ 1795' 450-500 gpm 1550 psi 70 RPM 5.5k tq on 4k off 44k PUW 39k SOW 41k ROT MW 9 ppg, sliding for direction following WP #4 Distance to plan 19.56' Low 18.32' Right 6.86'.;Circulate 18 bbls Hi Vis Sweep around 500 gpm 1650 70 rpm 5.7k, no increase in cuttings on return.;Hauled 160 bbls solids to KGFG&I Cumulative 160 bbls Hauled 160 bbls fluid to KGF G&I Cumulative 248 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 0 bbl 5/2/2020 Cycle pumps and preform Mode switch for ADR Due to pulse detection issues.;Orient and Pump ooh to mad pass top section where ADR failed f/ 1795' t/ 1424' w/ no issue GEO called and wants mad pass all slides areas Rih w/ no issue t/ 1775'.;Pooh mad passing slide areas f/ 1795' t/ 1233' @ 240 fph and 40 rpms and 470 gpm @ 1350 psi / Pump out 3 std t/ 1013' mad pass t/ 984' Pump out 2 std t/ 865' mad pass t/ 737' Pump out t/ 710' mad pass t/ 675' Pump out t/ 441' mad pass t/ 208'.;L/dn jars / rack back HWDP, L/D Flex Collar unload sources, Download MWD, L/D Remaining BHA, break bit Clean and clear rig floor, Pulled wear ring.;R/U to run casing, dummy run hanger and landing jt, R/U weatherford casing equipment, load pipe on racks.;PJSM Run 7 5/8'' Casing as per detail installing centralizers every other jt, Filling every jt on the fly topping off every 5 jts, checked floats held, RIH t/ 1784', M/U landing jt and Hanger and land on hanger.;R/U circulating equipment stage pumps t/ 6 bpm, spot in halliburton cementers and R/U cement lines, had 2 gallon spill from loader, cleaned up spill.;R/U Halliburton Cement head and circulating lines, PJSM with cementers.;PT Lines t/ 900 psi low, 4000 psi High, Pump 42 bbls 10.5ppg spacer @ 4.5 bpm 90 psi, Drop Bottom Plug, Pump 120 bbls 12 ppg 275 sx Lead cement @ 5 bpm 140 psi, Pump 40 bbls 175 sx 15.8ppg Tail Cement @ 4.5 bpm.;175 psi, Spacer seen back to surface 17 bbls of tail cement away, Drop Top Plug, Displace w/ Spud Mud.;Hauled 120 bbls solids to KGFG&I Cumulative 280 bbls Hauled 130 bbls fluid to KGF G&I Cumulative 378 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 0 bbl / drill f/ 130' t/ 180' survey on btm / gp pp p ;M/U BHA as per detail t/120', Upload MWD, load sources.;Hauled 0 bbls solids to KGFG&I Surface casing cement job (7 5/8") Spud well Continue working on rig acceptance checklist, p@ psi.;Drill Ahead f/ 363' t/ 1795' 450-5 pgpp , PJSM with cementers.;PT Lines t/ 900 psi low, 4000 psi High, Pump 42 bbls 10.5ppg spacer @ 4.5pgppgpppg p @ bpm 90 psi, Drop Bottom Plug, Pump 120 bbls 12 ppg 275 sx Lead cement @ 5 bpm 140 psi, Pump 40 bbls 175 sx 15.8ppg Tail Cement @ 4.5 bpm.;175 psi, p p p g p ppg @ p p p ppg Spacer seen back to surface 17 bbls of tail cement away, Drop Top Plug, Displace w/ Spud Mud.;Hauled 120 bbls solids to KGFG&I g Run 7 5/8'' Casing as per detail ppp Rih w/ no issue t/ 1775'.;Pooh mad passing slide areas f/ 1795' t/ 1233' 5/3/2020 Halliburton continue displace w/ 9.0ppg spud mud bump plug 1-1/2 bbls early @ 76.5 bbls away w/ 450 psi FCP held pressure 5 min bled off 1-1/4" bbls floats held / both lead and tail cmt had 1/4 ppb LCM / C.I.P @ 06:20 hrs / lost 26 bbls total during job / got back 42 bbls of colored spacer and;24 bbls of 11.5 ppg cmt.;R/dn cmt head and lines wash up blow dn lines monitor slight losses t/ well head +- 2.5 bph / wash out flow nipple and flow line w/ black water and rinsed clean.;B/O and pull landing jt / m/up and set pack-off and Run in lock dn screws and test pack-off seal t/ 5000 psi for 5 min ok.;Wash up and N/dn 16" flow nipple remove 4" valves install cap one side and port on other / cleaning pits.;Wash up cellar and well head / prep both starting head and "B" section of well head and nip/up same attempt test pack off void chg/out gauge ) test 500L 5min and 5000H 15min good / continue nip/up and crew chg.;Continue N/U BOP's, R/U Flow box and Riser, Air up boots, hook up choke and kill lines hook up Hydraulic lines and function test, set test plug, fill stack and lines with water, set test plug, Shell Test Stack t/ 250/3500 psi, continue cleaning pits.;R/U and P/U Excess Drill Pipe, RIH POOH Standing back DP 40 stands P/U total transfer HWDP to driller side.;Hauled 45 bbls solids to KGFG&I Cumulative 325 bbls Hauled 610 bbls fluid to KGF G&I Cumulative 988 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 26 bbls Total losses to hole 26 bbl 5/4/2020 Rig service grease and inspect linkages, Drive shafts, draw works, crown, blocks, and TDS and strap pipe. welder work on projects and repairs, shelves in conex.;Resume DP management / P/U rabbit strap 4-1/2" CDS-40 16.6# S-135 Drill Pipe and racking back same for total of 8060.86' of DP rack back / continue weld work / R/up geo-span / test gas alarms Ok.;Pull wear ring / set test plug / r/up test equipment / fill stack and lines purge air.;Test BOP's w/ 4.5'' test jt as per regulations, state inspector Jim Regg Waived witness.;R/D BOP test Equipment R/U to test Casing.;Test casing t/ 2500 psi f/ 30 min on chart good test, R/D Blow down test equipment and lines.;P/U Drilling BHA # 3 as per DD/MWD, Shallow test tools, 250 gpm 1350 psi, Load sources continue RIH w/ BHA t/ 698' Single in the hole w/ 20 jts t/ 1315'.;Service Rig and Top Drive.;Hauled 0 bbls solids to KGFG&I Cumulative 325 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 988 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 26 bbls Total losses to hole 26 bbl 16" X 7-5/8" = 0 psi 5/5/2020 Rih w/ 5 std from DS tagged up @ 1665' circ clabbered mud cmt.;Continue wash ream clabbered mud /cmt t/ 1697' Ream dn tag up on plugs on Float collar as per csg tally drilled both plugs and float collar and cmt t/ 1782' w/ clabbered mud.;Displace clabbered spud mud w/ 9.0 ppg PHPH water base mud.;Drill out shoe as per csg tally f/ 1782' and cleaned out rat hole t/ 1795' and 20' new formation t/ 1815'. WOB 1-2K, 255 gpm-1050 psi, 40 rpm.;RU test equipment for FIT. Purged air, pumped 39.8 gallons to achieve 403 psi with 9.0 mud, for a 13.5 ppg EMW. Pressure bled down to 181 psi over 10 min, bled back 29.4 gallons, RD test equipment.;Resumed directional drilling 6 3/4" production hole from 1815’ to 2288'. rot wob 1-3K, 254 gpm-1097 psi, 80 rpm-5099 ft/lbs on bott torque, 150 ft/hr ROP. Sliding wob 2K, 254 gpm-1158 psi, 122 psi diff, 300 ft/hr ROP. MW 9.0/vis42, ECD’s at 9.8 ppg, BGG 6 units. Drilling in Sterling formation 80%.;sand, 20% clay. HSE Rep Matt Hogge RU silica monitoring devices to be worn by any hands mixing mud products or working in vicinity of hopper areas. Peak rig support serviced and ran trailer mounted water tank for dust control around rig site.;Cont drilling 6 3/4" hole from 2288' to 2928', (pumped 20 bbl hi-vis sweep at 2324', back 300 strokes late and a 5% increase in cuttings), 275 gpm 1351' 70 RPM 5.8k tq on 4.5k off 50 PUW 34 SOW 40 ROT 9.05 ppg MW 9.8 ppg ECD.;Pull wiper trip f/ 2928' t/ 1874' No Hole issues,pulled on elevators hole took correct fill calc 7.8 bbls Act 10.1 bbls Didn't see anything pulling into shoe.;Service rig and top drive 1.5 bph static loss rate.;RIH f/ 1874' t/ 2928' No Hole issues.;Drill Ahead f/ 2928' t/ 2945' 266 gpm 1260 psi 70 rpm 5.8k tq on 4.5k tq off 50k PUW 34k SOW 44K ROT Pump Hi Vis sweep Around MW 9.05 ppg ECD 9.85 ppg Distance to plan 6.66' 5.24' Above 4.12' Left.;Hauled 67 bbls solids to KGFG&I Cumulative 392 bbls Hauled 518 bbls fluid to KGF G&I Cumulative 1506 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 26 bbl 16" X 7-5/8" = 0 psi 5/6/2020 Cont drilling 6 3/4" production hole from 2945’ to 3480', Rot wob 2K, 261 gpm-1216 psi, 75 rpm-6100 ft/lbs on bott torque, 150 ft/hr ROP, MW 9.0/vis 48, ECD’s at 9.7 ppg, BGG 6 units, max gas 24 units. 20 bbl hi-vis sweep back 12 bbls late with no increase in cuttings.;Received 90 joints 5 1/2" casing, racked same and drifted.;Cont drilling 6 3/4" production hole from 3480' to 3918', Rot wob 1-3K, 259 gpm-1324 psi, 70 rpm-6700 ft/lbs on bott torque, 150 ft/hr ROP, MW 9.0/vis 48, ECD’s at 9.8 ppg, BGG 6 units, max gas 33 units. Received 45 more joints 5 1/2" casing, racked same and started drifting.;CBU at 260 gpm-1235 psi, 80 rpm-8000 ft/lbs off bott torque. Obtained survey and SPR's.;Pulled 17 stand wiper trip on elevators from 3918' to 2863', up wt 62K.;Serviced rig and topdrive. Static loss rate during rig service = 3 bph. Strapped 135 joints 5 1/2" casing.;TIH on elevators from 2863' to 3908', down wt 44K. No Hole issues.;Pump Hi Vis Sweep Drill Ahead f/ 3918' t/ 4230' 265 gpm 1500 psi 70 rpm 7.9k tq on 8 k tq off 9.05 ppg MW 9.99 ppg ECD PUW 67k SOW 39k ROT 49k avg gas 19 units Max gas 51 units.;Drill Ahead f/ 4230' t/ 4724' 260 gpm 1400 psi, 70 RPM 8.8k tq on bottom 8k tq off, 9.0 ppg MW 9.92 ppg ECD, PUW 68k SOW 44k ROT 50k, Distance to plan 6.5' 6.17' above 2.03' right, Max Gas 74 units, avg. 13 units Background gas.;Hauled 92 bbls solids to KGFG&I Cumulative 484 bbls Hauled 308 bbls fluid to KGF G&I Cumulative 1814 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 72 bbls Total losses to hole 98 bbl 16" X 7-5/8" = 0 psi FIT 13.5 p ;Test casing t/ 2500 test equipment for FIT. pgy Purged air, pumped 39.8 gallons to achieve 403 psi with 9.0 mud, for a 13.5 ppg EMW. air.;Test BOP's w/ 4.5''pg p g test jt as per regulations, state inspector Jim Regg Waived witness. MIT casing 2500 psi p , Shell Test Stack t/ 250/3500 Halliburton continue displace w/ 9.0ppg spud mud bump plug 1-1/2 bbls early @ 76.5 bbls away w/ 450 psi FCP held pressure 5 min bled off 1-1/4" bbls floats pppgp ppg y@ yp p held / both lead and tail cmt had 1/4 ppb LCM / C.I.P @ 06:20 hrs / lost 26 bbls total during job / got back 42 bbls of colored spacer and;24 bbls of 11.5 ppg 5/7/2020 Cont drilling 6 3/4" hole from 4724' to 4912', rot wob 3K, 259 gpm-1473 psi, 70 rpm-8356 ft/lbs on bott torque, 125-150 ft/hr ROP, MW 9.0/vis 51, ECD's at 9.9 ppg, BGG 17 units, max gas 53 units.;CBU at 274 gpm-1459 psi, 80 rpm-9000 ft/lbs off bott torque. Obtained survey and SPR's.;Pulled up hole 17 stands from 4912' to 3860', on elevators with no issue. Up wt 74K. Calculated hole fill = 8.4 bbls, acual hole fill = 5.3 bbls.;Serviced rig, topdrive and centrifuge while monitoring well on trip tank. Loss rate at 1 bph.;TIH from 3860' to 4850' on elevators with no issue. Down weight 42K. Filled pipe and washed last stand to bottom.;Started sweep down drill string and resumed drilling ahead from 4912' to 5049', rot wob 2-3K, 276 gpm-1515 psi, 60 rpm-9300 ft/lbs on bott torque, 150 ft/hr ROP, MW 9.1/vis 55, ECD’s at 10 ppg, BGG 11 units, max gas 124 units. Sweep back on time with 25% increase in cuttings. Strapped all casing.;Cont drilling from 5049' to 5446', rot wob 2-3K, 275 gpm-1584 psi, 60 rpm-9300 ft/lbs on bott torque, 150 ft/hr ROP, sliding wob 2K, 266 gpm-1594 psi, 244 psi diff, 185 ft/hr ROP, MW 9.1/vis 53, ECD's at 10.1 ppg, BGG 11 units, max gas 169 units. At 5409' after drilling stand down, just started;backreaming stand and had a sudden loss of 13 bbls, reduced pump rate to 247 gpm and cont with connection/drilling ahead, also increased background LCM to 30 ppb.;Cont drilling from 5446' to 5904' 265 gpm 1595 psi 70 rpm 9.8k tq on 8.8k tq off 9.1 ppg MW 10.3 ppg ECD, max gas 131 units 74k PUW 43k SOW 53k ROT.;Circulate bottoms up 275 gpm 1580 psi, get SPR's and Survey f/ MWD, Pump up sample f/ Mud loggers.;Short trip f/ 5904' t/ 4854' No hole issues observed calc. 7.3 bbls act 7.1 bbls.;Service rig and top drive, change grabber dies, Static loss rate 1.5 bph.;RIH f/ 4854' t/ 5904' no hole issues observed, Calc 20.4 bbls act 15.3 bbls.;Drill Ahead f/ 5904' t/ 5985' 260 gpm 1610 psi, 60 rpm 9.8 k tq on 8.7k tq off 2-5k, WOB 72k, PUW 42k SOW 53k ROT, MW 9.1ppg ECD 10.26ppg, Distance to plan 5.45' 1.45' Above 7.08' left.;Hauled 108 bbls solids to KGFG&I Cumulative 592 bbls Hauled 272 bbls fluid to KGF G&I Cumulative 2086 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 97 bbls Total losses to hole 195 bbl 16" X 7-5/8" = 0 psi 5/8/2020 Cont drilling 6 3/4" hole from 5985' to 6353', rot wob 2-4K, 248 gpm-1473 psi, 60 rpm-9900 ft/lbs on bott torque, 80 to 150 ft/hr ROP, MW 9.1/vis 53, ECD's at 10.2 ppg, BGG 7 units, max gas 124 units.;Cont drilling 6 3/4" hole from 6353' to 6652', rot wob 2-4K, 248 gpm-1692 psi, 60 rpm-10,142 ft/lbs on bott torque, 100 to 150 ft/hr ROP. Sliding wob 2K, 248 gpm-1681 psi, 300 psi diff, 150 ft/hr ROP, MW 9.1/vis 55, ECD’s at 10.1 ppg, BGG 12 units, max gas 143 units.;Pumped a sweep around at 6411’ with no increase in cuttings, back on time. Had no issue with losses while drilling through the C1 and C2 zones. Cont utilizing NXS lube in suction pit to aid in sliding. Received 3 RA marker joints.;Cont drilling 6 3/4" hole from 6652' to 6957' 270 gpm 2020 psi 60 rpm 10.8k tq on 11k off, 88k PUW 50k SOW 64k SOW 25k WOB, 9.1 ppg MW 10.2 ppg ECD, max gas observed 164 units.;Circulate bottoms up 275 gpm 2020 psi 60 rpm 11k tq, take survey and SPR's.;Pull wiper trip f/ 6957' t/ 5899' No hole issues 7.1 bbls calculated 9 bbls actual.;Service rig and top drive, Static loss rate 3 bph.;RIH f/ 5899' t/ 6957' No hole issues.;Pump Hi Vis Sweep Back on time No increase in cuttings, Drill Ahead f/ 6957' t/ 7140', 270 gpm 1690 psi 60 rpm 11k tq on 11.5k tq off, 87k PUW 51k SOW 64k ROT, 9.15 ppg MW 10.29 ECD Distance to plan 1.52' .72 above 1.34 left, 41 max gas units.;Hauled 72 bbls solids to KGFG&I Cumulative 664 bbls Hauled 168 bbls fluid to KGF G&I Cumulative 2258 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 96 bbls Total losses to hole 291 bbl 16" X 7-5/8" = 0 psi 5/9/2020 Cont directionally drilling 6 3/4" hole from 7140' to 7311'. Rot wob 2-3K, 271 gpm-1944 psi, 60 rpm-11,970 ft/lbs on bott torqu e, 150 ft/hr ROP . Sliding wob 3-4K, 271 gpm-1780 psi, 163 psi diff, 68 ft/hr ROP, MW 9.2/vis 50, ECD's at 10.2 ppg, BGG 7 units, max gas 49 units.;Cont directionally drilling 6 3/4" hole from 7311' to 7587'. Sliding wob 1-2K, 281 gpm-1783 psi, 129 psi diff, 70 ft/hr ROP. Rot wob 3-4K, 271 gpm-2002 psi, 65 rpm-13,208 ft/lbs on bott torque, 100 to 150 ft/hr ROP, MW 9.2/vis 49, ECD's at 10.0 ppg, BGG 11 units, max gas 63 units.;Pumped hi-vis sweep at 7453' with 10% increase, back on time. At 7587' we are at 9.34° Inc and rotating ahead. Received shoe track, swell packer and hanger/landing joint. Cont to add lube to suction pit as needed to reduce on and off bottom torque.;Cont directionally drilling 6 3/4" hole from 7587' to 7949' 270 gpm 2140 psi 60 rpm 14k tq on bottom 13.3k tq off, 99k PUW 55k SOW 70k ROT, Max Gas 557 units.;Circulate bottoms up 270gpm 1820 psi , get survey and slow pump rates.;Make wiper trip f/ 7949' t/ 6892' No Hole Issues Observed, 7.1 bbls calculated and 7.9 bbls actual.;Service rig and top drive, Static loss rate - 3 bph.;RIH f/ 6892' t/ 7949' No hole issues observed, calculated 18.2 bbls actual 11.9 bbls.;Drill Ahead f/ 7949' t/ 8075' 270 gpm 1800 psi 60 rpm 13.3k tq on 12.8k tq off, PUW 100k SOW 54k ROT 71k, MW 9.25 ppg ECD 10.22 ppg, Distance to plan 4.98' 2.2' Low 3.78' Right Max Gas Observed 87 units.;Hauled 48 bbls solids to KGFG&I Cumulative 712 bbls Hauled 139 bbls fluid to KGF G&I Cumulative 2393 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 72 bbls Total losses to hole 393 bbl 16" X 7-5/8" = 0 psi Cont drilling 6 3/4" hole from 5985' to 6353', Cont drilling 6 3/4" hole from 4724' to 4912', 5/10/2020 Cont drilling 6 3/4" hole from 8075' to 8137'. Rot wob 3-4K, 271 gpm-2036 psi, 60 rpm-11,100 to 14,000 ft/lbs on bott torque, 90 ft/hr ROP, MW 9.2/vis 51, ECD's at 10.4 ppg, BGG 12 units, max gas 99 units. As we drilled this last stand down, on bott torque increased, ROP dropped off. No losses.;Currently in the LB_1C formation. Estimated formation pressure of 2500 psi. Drilling in fine silt and clay. Made connection, but having difficulty resuming drilling/rotating. Racked stand back and able to work pipe and re-establish rotation, off bott torque 12,216 to 15,593 ft/lbs.;Rotate and reciprocate string, 282 gpm-1761 psi, 60 rpm-10,210 to 15,800 ft/lbs. Reduce speed while pulling and slack off, torque dropping off but ECD's climbed to 10.6 ppg on first bottoms up, shakers had good amount of clay. Cont circ a second bottoms up and shakers cleaning up. After second;bottoms up pumped a 20 bbl hi-vis nut plug sweep around. At 3500 strokes (surf to surf 5444 strokes) ECD's spiked from 10.4 to 10.8 ppg then dropped to 10.3 ppg as we pulled up hole 50', flow show dropped from 19% to 3%. Reduced pump rate to 260 gpm, ECD's dropped to 9.8 ppg and we re-gained;flow, slowly increasing up to 14% over 30 min. During initial losses, we transferred pill pit into suction pit. Mud in pill pit contained BaraCarbs at 45 ppb. Total fluid lost was 93 bbls over 30 minutes as we re-gained flow rate. Cont circ sweep OOH with no increase in cuttings and shakers clean.;Made connection, resumed rotating ahead from 8137' to 8155'. Rot wob 3-4K, 222 gpm-1596 psi, 65 rpm-15,300 ft/lbs on bott torque, 60 to 130 ft/hr ROP, ECD's at 10.0 ppg. Flow steady but at 8155' it once again dropped from 13% to 5%. Pulled up hole to 8137' and racked back stand.;Reduced pump rate to 114 gpm (pump at idle) while finish building LCM pill in pill pit and start building volume in pit #10. Pumped and spotted LCM pill consisting of BaraCarb 5-25-50, 45 ppb, outside of drill string.;Pulled up hole slowly, from 8079', 17 stands, on elevators, up wt 104K, dwn wt 60K, to 7073' with no issue, to get BHA above LCM pill. Calculated hole fill = 6.3 bbls, actual hole fill = 7.7 bbls. If we pulled too fast it appeared to be swabbing. Slower we pulled, hole took more fluid.;Cont building volume in active and premix #10 while monitoring well on trip tank. Loss rate increased from 13 bph to 18 bph. Discussed plan forward with Drilling Manager and Geologist, decision made to call TD at current depth of 8155' md, 6375' TVD. Last survey at 8100' md, 10.15° Inc, 85.12° Azi,;6321' tvd has us 1.49' low and 5.40' right of the line. Projection to TD at 8155' md, 10.15° Inc, 85.12° Azi, 6375' tvd is 0.94' low and 5.90' right of the line. Casing run tally adjusted to fit current TD. Decision made to try and heal up the hole and attempt to get some GeoTap stations logged at;minimal flow rates. Cont moving drill string with no issue every 10 minutes. Straight pull up until broke over then park. Very little overpull. Hole on trip tank, flow rate steady at 5% over 3 hours. Pumped and spotted 20 bbl, 40 ppb LCM pill consisting of BaraCarb 150-400, Barafibre and nut plug.;Initially fluid level dropped 8' in wellbore as we pumped pill at an idle, then slowly fluid level rose and we re-gained slight returns until pill in place outside bit. Allowed pill to settle and soak one hour. Changed the two end screens on all 3 shakers to 120's, to keep new mud from running over.;Fluid dropped approximately 1' over an hour. TIH on elevators from 7073' to 8130' with no issue. Attempt t/ circulate @ 7930' with slight to no returns.;Spot 16 bbl LCM pill on bottom pull up 4 stands and monitor f/ 30 min, attempt to pump sight to no returns.;POOH w/ pumps 120 gpm 450 psi no returns f/ 7938' t/ 5588' attempt t/ regain returns with rotation and pumps in multiple spots with no luck, finally regained circulation @ 5588' 120 gpm 550 psi 4% returns.;Stage pumps t/ 260 gpm 1525 psi 17% returns slight losses while pumping, work pipe with rotation, regaining full returns, pumped walnut pill, hole unloaded before sweep back large chunks of clay, pump bit balling sweep stage pumps t/ 275 gpm 1600 psi no increase in cuttings with bit balling sweep.;RIH f/ 5588' t/ 6149'.;Stage pumps t/ 250 gpm 1410 psi 80 rpm 75% flow work pipe attempt to get full circulation, pump 20 bbls LCM Pill, continue attempting t/ regain full circulation.;Hauled 67 bbls solids to KGFG&I Cumulative 779 bbls Hauled 313 bbls fluid to KGF G&I Cumulative 2706 bbls Daily Metal 0 lbs 5/11/2020 Cont circulating at 261 gpm-1428 psi, 76 rpm-11,487 ft/lbs off bott torque, working pipe from 6712’ to 6767’ and spot LCM pill outside drill string.;Start pulling up hole but seeing swabbing, cont pump up hole to 5581’, pump at idle. 114 gpm-487 psi, up wt 75K, dwn wt 42K. Seeing swabbing despite trip speed, on down stroke we are pushing mud away.;Monitor well on trip tank for minutes. Static loss rate of 3 bph.;Pump and spot LCM pill at 5581', 60 ppb, 114 gpm-485 psi, 3% return flow. With pill in pipe increased pump rate to 226 gpm-1108 psi, 8% return flow. Slowed pump to idle prior to pill reaching BHA. Lost 70 bbls during pumping and spotting pill. (pill = baracarb 150-400, barafibre and nutplug).;Pulled up hole 2 stands slowly on elevators from 5581' to 5462'. up wt 70K, dwn wt 40K, still seeing swabbing, seeing some slight displacement on slack off. At 5462' let pill settle and soak for 30 minutes. Wel l static.;Attempt to circulate starting at idle, staging up to 180 gpm. Lost 22 bbls over 10 minutes. Shut down, notified Drilling Manager, decision made to pull up hole 1000' from pill spot and attempt to circ.;Pumped up hole from 5462' to 4535', up wt 68K, pump at idle due to swabbing. Started rotating at 25 rpm while pulling. Increased pump rate to 160 gpm and rotary to 80 rpm on one stand, then back to idle and 25 rpm. Lost 36 bbls on this particular trip.;At 4535' let sit 30 minutes while transferring fluid into active system. Well static.;Broke circ at idle, 114 gpm, slowly increasing rate to 160 gpm-694 psi, 30 rpm-7700 ft/lbs off bott torque. Initially had 8% return flow and a loss rate of 126 bph first 20 minutes, 94 bph at 30 minutes and no loss at 40 minutes into circulating. Return flow up to 10% then 13%, then 15%.;Lost 40 bbls by the time we had 15% flow rate and bottoms up. Had a good amount of sand, barafibre and baracarbs at bottoms up. No gas issues. Increased to 180 gpm- 854 psi for 15 minutes with no losses.;TIH 8 stands from 4535' to 5028' very slowly. Getting some displacement back. Calculated = 8.8 bbls, actual - 6 bbls. Down wt 38K, no issues, hole in good shape.;Filled pipe at 5028', pump at idle, 114 gpm-509 psi, 30 rpm-8000 ft/lbs off bott torque, no losses. Increased pump rate to 160 gpm-735 psi, still 30 rpm, 15% return flow, no losses. Increased to 187 gpm846 psi, lost 9.5 bbls over 20 minutes then stable. Had Sperry function GeoSpan at this rate (OK).;TIH 8 more stands from 5028' to 5513', slowly, getting most of displacement again. Down wt 43k. Calculated = 8.8 bbls, actual = 6.14 bbls.;Filled pipe, pump at idle, 30 rpm-8000 ft/lbs off bott torque, no losses. Increased pump rate to 150 gpm-685 psi, 14% return flow. Increased to 175 gpm- 826 psi, 16% return flow. Increased to 194 gpm-899 psi and lost 8 bbls over 30 minutes.;Discussed GeoTap operations with Sperry Reps, making mad pass with no rotation at 45° left, from 5511' up to 5488'. Made mad pass orienting tool face to 45°, reduced pump to idle, SO to 5498', then increased pump rate back up to 200 gpm, pulled up hole and parked bit at 5488.5'.;GeoTap samples with probe at 5488', 5344', 5262', 5210', 5209', 5166', 5165' Madd pass between stops reshoot 2 stations.;POOH f/ 5165' t/ 698' on elevators no hole issues 29.4 bbls Calc 37.3 bbls Act.;Stand back and L/D BHA, unload sources, L/D BHA, break bit, download MWD on the ground 9.5 bbls calc 15.5 bls act Bit graded 1-1- in gauge.;Clean and clear rig floor, P/U Clean Out BHA Components strap tools.;P/U BHA #3 Clean Out Assy t/ 533' RIH on 4.5'' DP t/ 1182'.;Hauled 0 bbls solids to KGFG&I Cumulative 779 bbls Hauled 1 bbls fluid to KGF G&I Cumulative 2707 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 707 bbls Total losses to hole 1739 bbl 16" X 7-5/8" = 0 psi pgp Geologist, decision made to call TD at current depth of 8155' pgpp ;Discussed GeoTap operations with Sperry Reps,y TD at 8155ft Cont drilling 6 3/4" hole from 8075' to 8137'. R 5/12/2020 Cont RIH with BHA #4 (cleanout assembly) from 1182’ to 1459’, slowly.;At 1459’ stabbed TIW and hung off blocks/topdrive. Cut and slipped 85' drill line, serviced rig and topdrive. Static loss at 3 bph. Calibrated block height and hookload, checked crown saver.;CBU starting with pump at idle, 114 gpm-55 psi, staged up to 189 gpm-97 psi and no losses.;TIH from 1459' to 2385' slow, no issue exiting surface casing shoe at 1784'. Getting most of pipe displacement.;Filled pipe and pumped string volume, pump at idle, 114 gpm-98 psi, staged up to 170 gpm-133 psi, 15% return flow, lost 2 bbls.;TIH from 2385' to 3314' slow, down wt 37K. Trip at 50 to 60 ft/min.;Filled pipe and CBU staging from 114 gpm to 160 gpm-148 psi. Lost 4 bbls.;TIH from 3314' to 4244' slow, 20 to 30 ft/min. Down wt 46K.;Filled pipe and CBU staging from 114 gpm to 131 gpm-168 psi, lost 6 bbls.;TIH from 4244' to 5175' slow, 20 to 30 ft/min. Down wt 53K.;Filled pipe and pumped string volume staging from 114 gpm-198 psi to 153 gpm-238 psi. Lost 8 bbls.;TIH from 5175' to 6103' slow, 20 to 30 ft/min. Down wt 57K.;Filled pipe and circ surface to surface at 112 gpm-265 psi down to 217 psi, good amount of very fine coal and course LCM on shakers at bottoms up. MW in 9.0 +, MW out 9.0 +. Lost 45 bbls.;TIH from 6103' to 7032' slowly. initially had little to no displacement from 6103' to 6300'. At 6300' started seeing better return flow on trip tank and gaining as well. By 6330' had good displacement and return flow all the way down to 7032'. Down weight 62K.;At 7032' broke circ at pump idle, 112 gpm-271 psi. 60 bbls lost over 1.5 hrs while circ. BU.;Resumed easing in the hole @ 30' per min F/7032'-T/8096', P/U-100K S/O-68K Off line cont. building 150 bbl batches of mud and a 70 bbl 100 lbs per/bbl LCM pill.;Kelley up and washed last stand to bottom, tagged up @ 8105', washed and rotated to 8130', cleaning out 25' of fill. Cal Disp.=138 bbls Act Disp.=84.7 bbls Diff=-53.3 bbls P/U-120K S/O-63K.;Cont. circ. STS at pump idle, GPM-112 SPP-327 psi, 60 bbls lost over 1.5 hrs while circ. STS.;Shut down the pump, stood 1 std. back in the derrick, observed mud U-tubing out of the pipe due to float no holding, screwed back into pipe, pumped additional string volume, no luck (still U-tubing) .;Held PTSM, crew change, pumped BU with no luck (still U-tubing). P/U-120K S/O-68K GPM-112 SPP-316 Flow-10%.;Made decision to pump OOH due to float not holding & swabbing F/8130' to current depth of 5861' Loss rate while pumping OOH= 11 bph.;Hauled 0 bbls solids to KGFG&I Cumulative 779 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 2707 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 352 bbls Total losses to hole 2091 bbl 16" X 7-5/8" = 0 psi 5/13/2020 Parked string at 5792’, up wt 80K, lost 60 bbls pumping up hole to this depth. Monitored well 30 minutes with slight flow. Lined up on pill pit, pumped and spotted 35 bbl 100 ppb LCM pill at 114 gpm-201 psi. Once pill out the bit, monitored for one hour. Well flowed back with a initial rate of 14;bph, then dropped to 12, 7, 5, 1.5 then .5 bph over that hour. Stroked full stand 3 times with slight swabbing on up stroke, good displacement on down stroke.;Pulled up hole slowly from 5783' on elevators, up wt 83K, to 4987'. Calculated hole fill 6 bbls, actual hole fill .7 bbls.;Monitored hole for one hour, fluid dropped +/- 12' first 40 min, topped hole off with .8 bbls, then fluid dropped +/- 12' again next 20 minutes. .8 bbls to top off.;Started pump, staging up to 125 gpm-189 psi, lost 25 bbls first 15 minutes, 54 bbls over an hour of circ, which then stabilized. Had 9.2 ppg returns at bottoms up (LCM pill was 9.5 ppg) with fair amount of calcium carb and bara fibre fine on shakers. Increased pump rate to 160 gpm-231 psi,;lost another 14 bbls at that rate over another hour of circ and shut down pump.;Put well on trip tank and monitored return flow. Got back 5.4 bbls over 1.5 hours and well went static.;TIH slow on elevators at 30 ft/min from 4987' to 5900' with no issue, hole in good shape.;Pumped and spotted remaining 50 bbls of 100 ppb LCM pill at 114 gpm-166 psi with a 24 bbl gain in returns. 114 gpm-166 psi. Every 10 minutes straight pull on drill string until breaks over then park. No issues.;Monitored well for flow on trip tank, gained back 10 bbls over 1.5 hours.;Closed annular, lined up pump on kill line, pumped LCM hesitation squeezes in 5 bbls increments, max pressure seen was 299 psi before showing signs of injecting fluid away, bull headed away a total of 28 bbls of 90 ppb LCM pill. Discussed options w/ town.;Racked 1 std. back in derrick, monitored well on TT (static), blew down Geo span lines & disconnected unit and mixed another 40 bbls LCM pill @ 9.9 ppg.;Held PTSM, crew change, broke circ. and pumped STS, loss rate= 54 bbls an/hr. observed small amount of LCM pill at BU w/ no mud wt increase. GPM-114 SSP-227 psi.;RIH w/ 1 std. out of derrick, put bit depth @ 5918', spotted 41 bbl LCM pill on back side, lost 12.5 bbls once pill exited bit. GPM-114 SPP-202 psi. P/U-75K S/O-51K.;Shut down pump, monitored well on TT, well was flowing @ 21 bbls per/hr. to start, dropped to 1.6 bbls after 1 hr. Started building additional 150 bbl batch on new mud.;Closed annular, lined up pump on kill line, currently pumping LCM hesitation squeezes in 5 bbl increments. Finished building additional 150 bbl batch on new mud.;Hauled 0 bbls solids to KGFG&I Cumulative 779 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 2707 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 220 bbls Total losses to hole 2311 bbl 16" X 7-5/8" = 0 psi pp bull headedpp q away a total of 28 bbls of 90 ppb LCM pill. pp@ pp ;Shut down pump, monitored well on TT, well was flowing @ 21 bbls p per/hr. to start, dropped to 1.6 bbls after 1 Cont RIH with BHA #4 (cleanout assembly) from 1182’ to 1459’, slowly. 5/14/2020 Perform hesitation squeeze of 60 bbls total LCM pill in 5 and 10 bbl stages. Final stage obtained max of 324 psi that bled down to 141 psi over 10 minutes.;Bled everything off, opened annular, lined up plumbing to drill. Well flowing 25 bph first 15 min, 12 bph at 20 min, 7 bph at 30 min, 5 bph at 50 min, 3 bph at 60 min. Got back a total of 24 bbls over that hour.;TIH from 5924’ to 6539’, calculated displacement 12 bbls, actual displacement 4.7 bbls. Down wt 60K.;CBU at 114 gpm- 274 psi, 6% to 11% flow. Lost 31 bbls first 30 min of pumping, then increased rate up to 126 gpm-289 psi, 12% flow. With a loss of 44 bbls, we no longer had any losses, even at the higher pump rate. Did have some LCM on shakers at 3100 strokes (500 strokes early of bottoms up;considering the losses encountered). Increased rate to 150 gpm-304 psi at 4000 strokes, 14% flow, no additional losses. Shut down at 4520 strokes.;Monitored flow, seeing 7% on the flow show, 126 bph intitial rate down to 30 bph down to 3 bph over an hour and tapering off. Replaced centrifuge feed pump and MI Rep serviced centrifuge.;POOH on elevators from 6539’ to surface, up wt 94K. First 10 stands hole took no fluid, then started taking more each set of 5 stands. End of trip, calculated hole fill = 48.5 bbls, actual hole fill = 43 bbls. Once out of hole taking 8 bph.;LD bit (1-1), bit sub w/float, stab. cleared & cleaned rig floor, flush choke manifold w/ H20.;PU and MU CDS-40 mule shoe. TIH F/surface -T/4083' w/ no pipe displacement, broke circ. & pumped 20 bbls to clean mule shoe, lost 7 bbls while circ. GPM-114 SPP-146 psi P/U-78K S/O-50K.;Resumed TIH F/4083'-T5890', Pipe displacement- Cal Disp.-43.7 bbls Act Disp.-32.3 bbls Total losses for trip=76 bbls.;Held PTSM, crew change, cont. TIH F/5890' to cement depth of 6511'. Cal Disp.-48.3 bbls Total losses for trip=86 bbls P/U-86K S/O-52K.;Broke circ. & pumped 40 bbls to clean mule shoe, lost 21 bbls while circ. GPM-114 SPP-241 psi, HES cmt arrived on location @ 01:00 hrs.;Shut down pump. monitored well on TT, flowing- initial rate=7.1 bph final rate=.3 bph, R/U HES cmt equip. Serviced rig, P/T cmt surface lines 250 Low 2500 High (ok), Held PJSM w/ rig crew, HES cmt, Peak, & Baroid.;Lined up & pumped 6.5 bbls of 10.5 ppg tune spacer, dropped 1st wiper ball, pumped 35 bbls of 13 ppg cmt, dropped 2nd wiper ball, pumped 3.5 bbls of 10.6 ppg tune spacer, and chased w/ 70 bbls of 9.1 ppg drilling mud. Shut down pump, back out head pin & L/D, pipe on a vac. lost 69 bbls during job.;POOH on elevators F/6511'-T/5392' @ 30' per/min, well was flowing @ 6.7 bph-3.5 bph during trip.;Hauled 0 bbls solids to KGFG&I Cumulative 779 bbls Hauled 80 bbls fluid to KGF G&I Cumulative 2787 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 174 bbls Total losses to hole 2485 bbl 16" X 7-5/8" = 0 psi 5/15/2020 Dropped two wiper balls, MU topdrive and CBU at 5392’, staging pump up to 220 gpm-323 psi with only 13 bbls lost entire circ time. Had trace of tuned Spacer at bottoms up (small show of celloflake). Shut down pump, flow check = 1/4 bph.;Closed annular, lined up on choke manifold to monitor casing pressure, lined up pump on kill line. With rig pump, pressured up on wellbore to 100 psi, down pump and repeat, squeezing cement into formation for 30 min. Put away 7.7 bbls over 30 minutes. Bled off, opened up, 1/4 bph flow rate.;POOH on elevators from 5392' to surface. Hole in good shape, still seeing what appears to be swabbing at times. Up wt 76K, no sign of cement rings in tool joints or on tool joint shoulders. LD mule shoe. Cal Disp.=35.7 bbl Act Disp.=-23.4 bbl Diff=12.3 bbl.;Flushed choke manifold with water, PU single HWDP and MU stab, bit sub with float and new 6 3/4" tricone bit jetted with 3 x 16's.;TIH filling pipe every 1500' to 5430' Down wt 56K. Calculated displacement = 96.3 bbls, actual displacement = 77.4 bbls.;Fill pipe then start wash and ream down at 180 gpm-434 psi, 40 rpm-6500 to 8500 ft/lbs off bott torque. At 5815' started seeing wob of 1 to 5K. Had a loss rate of 30 bph the first hour (5430' to 5739'), 20 bph the second hour (5739' to 5930') of wash and reaming. Had occasional issue with topdrive;forward control in both connection and drill mode. Tool Pusher brought Derrickman that strained bi-cep last night, in to doctor to be checked. Probable torn muscle, recommended to ice and take ibuprofen, released for light duty.;Cont. washing /reaming F/6047'-T/6500', bumped GPM to 225 for 2 stds, loss rate increased to 30 bph, dropped rate back to 180 gpm, loss rate dropped to 15-20 bph, still seeing mostly 60% LCM, 30% cmt, & 10% background formation on shakers, added 1 drum of NXS lube to suction to reduce TQ,;Cont. washing /reaming, @ 6500', started seeing increase in cuttings - 60% cmt , 30% LCM, & 10% background formation on shakers, well cont. to flow on every connection (ballooning), average loss rate=12.6 bph, P/U-90K S/O-58K ROT-68K GPM-180 SPP-446 psi WOB-1-5K RPM-50 on bottom TQ-11K.;Held PTSM, crew change, cont. washing /reaming F/6550'-T/6784', cmt % continuously changing while washing/reaming ahead, added 2 drums of NXS lube to suction pit to control TQ, P/U-95K S/O-54K ROT- 68K GPM-180 SPP-453 psi WOB-1-5K RPM-50 on bottom TQ-11-12K.;On connection performed flow check due to well flowing stronger (ballooning), flow rate every 10 min over 1 hr= 60 bbl per/hr., 42 bbl, 20.4 bbl, 14.2 bbl, 10.7 bbl, 7.1 bbl.;Cont. washing /reaming F/6784'-T/6979', shut down & flow check, 61 bbls per/hr & dropping., called to discuss options, made decision to attempt to TIH on elevators w/ 5 std. pumping down the fifth one. P/U-98K S/O-56K ROT-68K GPM-180 SPP-479 psi WOB-1-5K RPM-50 on bottom TQ-11-12K.;TIH on elevators F/6979' to current depth 7280' w/ no hole issues & slight flow, average loss rate =12.8 bph.;Hauled 6 bbls solids to KGFG&I Cumulative 785 bbls Hauled 134 bbls fluid to KGF G&I Cumulative 2921 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 220 bbls Total losses to hole 2705 bbl 16" X 7-5/8" = 0 psi Perform hesitation squeeze of 60 bbls total LCM pill in 5 and 10 bbl stages. p gp squeezing cement into formation for 30 min. Put away 7.7 bbls pp p gp p p p p p p p q over 30 minutes. Bled off, opened up, 1/4 bph flow rate.;POOH on elevators from 5392' to surface. H 5/16/2020 Cont working down hole from 7280’, trip 4 stands on elevators, wash 5th stand down, repeat to 8130’. 58 to 60K down wt on elevators, 168 gpm-773 psi, 45 rpm- 9800 to 11,700 ft/lbs off bott torque when washing/reaming, 10% flow. Pump on no rot, up wt 104K, dwn wt 58K.;Circ surface to surface at 167 gpm-557 psi, 76 rpm-10,000 to 13,000 ft/lbs torque on down stroke, 14,900 to 15,500 ft/lbs torque on up stroke. Hole unloaded at bottoms up, 15% formation material, 40% cement and 45% LCM. Lost 113 bbls over two hours of circ at this rate. Max gas 6 units.;Shakers cleaned up, shut down and monitored well for one hour taking flow rates every 10 minutes. Initial flow rate of 225 bph reduced to 8 bph over the hour, re-gained 56.5 bbls over the hour.;Pulled up hole 5 stands on elevators slowly to 7775’, seeing swab effect and gained another 6 bbls during trip. Monitored flow for 30 minutes. Flow reduced from 8 bph to 0.12 bph over 30 minutes.;Pulled up hole 5 stands slowly to 7467’ with a 1.82 bbl gain. Monitored well on trip tank 30 minutes, hole took .02 bbls.;Cont pulling up hole slow then monitoring every 5 stands, hole taking more each group of 5 stands. Getting better hole fill at a faster pull rate. Stopped at 4990’ and did another 15 min monitor. Hole took .43 bbls static loss.;Cont POOH on elevators from 4990' to 3567'.;Performed kick drill while TOOH, had well secured in 65 seconds. had after action review on trip drill.;Cont POOH on elevators from 3567' to 1772', inside casing shoe 1784'. Monitored well for 30 mins on TT (static).;CBU at 167 gpm-170 psi, cut and slip 54' drill line, calibrate block height and hook load, check crown saver.;Cont POOH F/1772'-T/533' and lay down 4 1/2" DP. Had Peak vacuuming absorb darts through pipe w/ vac truck on rack, inspecting each jt, re-doping threads and installing protectors on tight.;Cont TIH w/ 20 stds out of derrick and POOH L/D 40 jts each time, repeating process until all 4.5' DP in derrick was L/D and cont. w/ pipe cleaning & maintenance.;Hauled 0 bbls solids to KGFG&I Cumulative 785 bbls Hauled 0 bbls fluid to KGF G&I Cumulative 2921 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 120 bbls Total losses to hole 2825 bbl 16" X 7-5/8" = 0 psi 5/17/2020 Cont POOH LD 4 1/2" CDS-40 DP, then RIH 20 stands, LD 40 joints, repeat until all DP down, LD HWDP and BHA. Bit graded at 1-1.;Drained BOP stack, PU 2 7/8" test joint and run tool, pulled wear bushing, LD test joint and run tool. PU DP single and wash tool, flushed stack and cavities, LD single and wash tool. PU 2 7/8" test joint and set test plug, LD test joint. Changed upper rams to 5 1/2". Flooded stack and functioned.;RU fill up line on annulus valve on wellhead, with bypass line into trip tank, to keep hole full while flushing stack etc. Shut down and disconnected fill up line from open annulus.;Installed 2 7/8" test joint, tested lower rams at 250/3500 for 5 min each, good tests, LD 2 7/8" test joint, PU and installed 5 1/2" test joint. Tested annular at 250/2500 then upper rams at 250/3500 for 5 min each. Good tests.;RD test equipment, pulled test plug, closed annulus valve. PU and dummy ran hanger/landing joint, RKB to load shoulder = 19.10', LD hanger/landing joint.;RU Weatherford casing equipment, RU fill up line, staged drive subs and centralizers, loaded pipe racks with casing in groups of 5 joints. Held PJSM with casing crew and rig crew.;PU and MU shoe track, BakerLok'd connections, top filling each joint. Stroked shoe track and checked floats (OK). Cont PU single in hole with 5 1/2", 17# L-80 CDC/HTQ casing at 20 ft/min to 1402'. Average loss rate per/hr.= 6bbls.;M/U drive sub & circ. while waiting on Weatherford to change out power tongs due pressure on control valve and not allowing tongs to TQ up casing. lost 11 bbls while circ. Off line built 150 bbl batch of mud.;Cont PU single in hole with 5 1/2", 17# L-80 CDC/HTQ casing at 20 ft/min F/1402'-T/1767', M/U drive sub, broke circ. obtained parameter before exiting shoe, P/U-38K S/O-36K ROT-36K TQ (10 RPM-3K 20 RPM-3.6K 30 RPM-4K).;Cont PU single in hole with 5 1/2", 17# L-80 CDC/HTQ casing at 20 ft/min F/1767'-T/2162'. Casing Disp.- Cal=12.4 bbls Act= -13.41 bbls Diff=-25.81 bbls.;Held PTSM/Sunday safety meeting, crew change, Cont PU single in hole with 5 1/2", 17# L-80 CDC/HTQ casing at 20 ft/min F/2162'-T/3211'. broke circ. lost 9.5 bbls while circ. Average loss rate=6.7 bph P/U-58K S/O-38K GPM- 114 SPP-172 Off line building 150 bbls 2nd batch of mud.;Cont. PU single in hole with 5 1/2", 17# L-80 CDC/HTQ casing at 20 ft/min F/3211' to current depth 4178'.;Hauled 1 bbls solids to KGFG&I Cumulative 786 bbls Hauled 99 bbls fluid to KGF G&I Cumulative 3020 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 80 bbls Total losses to hole 2905 bbl 16" X 7-5/8" = 0 psi Run 5 1/2" casing and cement p j Tested annular at 250/2500 then upper rams at gj 250/3500 for 5 min each. Good tests.;RD test equipment, pulled test plug, closed annulus valve. gqp p g pp g g crew.;PU and MU shoe track, BakerLok'd connections, top filling each joint. Stroked shoe track and checkedjgg floats (OK). Cont PU single in hole with 5 1/2", 17# L-80 CDC/HTQ casing at 20 ft/min to 1402'. A 5/18/2020 Cont PU single in hole from 4210’ with 5 1/2" 17# L-80 casing, top filling on the fly, topping off every 10 joints. Stopped at 5219’ and 6706’ and circulated for a bit just to ensure we did get some returns, which we did. Broke off topdrive and circ swedge, MU 6.35" OD swell packer and pups;cont TIH to 8097’ and MU landing joint/hanger, eased down and landed hanger putting shoe at 8121’, dwn wt 50K. Hole got a little sticky at 6425’, sometimes taking 20K to break loose on down stroke, but for the most part, string slid right to bottom.;Topfilled landing joint, MU drive sub and topdrive, broke circ at 47 SPM-114 gpm-2.7 bpm- 454 psi, pull hanger 1' off seat and parked. Getting 8 to 9 bph return flow rate. Lay out liner for cementers to park on, backed in cement trucks, staged plug launcher, manifold, HP wash hose and hardware on;rig floor, removed Weatherford air slips. Cycled rig pump on for 10 min, off for 10 min to minimize losses to surface volume, installed dogbones on bails, loaded bottom plug in launcher (single plug launcher). Shut down pump, removed topdrive and drive sub, MU plug launcher, MU hardline and plumbing;Cont to cycle rig pump on/off while holding PJSM with Halliburton cementers, Peak and rig team. At shut down of pump, well flowing at 5.3 bph.;MU plug launcher and hardline, Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 580 low 4050 high, good tests. Halliburton pumped 36.9 bbls 10.5 ppg Tuned Prime Spacer at 1.5 to 2.5 bpm-364 to 420 psi then dropped bottom plug. Loaded top plug in;plug launcher, followed by pumping 122.4 bbls (295 sx) 12.0 ppg Type I II lead cement at 3 to 4 bpm-380 to 45 psi, 21.4 bph return flow rate, followed by 23.3 bbls (85 sx) 15.3 ppg Class G tail cement at 2 bpm-50 psi. Halliburton dropped top plug, then displaced with 9.0 ppg 6% KCL PHPA mud at 5 to;7 bpm-50 to 1500 psi. Increased rate to catch up with cement. Caught cement and pressure 35 bbls into displacement and slowed to 5 bpm-150 psi. Slowed pump to 3 bpm with 12 bbls to go. Did bump the plug at 180.5 bbls into displacement (calculated 187 bbls). Held 2200 psi (FCP of 1037 psi);for 3 minutes, bled off and floats held. Bled back 1.5 bbls to truck. Had 0 bbls of Spacer returns to surface and 0 bbls lead cement to surface. Added LCM to both lead and tail cement at 1/4 ppb. Mix water temp 70 deg. Pumped 10% excess on both lead and tail. Lost 318.6 bbls throughout the job.;Did not reciprocate pipe. CIP at 19:15, 5-18-20. Washed up, RD plug launcher and released Halliburton. Backed out landing joint and flushed same with water. Pulled landing joint to rig floor.;MU pack-off run tool on landing joint with pack-off assembly, RIH and set same on hanger, RILD's. RU and test void at 250 low for 5 min, 5000 high for 10 min, good tests. Total Safety on location at 21:00 hrs, testing and calibrating gas sensors and audio alarms.;Closed blinds, opened upper ram doors and swapped from 5 1/2" solid body to 2 7/8" x 5" VBR's. Buttoned up ram doors.;Opened blind rams, vacuumed out stack from floor & R/U testing equip, well head NOS Rep Sam set 2 way check valve, M/U blanking sub to bottom of 2-7/8" test jt. M/U side entry sub & TIW/dart on top, screwed blanking sub into hanger neck, flooded stack & purged air.;Tested BOP's as per state regulations 250 Low & 3500 High 5/5 min, witness waved by AOGCC Jim Regg.;Held PTSM, crew change, cont. testing BOP's, off line cleaned pits 4-6 9& 10, cleaned MP suction manifold, suction & discharge screens, strap, tally, & drift 2-7/8" PH-6 work string, staged scraper & XO's on cat walk, loaded MWD/DD shack & cabinets onto trailer.;Hauled 22 bbls solids to KGFG&I Cumulative 808 bbls Hauled 118 bbls fluid to KGF G&I Cumulative 3138 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 676 bbls Total losses to hole 3581 bbl 16" X 7-5/8" = 0 psi 5/19/2020 Continued and finished testing bope's as per regulations 250L/3500H w/ no issues.;R/dn bope testing equipment and r/up test 5-1/2" csg and test same t/ 3500 psi on chart 30 min good test and service rig.;P/up and M/up c/out assy 4-3/4" bit and 5-1/2" scraper Bha#7 and single in hole p/up and rabbiting 2-7/8" PH-6 work string t/ 611'.;Crew change, continue rih w/ bha #7 p/up and rabbiting 2-7/8" work string F/611'-T/2621', CBU @ 266 GPM, SPP-720 psi MW-9.1 ppg.;Resumed P/U & rabbiting 2-7/8" work string F/2621'-T/5308', CBU @ 266 GPM, SPP-1396 psi MW-9.1 ppg.;Cont. P/U & rabbiting 2-7/8" work string F/5308', tagged up at 8023', set down 4K to confirm tag, 13' high, staged pump up & CBU @ 266 GPM, SPP-2093 psi MW-9.1 ppg. Dry=P/U-61K S/O-38K. Off line un plug mud loggers shack & moved away from rig.;Held PTSM, crew change, cont. CBU @ 266 GPM, SPP-2093 psi MW-9.1 ppg. Wet=P/U-62 S/O- 34K.;Shut down pump, R/U to reverse circ. P/U & M/U 5' pup, TIW, side entry sub, XO to PH-6.;Broke circ. Staged up pump, GPM-226, SPP-2263 psi. Held PJSM w/ rig crew, Peak, & Baroid on brine displacement.;Displaced well- pumped 21 bbl Hi-Vis mud spacer, followed by 6% KCL brine, w/ 190 bbls pumped saw dirty brine back at shakers, pumped a 157 bbls extra to clean up brine. Total pumped=368 bbls. GPM-276 SPP=3463 psi.;B/O XO, side entry sub, TIW, & 5' pup and L/D same, blow down lines, flushed MP #2, cleared & cleaned rig floor.;POOH F/8004' L/D 2-7/8" PH-6 work string, vacuuming wiper balls through pipe, re-doping threads, & installing thread protectors on tight. P/U-60K S/O-37K Current depth of 6608' . Cont. working on cleaning pits & hauling off mud.;Hauled 10 bbls solids to KGFG&I Cumulative 818 bbls Hauled 175 bbls fluid to KGF G&I Cumulative 3313 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 3581 bbl 16" X 7-5/8" = 0 psi 5/20/2020 Continue POOH F/6608' L/D 2-7/8" PH-6 work string, vacuuming wiper balls through pipe, re-doping threads, & installing thread protectors Inspect brk/dn and l/dn bha #7.;Set TWC.;R/dn weather ford / service rig trouble shoot TDS elect readings / flush lines w/ Barakleen.;Flushed MP's, TD, kill line & choke manifold, blew down lines.;Pressured down koomey, N/D BOP's, removed flow line, flow box, kill & choke from HCR's. trolley stack off to side, brought in and installed dry hole tree, tested void on tree to 250 Low/5000 psi High 5/15 min (ok), R/U & tested tree w/ test pump 250 Low/5000 psi High 5/10 min (ok), pulled TWC,;and shut in master valve on tree, R/D Gen # 3 & moved away from rig along w/ mud lab. finished cleaning in pits.;Removed koomey lines between koomey house & sub base, removed bales, saver sub clamp & saver sub. Cont. R/D MP's & changing liners & swabs to 5.5", and R/D in pits. Last Report for KU-24-32. Changing AFE # @ Midnight to well KU 42-12.;Hauled 4 bbls solids to KGFG&I Cumulative 822 bbls Hauled 736 bbls fluid to KGF G&I Cumulative 4019 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs Losses to hole 0 bbls Total losses to hole 3581 bbl 16" X 7-5/8" = 0 psi g pp Halliburton pressure tested lines at 580 gppg p low 4050 high, good tests. Halliburton pumped 36.9 bbls 10.5 ppg Tuned Prime Spacer at 1.5 to 2.5 bpm-364 to 420 psi then dropped bottom plug. Loaded top gg p p ppg p p p pp pg p plug in;plug launcher, followed by pumping 122.4 bbls (295 sx) 12.0 ppg Type I II lead cement at 3 to 4 bpm-380 to 45 psi, 21.4 bph return flow rate, followed by pg pg yp pg ( ) ppgyp p p py 23.3 bbls (85 sx) 15.3 ppg Class G tail cement at 2 bpm-50 psi. Halliburton dropped top plug, then displaced with 9.0 ppg 6% KCL PHPA mud at 5 to;7 bpm-50 ( ) ppg p p pp p p g p ppg p to 1500 psi. Increased rate to catch up with cement. Caught cement and pressure 35 bbls into displacement and slowed to 5 bpm-150 psi. Slowed pump to 3 ppgp bpm with 12 bbls to go. Did bump the plug at 180.5 bbls into displacement (calculated 187 bbls) ;R/dn bope testing equipment and r/up test 5-1/2" csg and test same t/ 3500 gp psi on chart 30 min good test and service Note: lost 318 bbls during cement job Cont PU single in hole from 4210’ with 5 1/2" 17# L-80 casing, top filling on the fly, topping off every 10 joints. Stopped at 5219’ and 6706’ and circulated for a bit gg just to ensure we did get some returns, which we did. Broke off Activity Date Ops Summary 5/23/2020 5 am sign in and mobe to location. PTW and JSA. Spot equipment and rig up wireline pack-off.,RIH with Halliburton cement bond log and check tool out on way down hole and correlated with HES LWD. Tagged at 8029.5' . Had excellent cement from 8029.5' to 6270'. 6270' to 5600' 30 to 40% bond. 5600' to 1766' had patchy cement bond. 1766' to 1200' pratically no cement bond. This was from Halliburton Engr. He will send a finished copy when he gets back to his shop.,Rig down off well and park equipment on pad to do the perforating. 6/9/2020 PTW, JSA with SLB coil crew, Cruz crane op and Hilcorp Rep.,MIRU SLB CTU 13 with 1.75" CT.,24 Hr. BOPE test witness notification sent 6/8/2020 @ 11:35 AM. Witness waived by Jim Regg @ 12:09 PM on 6/8/2020. Start BOPE test. Test all rams and valves 250/4000 psi . Perform accumulator draw down test. BOPE test passed.,Make up coil connector. Top off equipment with diesel. 6/10/2020 PTW, JSA.,Pick injector head. Make up Reverse out BHA. Stab on well. PT stack 250/4000 psi. Cool down N2. PT n2 lines 250/4000 psi.,Bleed down PT. Open master and swab 23.5 turns. RIH Online with N2 800 scf/min down CT. Returns open to tank. 141 bbls returned conventionally. Tagged PBTD @ 8007 CTMD. Swap to reverse out.,While parked at 8007' reversed out an additional 79 bbls of fluid. N2 at surface. POOH. Close in choke. Pressure up well to 1750 psi.,Tagged up at surface. SITP 1750 psi. Total fluid recovered 220 bbls. Total N2 pumped 285,528 scf or 3066 gallons. Rig down coil unit. Move equipment to KTU 24-06H. 6/11/2020 PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 3500 psi high. TP - 1700 psi. Bleed pressure to 1600 psi.,RIH w/3-3/8"x10' Razor HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 7685' to 7695'. Spot and fire gun with 1602 psi. After 5 mi n - 1606.2 psi, 10 min -1606.7 psi and 15 min - 1606.1 psi. POOH. All shots fired and gun was dry.,RIH w/3-3/8"x20' Razor HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 6666' to 6686'. Spot and fire gun with 1600 psi. After 5 mi n - 1608 psi, 10 min -1609.7 psi and 15 min - 1610 psi. POOH. All shots fired and gun was dry.,Rig down lubricator and turn well over to field. Halliburton equipment still on location 6/12/2020 PTW and JSA. Rig up lubricator. PT to 250 psi low and 4000 psi high.,RIH w/GPT tool and tie into OHL. Find fluid level at 1352' going down and ran across perf zones while blowing well down. Looked like fluid entering both. POOH and found fluid at 886'.,RIH w/2' bailer down to 1400' and got a fluid sample. POOH. Leave sample on Kevins desk.,Rig down lubricator and secure well. Will be doing some meeting work for the next few days. Have a Halliburton Retrievable bridge plug coming from anchorage. 6/15/2020 Sign in. PTW and JSA. Rig up lubricator. PT to 250 psi low and 3500 psi high.,RIH with GPT tool to 878' and find fluid level. Pull back up in lubricator, Have SIMOPs with SLB N2. Rig up hard lines and PT to 3500 psi. Start pushing fluid into perfs w/N2 down to 6768' bringing pressure up to 1500 scfd, Ran a correlation log across open perfs from 7685' to 7695' and 6666' to 6686', Send to town. Fluid broke over at 2500 psi. POOH.,RIH w/Halliburton Evotrieve RBP, tie into GPT log and spot plug at 7600' w/1995 psi on tubing. This is a DPT (timer) plug. Had timer set for 2 hours, Wait another 30 min and plug set. PU 30' and went back down and tag plug. POOH. Look like good set.,Rig down lubricator and turn well over to field. We were using AKE-Line 7" lubricator to set plug. Halliburton doesn't have that big lub. AKE-Line said to call them when we need to use it to pull plug. 6/16/2020 ARRIVE AT PWL SHOP - CALL OUT FOR CREW TO KGF- LOADOUT TOOLS AND EQUIPMENT TRAVEL TO KFG ARRIVE AT KFG OFFICE DO PERMIT JSA AND TGSM RIG UP SLICKLINE AND TALK WITH BILLY ABOUT JOB P/T LUB 2500 PSI FAIL ON PRESSURE UP FIX LEAK- RETEST GOOD - BLEED FLUID FROM LUB PRIOR TO OPEN,RIH/W 4.5" LIB FOUND FLUID LEVEL AT 4200' SLM TAG OBSTRUCTION AT 7477 W/T 10 TIMES POOH OOH/W IMPRESSION OF SAND ON FACE- SIDES HAVE GOUGES POSSIBLY FROM PERFS AT 6666` to 6668' (LOTS OF TROUBLE FALLING DUE TO ELINE GREASE),OOH TALK WITH BILLY AND CHAD ABOUT WELL CONDITIONS- CONFRENCE CALL WITH ENGINEERS IN TOWN- HAVE TOOLS SENT FROM PWL SHOP STANDBY FOR TOOLS- PUMP 15 GALLONS DIESAL IN WELL TO HELP WITH ELINE GREASE RIH/W KUSTER SAMPLE BAILER TO 6665' RKB (6647' SLM) SET FIRE TIMER TO GO OFF AT 17:45 WAIT 15 MINS THEN POOH,RIH/W 3" DD BAILER TO 7477' RKB W/T TO 7482'KB. POOH. OOH/W SAMPLE OF MOIST SAND THAT WAS PACKED SOLID IN BAILER.,RIG DOWN LUBRICATOR. PUT SAMPLES ON LEAD OP DESK. WILL BE BACK IN AM. 6/22/2020 Sign in. Mobe equipment to location. PTW, JSA and safety meeting w/Halliburton and SLB N2. Spot and rig up equipment. PT hard lines and lubricator to 250 psi low and 4500 psi high.,RIH w/GPT and find fluid level at 3426'. Pick up in lubricator. Cool down N2 and sart pumping as we go in hole with GPT. Went on down to 6500 psi and waited until fluid passed by. Pumping N2 at 2500 psi and was building pressure slowly. Pushed fluid to bottom of open perfs at 6686'. Pressure was 2800 psi. Shut down N2. Run correlation log and send to town. POOH.,RIH with 5-1/2" CIBP and tie into GPT log that we had to add 2' to log. Pressured up tubing to 2800 psi from 2200 psi. Set plug at 6655' with 2800 psi on tubing. Lost 100 lb of line tension when plug set. Waited 5 min. Picked up 30' and went back down and tagged plug. POOH and setting tool looked ok.,RIH w/3-3/8"x8' and tied into OHL. Bleed down tubing while running correlation log and sending to town. Get ok to perf from 6632' to 6640' with 1032 psi on tubing. Spotted and fired gun. Pressure built to 1038 psi when shot and stayed there for 15 min. POOH. All shots fired and gun was dry.,Rig down lubricator and turn well over to field. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: KEU KU 24-32 Kenai Gas Field Hilcorp Energy Company Composite Report Kenai, Alaska Contractor AFE #: AFE $: Job Name:2011534C KU 24-32 Completion Spud Date: yg ,RIH w/GPT and find fluid level at 3426'. Pick p Swap to reverse out.,While parked at 8007' reversed out an additional 79 bbls of fluid. ,MIRU SLB CTU 13 with 1.75" CT.,24 Hr. Completion Operations ... sundry 320-225 pg p Get ok to perf from 7685' to 7695' g Set plug at 6655' w ggp p ,RIH w/Halliburton Evotrieve RBP, tie into GPT gpp log and spot plug at 7600' w/1995 psi on tubing CBL pgp POOH.,RIH with 5-1/2" CIBP and gp p Had excellent cement from 8029.5' to 6270'. 6270' to 5600' 30 6/24/2020 Sign in. Mobe to location. PTW, JSA and SIMOPS w/Halliburton and SLB N2. Spot and rig up equipment and PT hard lines and lubricator to 250 psi low and 4200 psi. high.,RIH w/GPT and tie into OHL. Find FL at 4200'. Start pushing fluid with N2 working their way up to 2900 psi at 2500 scf. Pushed fluid away down to 6639'with well static at 2100 psi. POOH.,Started in hole with 4.24" OD CIBP and got stuck in tree. Closed bottom ram and pull plug from tree. Had 1 of 4 bottom slips came out. We were lucky and fished it out of tree. Had another plug sent out. RIH with another plug and tie into OHL. Used GPT correlation log to tie in. Pressure tubing up to 2400 psi and set plug at 6610'. Lost 150 psi on line tension. Picked up 25' and slacked back down and tag plug. POOH.,RIH w/3-3/8"x6' HC Razor, 6 spf, 60 deg phase and tie into OHL. Bleed well down to 5020 psi. Run correlation log and send to town. Get ok to perf from 6573' to 6579' with 519 psi. Spotted and fired gun. Pressure went to 523 psi. Afteer 5 min - 533 psi, 10 min - 538 psi and 10 min - 542 psi. POOH. All shots fired and gun was dry.,RIH w/3- 3/8"x6' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 6556' to 6562' with 568 psi. Spotted and fired gun. After 5 min - 577 psi, 10 min - 582 psi and 15 min - 586 psi. POOH. All shots fired and gun was wet.,Rig down lubricator and turn well over to field. 6/26/2020 Sign in. Mobe to location. PTW and JSA. SIMOPS with Halliburton and SLB N2. Rig up hard lines and lubricator. PT to 250 psi low and 4000 psi high.,RIH w/GPT and tie into OHL. Found fluid level at 3800'. Started pushing fluid away with N2 and pushed it to perf depth at 6574' with pressure breaking over at 2320 psi. Watch fluid go by with GPT tool. Ran strip log and send to town. POOH,Picked plug up into lubricator and when SLB was going to pressure lubricator up to well pressure it got away from them and pressured lub up to 1700 psi to fast, It push tools up and knocked the slips out of plug. Bed pressure and while waiting on another plug fished the slips off top of bottom master. Couldn't find another Geo plug so had to use a Halliburton plug which i s about 1000 to 1500 dollars more.,RIH w/Halliburton CIBP and tie into GPT log. Ran correlation and set plug at 6532' with 1495 psi on tubing. Wanted plug at 6530' but was 2' off on my correlation. Lost 150 lbs line tension. Picked up 25' and back down and tag plug. POOH. Good set,RIH w/3-3/8"x20' HC Razor, 6 spf, 60 deg phase and tie into OHL. Ran correlation log and send to town. Get ok to perf from 5360' to 5380' with 75.5 psi on tubing. Spotted and fired gun. After 5 min - 208.5 psi, 10 min - 409.2 min and 15 min - 484.8 psi. POOH. All shoots fired and guns bull plug was packed with wet sand.,Rig down lubricator and turn well over to field. SLB N2 rigged down at 1530 hrs. 7/24/2020 Hold PJSM.,R/U SLB coil unit. spot all components around well. R/U BOP equipment. test same to 250 low 4000 high. test good. Witness was waived by AOGCC. Bleed down pressure, cont. R/U BOP on wellhead w/ cruz crane. Clean up and shut down for the night. 7/25/2020 PJSM,R/U SLB INJ Head and Test Pack off 250/4000 PSI All good Continue RIH w/ BHA #1 Down jet, MBT,X-over, DPCV and CC . Tot BHA= 6.07' and tag @ 5373' wash f/5374' t/ 6532' @1.5 BBLs min w/ 3200-PSI Tag CIBP @ 6532' W/CTM Clean up W/ Form and water F/ 6532' to 5400' and Blow down well w/N2 t/surface and leave 1100 PSI on well Bore POOH Would not hold 2000 PSI .,Shut Well in , L/D BHA # 1 R/D Inj head ,SLB BOP and Set on Rack , stack out components on side of pad RDMO Recover 7 bbl of cilt sand 7/27/2020 Sign in. Mobe to location. PTW and JSA. PT to 250 psi low and 3000 psi high. TP was 900 psi. Coil tubing tried to put 2000 psi of N2 yesterday but it broke over at 1460 psi and left the well with 1100 psi.,RIH w/Halliburton ACX tool string 1.69" OD with 2 finger centralizers. and tie into OHL. Had quite a bit of trouble getting tools to act right. It was sorta good for a while and then go bad. Tools set down at 6154'. Called town and decision made to get slickline out tomorrow. POOH. Bottom of tool had Beluga mud mashed in the slots of the temperture tool that is on bottom of tool string.,Rig down lubricator andequipment. Taking wireline truck to shop and work on the tool and double check line. If slickline gets down and finishes around noon then I will try and get Halliburton back out to run the log if they think everything is fixed. 7/28/2020 ARRIVE @ KGF OFFICE, SIGN-IN, PERMIT/JSA/TALK W/PROD LEAD OP ABOUT DAYS OPERATIONS CHECK FLUIDS AND INSPECT WIRELINE UNIT FOR READINESS SPOT EQUIPMENT, RU SLICKLINE PT LUBRICATOR TO 2500 PSI, PASS,RIH W/4.60" FLUTED CENTRALIZER TO 5378KB, SET DOWN, W/T MULTIPLE TIMES, CANNOT PASS, POOH RIH W/4.49" FLUTED CENTRALIZER TO 6161KB, SET DOWN, W/T CANNOT PASS, SLIGHTLY STICKYFL - 5240' KB ADD STICK OF 4.5" LUBRICATOR RIH W/ 9'x3" DD BAILER TO 6161KB W/T 6163KB, POOH W/ FULL BAILER OF MUD, TALK W/BILLY APPLEWHITE AND HE WILL CONFER W/MIKE QUICK ABOUT PLAN FORWARD,RIH W/SAME TO 6166KB W/T 6167KB, POOH W/ FULL MUD - ADD KNUCKLE JAR + 3' x 1.75" STEM14 RIH W/3.5" x 11' DD BAILER TO 6166KB W/T 6173KB POOH W/ EMPTY BAILER RIH W/SAME W/BALL BOTTOM TO 6175KB W/T 6180KB POOH W/FULL MUD AND DRY SAND IN BTM RIH W/SAME TO 6183KB W/T 6186KB POOH W/ SAME,RIH W/SAME TO 6187KB W/T 6189KB POOH OOH, LAY DOWN LUBRICATOR, CUT WIRE, RE-HEAD DEPART FIELD 7/29/2020 ARRIVE @ KGF OFFICE, SIGN-IN/PERMIT/JSA, TALK W/LEAD OP RU SLICKLINE, ADD 4.5" WLV & PUMP-IN-SUB PT LUB TO 2500 PSI, PASS RIH W/3.5" x 10' DD BAILER TO 6181KB W/T 6187KB POOH W/ FULL THICK MUD,RIH W/SAME TO 6189KB W/T 6191KB POOH W/FULL SLURRY AND DRY SAND IN BAILER BALL BTM RIH W/SAME W/ FLAPPER BTM TO 6192KB W/T 6194KB POOH EMPTY BAILER RIH W/SAME W/BALL BTM TO 6193KB W/T 6194KB POOH W/FULL MUD W/SAND IN BAILER BTM RIH W/SAME TO 6197KB W/T 6198KB POOH W/SAME,RIH W/SAME TO 6199KB W/T 6200KB POOH W/SAME RIH W/SAME TO 6203KB W/T 6205KB POOH W/SAME RIH W/SAME TO 6206KB W/T MAKE NO HOLE POOH W/SAME RD SLICKLINE DEPART FIELD 7/30/2020 Move F/ Frances #1 to KGF well 24-34,MIRU on 24-34 SLB unit 13,Test BOP t/ 250/4000 PSI All SLB components w/ AOGCC Jim Rigg test witness waved by Jim Rigg,R/D bop test equipment and stack up bop on well head .secure well for the night 7/31/2020 PTW, JSA with crew.,Fire equipment. Pick injector head stab lubricator. Load N2 from Air liquid transport.,Stab on well. PT stack 250/4000 psi.,Open well. Initial WHP 1200 psi. RIH against closed choke. Wt check 5300' 11k Dry tag 6199" CTMD. Pick up to 5300' Online with produced water down CT at 1.7 bbls/min to fill well. Bleed down whp (nitrogen). Attempted to see if well will hold a column of fluid. Pumped 145 bbls with no returns. SL report showed fluid level after perf was at 3800'. Pick up and park at 4000' Online with N2 and foam.,Slowly pick up OOH. 2731' CTMD N2 at surface. RIH to perform nitrified FCO online with N2 at 1500 scf/min and 1.1 bbls/min. Good fluid and n2 returns to surface. Tag top of plug at 6543' CTMD. Wash up and down 4 times from 5300' to 6543' CTMD. Keeping choke pinched in at 550-700 psi. Equivalent pump rate 2.25 bbls/min 4.26 ppg. Hydrostatic at ct depth of 6543 is 1946 psi, Annular velocity 112 ft/m,Pump bottoms up. chase bottoms up OOH. POOH to surface.,Once bottoms up reached surface Close choke and pressure up well to 1500 psi. Tagged up. Shut in well. Rig back ctu. Plan to have Slick line out in the AM to check tag depths. 8/1/2020 ARRIVE KGF MEET W/ KREIG JSA PERMIT,RIG UP SLICKLINE P/T LUB. TO 2500PSI GOOD TEST,RIH W/ 2.5''X12' DD BAILER TO 6235'KB W/ TOOL POOH FULL DRY SAND - DISCUSS PLAN FORWARD W/ MIKE & COLE,RIH W/ SAME TO 6241'KB W/ TOOL POOH EMPTY FLAPPER STUCK OPEN,RIH W/ SAME TO 6244'KB W/ TOOL POOH 1/2 FULL SAND DISCUSS PLAN FORWARD W/ COLE,RIG DOWN SLICKLINE SECURE WELL FOR COIL MOVE TO KU 42-12 pg p p pg pg ,RIH w/Halliburton CIBP and tie into GPT log. Ran correlation and set plug at 6532' with 1495 psi on tubing. Wanted plug at 6530' but was 2' off on my correlation. gp g perf from 5360' to 5380' with g pg Get ok to perf from 6573' to 6579' and set plug at 6610'. CIBP at 6610ft location. PTW, JSA and SIMOPS w/Halliburton and SLB N2. SIMOPS with Halliburton and SLB N2. CIBP at 6532 ft 8/2/2020 PTW, JSA with SLB coil.,Stab on well PT stack 250/4000 psi. Open well. Initial WHP 825 psi. RIH for reverse FCO.,Cool down N2. 3500' online with n2 at 1000 scf/min down 5.5' casing. Unload 30 bbls of water. Continue RIH unloading backside CT x casing to 5000' CTMD.,Start FCO with gel/foam and N2 at .5 bbls/min and 1200 scf/min. WHP or circulating pressure since doing reverse FCO is 1400 psi. 1500 psi well takes pressure. Set down at 5167' 4K. Pick up clean. Continue in hole to 6,074' lost returns. Pick up to 4750' returns to surface but slow. Reverse N2 lift not working. Decided to swap and go conventional. Prior to conventional clean out pump 25 bbls gel .,Swap iron. Spear coil with 5 bbls of gel. Online for conventional clean out down CT at 1400 scf/min and 1 bbl/min of foam and flo-vis gel.,increae rates. 1500 scf/min and 1.1 bbls/min . Equivalent pump rate 4 bbls/min and 200 ft/m in. wash from 5300'-6543 4 times. Pump bottoms up and chase to surface. Return tank as 12 bbls of sand in tank.,POOH chasing bottoms up to surface. At 5300' lay in water to surface. Tagged up SITP 1160 psi. Shut in well. Rig down SLB coil.,3600 gallons of N2 pumped. 189 bbls of water gel pumped for FCO . Total solids in return tank 25 bbls. 8/3/2020 Sign in. Mobe to location. PTW and JSA. Rig up equipment and lubricator. PT to 250 psi low and 3000 psi high. TP - 900 psi,RIH w/ACX log down at 30 fpm from 3800' to 6391'. Tied log in with CBL. Engr notes on what depths they heard noise. Started logging up from 6391' at 20 fpm and take notes where noise was. Plan on sending log and notes to Fanny with Halliburton and she will let engineer know what depths to take stops at. Logged up to 3800'. Called Fanny with Halliburton and she is telling engineer where to take stops at.,-There are 8 stops - 1) 3970', 2) 4462', 3) 4472', 4) 4772', 5) 5370' 6) 5778', 7) 6240' 8) 6374'. They will do a 5 min stop approx. 10' below each stop, 5 min at stop and 5 min approx. 10' above each stop.,Rig down Equipment and secure well and turn well over to field 9/10/2020 Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT Lubricator to 250 psi low to 3000 psi high. TP 950 psi,RIH with JB/4.26" GR and run down to 5550' tie into OHL. Had no problem going in hole but had a couple of issues with grease head coming out of hole. OOH and fixed grease head.,MU CIBP, RIH with CIBP and tie into OHL. Run correlation log and send to town. Get ok to set CIBP at 5450' with 950 psi on tubing, Plug will have at least that much pressure under plug if milled out. Spot and set plug at 5450'. PU 25' and go down and tag plug. OOH and everything looks ok. Good set.,Rig down E- Line equipment and turn well over to field. pgg p g g ,MU CIBP, RIH with CIBP and tie into OHL. Run correlation log and send to town. 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'!AD'!A A Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.05.14 10:29:12 -08'00'Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.05.14 14:01:04 -08'00' TD Shoe Depth: PBTD: Jts. 1 2 41 Yes X No X Yes No Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Float Shoe 8 3/4 Rotate Csg Recip Csg Ft. Min. PPG9 Shoe @ 1784 FC @ Top of Liner1,698.00 Floats Held 78 160 24 136 Spud Mud CASING RECORD County Kenai State Alaska Supv.S Hauck/J Riley Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.KEU KU 24-32 Date Run 2-May-20 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top DWC 2.07 1,784.12 1,782.05 Csg Wt. On Hook: Type Float Collar: No. Hrs to Run: 9.1 5 480FIRST STAGE10.5 42 76.5/78 2000Halliburton 15.8 40 Bump pressBump Plug? 6:20 5/3/2020 0 1,784.001,795.00 CEMENTING REPORT Csg Wt. On Slips: Spud Mud 12 120 Type of Shoe: Casing Crew:Weatherford www.wellez.net WellEz Information Management LLC ver_04818br 5 One Every other jt 19 total from shoe jt t/ jt #37 7 /8'' Casing Jt 7 5/8 29.7 L-80 DWC 41.60 1,782.05 1,740.45 7 5/8'' Casing Jt 7 5/8 29.7 L-80 DWC 40.50 1,740.45 1,699.95 Float Collar 8 3/4 DWC 1.30 1,699.95 1,698.65 7 5/8'' Casing jt 7 5/8 29.7 L-80 Hyd 563 1,673.06 1,698.65 25.59 7 5/8'' Casing Pup Jt 7 5/8 29.7 L-80 Hyd 563 2.56 25.59 23.03 Hanger 11 3/4 1.83 23.03 21.20 275 2.4 175 1.17 5 TD Shoe Depth: PBTD: Jts. 2 8 1 17 1 9 1 128 34 Yes X No Yes No Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes X No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Type I II 295 2.19 Class G 85 1.24 4 6,554.41 Casing 5 1/2 17.0 L-80 CDC HTQ USS 5,143.31 6,554.41 1,411.10 6,954.88 6,592.84 RA marker C 5 1/2 17.0 L-80 CDC HTQ USS 38.43 6,592.84 39.44 6,994.32 6,954.88 Casing 5 1/2 17.0 L-80 CDC HTQ USS 362.04 RA marker B 5 1/2 17.0 L-80 CDC HTQ USS 7,675.80 Casing 5 1/2 17.0 L-80 CDC HTQ USS 681.48 7,675.80 6,994.32 8,038.01 7,715.77 RA marker A 5 1/2 17.0 L-80 CDC HTQ USS 39.97 7,715.77 1.22 8,039.23 8,038.01 Casing 5 1/2 17.0 L-80 CDC HTQ USS 322.24 Float Collar 6 CDC HTQ Innovex Ran 150 centralizers Casing 5 1/2 17.0 L-80 CDC HTQ USS 80.00 8,119.23 8,039.23 www.wellez.net WellEz Information Management LLC ver_04818br 2 Type of Shoe:Bullnose Casing Crew:Weatherford 19.11 12 122.4 8,121.038,155.00 CEMENTING REPORT Csg Wt. On Slips: 6% KCL PHPA fresh water based drilling fluid 19:15 5/18/2020 6,270 15.3 23.3 Bump press CBL Bump Plug? 180.5/183 2200Cmt pumpFIRST STAGE10.5Tune spacer 36.9 95 7 1037 Csg Wt. On Hook: Type Float Collar:Innovex No. Hrs to Run:20.5 1,387.62 23.82 4.01 23.82 19.81 1,363.80Casing 5 1/2 17.0 L-80 CDC HTQ Hanger 10 3/4 19.81 USS 9.80 L-80 CDC USS USS 1,397.42 CDC 0.71 5 1/2 17.0 5 1/2 17.0 L-80 BTC 5 1/2 17.0 L-80 BTC USS 1,408.406 10.98 CDC HTQ Innovex 1.80 8,121.03 8,119.23 1,397.42 1,387.62 2.70 1,411.10 1,408.40 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.KEU KU 24-32 Date Run 17-May-20 CASING RECORD County Kenai State Alaska Supv.R Pederson /J Richardson 8,038.01 Floats Held 10 145.7 0 145.7 6% KCL PHPA mud Rotate Csg Recip Csg Ft. Min. PPG9.1 Shoe @ 8121.03 FC @ Top of Liner 94 103.4 10 Pup Pup Casing (Or Liner) Detail Shoe Pup 6.35" Swell Packer 6 note: lost 318 bbls during job (gls 10/16/20) :LQVWRQ+XJK(&(' )URP&RG\'LQJHUFGLQJHU#KLOFRUSFRP! 6HQW7KXUVGD\6HSWHPEHU$0 7R:LQVWRQ+XJK(&(' 6XEMHFW5(>(;7(51$/@.8:HOO&RPSOHWLRQ5HSRUW4XHVWLRQV 'ŽŽĚŵŽƌŶŝŶŐ,ƵĞǇ͕ dŚĞǁĞůůǁĂƐŽƌŝŐŝŶĂůůǇƐƵƉƉŽƐĞĚƚŽďĞĂĞůƵŐĂͬhƉƉĞƌdǇŽŶĞŬ'WŽƌdǇŽŶĞŬ'Wϭ͕ďƵƚŶĞŝƚŚĞƌŽĨƚŚŽƐĞƉŽŽůƐǁĞƌĞ ƉƌŽĚƵĐƚŝǀĞƐŽǁĞŵŽǀĞĚƵƉŚŽůĞƚŽƚŚĞƐƚĞƌůŝŶŐƐĂŶĚƐ;ĂůƐŽŶŽƚƉƌŽĚƵĐŝŶŐĂƚƚŚŝƐƚŝŵĞͿ͘^ĞĞŵƐǁĞŵĂǇŚĂǀĞƐƚƌƵĐŬŽƵƚ ŽŶƚŚŝƐŽŶĞ͘ dŚĞƚŽƉƉĞƌĨŽƌ;dW,ͿŝƐŶŽƚĐƵƌƌĞŶƚůǇƉƌŽĚƵĐŝŶŐĂŶĚũƵƐƚǁĂŶƚĞĚƚŽŶŽƚĞƚŚĂƚ͕ŐŝǀĞŶƚŚĂƚƚŚĞ͞W͟ŝŶdW/ŝƐĨŽƌ ƉƌŽĚƵĐƚŝǀĞ͘/ŬŶĞǁ/ƐŚŽƵůĚŶ͛ƚůĞĂǀĞŝƚďůĂŶŬ͕ďƵƚƐĂǇŝŶŐƚŚĂƚŝƚƐ͞ƉƌŽĚƵĐƚŝǀĞ͟ǁŽƵůĚďĞŵŝƐůĞĂĚŝŶŐ͘ ŽĚǇŝŶŐĞƌ ,ŝůĐŽƌƉůĂƐŬĂ͕>> ƌŝůůŝŶŐdĞĐŚ ϵϬϳͲϳϳϳͲϴϯϴϵ &ƌŽŵ͗tŝŶƐƚŽŶ͕,ƵŐŚ;Ϳ΀ŵĂŝůƚŽ͗ŚƵŐŚ͘ǁŝŶƐƚŽŶΛĂůĂƐŬĂ͘ŐŽǀ΁ ^ĞŶƚ͗tĞĚŶĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϮϯ͕ϮϬϮϬϰ͗ϬϳWD dŽ͗ŽĚǇŝŶŐĞƌфĐĚŝŶŐĞƌΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗΀ydZE>΁<hϮϰͲϯϮtĞůůŽŵƉůĞƚŝŽŶZĞƉŽƌƚYƵĞƐƚŝŽŶƐ ,ŝŽĚǇ͕ dŚĞƉŽŽůƌĞƉŽƌƚĞĚŽŶƚŚŝƐϭϬͲϰϬϳŝƐ^ƚĞƌůŝŶŐhŶĚĞĨŝŶĞĚ͘,ŽǁĞǀĞƌƚŚĞƉĞƌŵŝƚůŝƐƚƐƚŚĞƉŽŽůĂƐƚŚĞ<ĞŶĂŝ͕dǇŽŶĞŬ'ĂƐWŽŽů͘ tĂƐƚŚŝƐĂŶĞƌƌŽƌ͕ŽƌŚĂƐƚŚĞƌĞďĞĞŶĂĐŚĂŶŐĞƐŝŶĐĞƚŚĞǁĞůůǁĂƐƉĞƌŵŝƚƚĞĚ͍ĚĚŝƚŝŽŶĂůůǇ͕ĐĂŶǇŽƵĞǆƉůĂŝŶƚŚĞŶŽƚĞǇŽƵ ĂĚĚĞĚŝŶďŽǆϮϵĂďŽƵƚƚŚĞƚŽƉƉĞƌĨďĞŝŶŐŶŽŶͲƉƌŽĚƵĐƚŝǀĞ͍dŚĂŶŬƐ ,ƵĞǇtŝŶƐƚŽŶ ^ƚĂƚŝƐƚŝĐĂůdĞĐŚŶŝĐŝĂŶ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ ŚƵŐŚ͘ǁŝŶƐƚŽŶΛĂůĂƐŬĂ͘ŐŽǀ ϵϬϳͲϳϵϯͲϭϮϰϭ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avid Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchrage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE 09/10/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (220-037) HALLIBURTON RCBL 05-29-2020 Please include current contact information if different from above. Received by the AOGCC 09/10/2020 PTD: 2200370 E-Set: 33820 Abby Bell 09/10/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (220-037) ELOGS Please include current contact information if different from above. Received by the AOGCC 07/20/2020 PTD: 2200370 E-Set: 33562 Abby Bell 07/20/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-32 (220-037) MUDLOG DATA Please include current contact information if different from above. Received by the AOGCC 07/20/2020 PTD: 2200370 E-Set: 33563 Abby Bell 07/20/2020 From:Loepp, Victoria T (CED) To:Mike Quick Subject:Hilcorp KU 24-32 PTD 220-037 Date:Monday, July 20, 2020 1:13:35 PM Mike, Approval is granted for the procedure modification as outlined below. Thanx, Victoria Sent from my iPhone On Jul 20, 2020, at 10:38 AM, Mike Quick <mquick@hilcorp.com> wrote: Hello Victoria – Hope that you had a nice weekend. Hilcorp has revised our schedule, and we plan to move coil tubing to this well (KU 24- 32) on Wednesday, 7/22, to blow down/clean out the well as outlined below. Please let me know if you have any questions on the work scope below. Thanks, Mike From: Mike Quick Sent: Thursday, July 16, 2020 2:29 PM To: victoria.loepp@alaska.gov Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: Hilcorp KU 24-32 PTD 220-037 Victoria – On the new drilled gas well, KU 24-32, PTD 220-037, Hilcorp has 3 approved sundry’s, as the work scope has changed during the course of trying to find commercial gas in this well. The sundry numbers are 320-205, 320-225, and 320-276. Under these sundry’s, we have approval for both coil tubing blow down with N2, and cement squeezes with coil to isolate any perforated zones that produced water/fill. The last zone perforated 5360’ to 5380’ brought in water and fill. There is a CIBP set at 6532’. These are the only open/non-isolated perforations in the well. Hilcorp is planning to use coil tubing with N2 to clean out the water and any fill that was brought in after perforating and flowing the well from the 5360’ to 5380’ zone. We will then run an acoustic log to see if we can determine if water is moving behind the casing, or if the water was from the zone we perforated. I believe the coil blow down/clean out with N2 is covered under the coil tubing blow down with N2 work approved in sundry 320-225, but wanted to keep you updated on the steps we are taking to get this well online. Please let me know if you have any questions, or would like additional paperwork submitted on this plan. TIMING: Hilcorp will likely move back on this well with Coil Tubing on 7/27. Thanks, Mike Michael Quick Hilcorp Alaska, LLC Operations Engineer Office 907-777-8442 Cell 907-317-2969 Email mquick@hilcorp.com Hilcorp A Company Built on Energy The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 00 0 - 31 - Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 �T Anchorage, AK 99503 Tele: 907 777-8337 iriif•„rp %1.1�k;,.13A. E-mail: doudean@hilcorp.com DATE 7/02/2020 RECEIVED To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 JUL 0 6 2020 Anchorage, AK 99501 _ . AOGCC WELL BOX SAMPLE INTERVAL KU 24-32 BOX 1 OF 5 1800'— 3150' KU 24-32 BOX 2 OF 5 3150'— 4350' KU 24-32 BOX 3 OF 5 4350' — 5610' KU 24-32 BOX 4 OF 5 5610'— 6960' KU 24-32 BOX 5 OF 5 6960'— 8154' 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 B \\ /; ^ 0 Date: ��q ( 2_(1- �` �� 1 ti X (moi 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: Coil 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): 8,155'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 8,730psi Liner 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: Mike Quick Operations Manager Contact Email: Contact Phone: 777-8442 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 mquick@hilcorp.com 7,057' 8,120' 7,027' 1365 psi N/A Swell Pkr, Perm Packer ; N/A ~1,400'MD / 1,361'TVD; ~6300'MD/4620'TVD; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: 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 ADL392668, FEE AA093808 220-037 50-133-20688-00-00 Kenai Unit (KU) 24-32 Kenai Gas Field - Beluga/Upper Tyonek Gas Pool - Tyonek Gas Pool 1 Length Size 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 10,600psi MD 2,980psi 6,890psi 120' 1,695' 120' 1,784' 7,027'5-1/2" 16" 7-5/8" 120' 1,784' 8,120' Perforation Depth MD (ft): See Attached Schematic 8,120' 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: July 8, 2020 N/A Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:18 am, Jun 24, 2020 320-276 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.06.24 09:08:22 -08'00' Taylor Wellman Perforatef Change Approved Program 10-407 GAS (report sundry 320-225 and 320-276) DSR-6/24/2020 Final well DLB 06/22/2020 Sterling 3 Gas & Sterling 4 Gas (new perfs) DLB X Coil contingency * 14 day limit on flow test without packer/tubing installed. gls 6/24/20Comm 6/25/2020 dts 6/24/20/20 JLC 6/25/2020 Well Prognosis Well: KU 24-32 Date: 6-22-2020 Well Name: KU 24-32 API Number: 50-133-20688-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: July 8, 2020 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-037 First Call Engineer: Michael Quick (907) 777-8442 (O) (907) 317-2969 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: 2011534C Maximum Expected BHP: ~ 1,755 psi @ 3,900’ TVD (Based on 0.45psi/ft gradient) Max. Potential Surface Pressure: ~ 1,365 psi @ 3,900’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KU 24-32 is a grass roots development well targeting gas sands in the Upper Tyonek and Middle and Upper Beluga formations. This new well TD was reached on 5-11-2020. Hilcorp has been perforating the sands approved in Sundry 320-225, and has not yet found commercial hydrocarbons. The purpose of this work/sundry is to add contingency perforation intervals in the Sterling sands, if all the lower sands are deemed non-commercial. These zones would be tested for up to 14 days per zone to confirm commercial zones are encountered before running the completion approved in Sundry 320-225, with the 2-7/8” tubing packer moved above these new perforations and set at +/- 4800’ MD. Notes Regarding Wellbore Condition x Well has been blown down with N2 or is producing some gas. x CIBP’s will set above non-commercial Beluga sands as approved in 320-225. x AOGCC has a CBL on file. E-Line Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 3,500 psi Hi 250 Low. 2. PU RIH W/perf guns. Perforate each interval with 3-1/8” or 3-3/8” Perf guns 6 to 12 JSPF 60 degree phasing. 3. Proposed Perforated Intervals: 4. Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom P3_A8 ±4,987' ±5,033' 46' ±3,691' ±3,737' P3_A9 ±5,050' ±5,065' 15' ±3,732' ±3,747' P3_A10 ±5,100' ±5,165' 65' ±3,765' ±3,830' P3_A 11 ±5,204' ±5,264' 60' ±3,832' ±3,892' P4_B1 ±5,306' ±5,394' 88' ±3,900' ±3,988' These zones would be tested for up to 14 days per zone to confirm commercial zones are encountered before running the completion approved in Sundry 320-225, with the 2-7/8” tubing packer moved above these new perforations and set at +/- 4800’ MD. Additional perforations from 320-225 NOTE: Well did not pass MIT-IA. very little cement in liner overlap and swell packer not holding. Will need to run tubing packer after zone testing is complete. gls P3_A8 ±4,987' ±5,033' 46' ±3,691' ±3,737' P3_A9 ±5,050' ±5,065' 15' ±3,732' ±3,747' P3_A10 ±5,100' ±5,165' 65' ±3,765' ±3,830' P3_A 11 ±5,204' ±5,264' 60' ±3,832' ±3,892' P4_B1 ±5,306' ±5,394' 88' ±3,900' ±3,988' Well Prognosis Well: KU 24-32 Date: 6-22-2020 a. Proposed perfs. also 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 Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. f. These sands are governed by Conservation Order 510A. g. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. CONTINGENCY: If water is encountered in any of these sands, a cement squeeze may be performed on the open perforations, followed by re-perforating the interval. Coil Tubing Contingency Procedure A. MIRU Coil tubing unit. Pressure test BOP to 250 psi low / 4,000 psi high. Notify AOGCC 24 hours in advance of BOP test. B. RIH spot +/- 2 bbls of Class G cement and bradenhead squeeze open perforations with cement, pull out of cement and WOC. C. RIH and wash/ream through cement. D. Rig up E-Line starting at step 1 above to re-perforate interval. 5. POOH. 6. RD e-line. 7. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing). 8. Completion approved in Sundry 320-225 must be ran after no more than 14 days of testing to confirm commercial hydrocarbons. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil BOP Schematic Completion approved in Sundry 320-225 must be ran after no more than 14 days of testing to confirm commercial hydrocarbons. NOTE:------> CONTINGENCY: If water is encountered in any of these sands, a cement squeeze may be performed on y,q the open perforations, followed by re-perforating the interval. contingency cmt sqz with CTU Updated by DMA 05-14-20 SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = ~8,120’ MD / TVD = ~7,027’ TD = 8,155’ MD / TVD = 7,057’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status UB 1X ±6,555' ±6,561' ±4,841' ±4,847' 6' Proposed Sundry 320-205 ±6,571' ±6,577' ±4,856' ±4,862' 6' Proposed Sundry 320-205 UB 2 ±6,630' ±6,647' ±4,907' ±4,924' 17' Proposed Sundry 320-205 6,666' 6,686' 4,938' 4,965' 20' 6/11/2020 Sundry 320-205 UB 3A ±6,736' ±6,753' ±5,003' ±5,020' 17' Proposed Sundry 320-205 UB 6 ±6,985' ±6,995' ±5,232' ±5,242' 10' Proposed Sundry 320-205 MB 4 ±7,457' ±7,468' ±5,687' ±5,698' 11' Proposed Sundry 320-205 MB 6 7,685' 7,695' 5,910' 5,935' 10' 6/11/2020 Sundry 320-205 MB 7 ±7,803' ±7,819' ±6,028' ±6,044' 16' Proposed Sundry 320-205 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf ~1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf ~8,120’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ~1,400’ 4.892” 6.875” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 140 BBL’s of cement in 9-7/8” hole – Returns to surface (50% excess) 5-1/2” 131 BBL’s of cement in 6-3/4” hole. Est. TOC @ ~1,250’ (5% excess) 6-3/4” hole UB 2 MB 6 5-1/2” Evo-Trieve plug set at 7600’ 5-1/2” CIBP set at ~6655’ MD UB 2 MB 6 MIT-IA did not pass. gls NOTE: spotty cement above 5000 ft. md gls Updated by DMA 06-19-20 PROPOSED SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = ~8,120’ MD / TVD = ~7,027’ TD = 8,155’ MD / TVD = 7,057’ RKB to GL = 18’ 3 2 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf ~1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf ~8,120’ TUBING DETAIL 2-7/8” Production 6.4 L-80 8 RD EUE 2.441” Surf ±4,810’ Sundry 320-225 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ~1,400’ 4.892” 6.875” Swell Packer – Sundry 320-205 2 ±4,800’ 2.33” 3.79” 5-1/2” Packer w/snap latch assembly – Sundry 320-225 3 ±4,810’ 2.313” X-Nipple – Sundry 320-225 OPEN HOLE / CEMENT DETAIL 7-5/8" 140 BBL’s of cement in 9-7/8” hole – Returns to surface (50% excess) 5-1/2” 131 BBL’s of cement in 6-3/4” hole. Est. TOC @ ~1,250’ (5% excess) - Sundry 320-205 6-3/4” hole PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status P3_A8 ±4,987' ±5,033' ±3,691' ±3,737' 46' Proposed TBD P3_A9 ±5,050' ±5,065' ±3,732' ±3,747' 15' Proposed TBD P3_A10 ±5,100' ±5,165' ±3,765' ±3,830' 65' Proposed TBD P3_A 11 ±5,204' ±5,264' ±3,832' ±3,892' 60' Proposed TBD P4_B1 ±5,306' ±5,394' ±3,900' ±3,988' 88' Proposed TBD UB 1X ±6,555' ±6,561' ±4,841' ±4,847' 6' Proposed Sundry 320-205 ±6,571' ±6,577' ±4,856' ±4,862' 6' Proposed Sundry 320-205 UB 2 ±6,630' ±6,647' ±4,907' ±4,924' 17' Proposed Sundry 320-205 6,666' 6,686' 4,938' 4,965' 20' 6/11/2020 Sundry 320-205 UB 3A ±6,736' ±6,753' ±5,003' ±5,020' 17' Proposed Sundry 320-205 UB 6 ±6,985' ±6,995' ±5,232' ±5,242' 10' Proposed Sundry 320-205 MB 4 ±7,457' ±7,468' ±5,687' ±5,698' 11' Proposed Sundry 320-205 MB 6 7,685' 7,695' 5,910' 5,935' 10' 6/11/2020 Sundry 320-205 MB 7 ±6,630' ±6,647' ±4,907' ±4,924' 17' Proposed Sundry 320-205 UB 1X UB 2 UB 3A UB 6 MB 4 MB 6 MB 7 X P3_A 11 P4_B1 P3_A8 P3_A9 P3_A10 5-1/2” CIBP to be set above non- producing sands 5-1/2” CIBP set at ~6655’ MD 5-1/2” Evo-Trieve plug set at 7600’ 1 Winston, Hugh E (CED) From:Carlisle, Samantha J (CED) Sent:Wednesday, June 3, 2020 9:24 AM To:Winston, Hugh E (CED) Subject:FW: [EXTERNAL] KU 24-32 sundry (PTD 220-037) Withdrawn sundry. Can you please enter into RBDMS? From: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Sent: Tuesday, June 2, 2020 3:23 PM To: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov> Subject: FW: [EXTERNAL] KU 24‐32 sundry (PTD 220‐037) Can you pull this sundry as per below. Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: Mike Quick <mquick@hilcorp.com> Sent: Tuesday, June 2, 2020 12:53 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: Re: [EXTERNAL] KU 24‐32 sundry (PTD 220‐037) Guy‐ Hilcorp formally requests to withdraw sundry 320‐205 and replace it with the newly submitted sundry. Yes, we will monitor the IA during the duration of testing. Thanks, Mike On Jun 2, 2020, at 12:43 PM, Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> wrote: Mike , Can you reply by email formally requesting to withdraw sundry 320‐205 ( First sundry). Also, is there going to me continual monitoring of the well. Checking IA pressure during the 14 day test? 2 Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793- 1226 ) or (Guy.schwartz@alaska.gov). 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: CT N2 Lift + Run Tubing 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): 8,155'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 8,730psi Liner 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: Mike Quick Operations Manager Contact Email: Contact Phone: 777-8442 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 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, 2020 N/A 8,120' Perforation Depth MD (ft): See Attached Schematic 8,120' 7,027'5-1/2" 16" 7-5/8" 120' 1,784' 2,980psi 6,890psi 120' 1,695' 120' 1,784' N/A TVD Burst N/A 10,600psi MDLength Size 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL392668, FEE AA093808 220-037 50-133-20688-00-00 Kenai Unit (KU) 24-32 Kenai Gas Field - Beluga/Upper Tyonek Gas Pool - Tyonek Gas Pool 1 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic mquick@hilcorp.com 7,057' 8,120' 7,027' 1,997psi N/A Swell Pkr, Perm Packer ; N/A ~1,400'MD / 1,361'TVD; ~6300'MD/4620'TVD; N/A Perforation Depth TVD (ft): Tubing Size: Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 2:31 pm, Jun 01, 2020 320-225 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.06.01 14:06:01 -08'00' Taylor Wellman (CTU) XPerforate f flow test gls 6/2/20 *3500 psi BOPE test (rig 401) * packerless flow test approved for 14 days max. 10-407 DSR-6/1/2020 X 401/CTU * 4000 psi BOPE test SFD 6/1/2020Comm. 6/3/2020 dts 6/3/2020 JLC 6/3/2020 Well Prognosis Well: KU 24-32 Date: 6-1-2020 Well Name: KU 24-32 API Number: 50-133-20688-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: June 15, 2020 Rig: Coil / E-line / HAK 401 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-037 First Call Engineer: Michael Quick (907) 777-8442 (O) (907) 317-2969 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: 2011534C Maximum Expected BHP: ~ 2,600 psi @ 6,028’ TVD (Based on geotap side wall tool data) Max. Potential Surface Pressure: ~ 1,997 psi @ 6,028’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KU 24-32 is a grass roots development well targeting gas sands in the Upper Tyonek and Middle and Upper Beluga formations. This new well TD was reached on 5-11-2020. 5-1/2” casing was ran from TD to surface and cemented in place. Approved sundry 320-205 is valid to jet the well dry with CT, and perforate. Hilcorp requests to replace sundry 320-205 with this new sundry application. Required in the sundry 320-205 was to pressure test the IA to 2500 psi. When Hilcorp attempted this pressure test, the IA would not hold adequate pressure and fluid was pumped away. The swell packer located at 1400 feet has not had adequate time to swell and cannot currently hold pressure. Waiver Request Hilcorp is requesting a waiver from the monitorable annulus required per 20 AAC 25.200 (d) for no more than two weeks per zone in order to perforate, test, and plug back any non-productive intervals prior to running the final completion which will isolate the tubing/casing annulus from fluids being produced. This testing with access to the full bore ID of the well is necessary to perforate with larger casing guns and in order to set plugs or patches to isolate non-productive zones that make water. Once commercial production is established, a packer and production tubing will be ran, with a packer being set at +/-6,300’, below where good cement is known to exist from a cement bond log. The purpose of this work/sundry is to perform the same approved work in Sundry 320-205 under a new temporary waiver for the IA pressure test: work includes blowing the well dry with nitrogen, perforate and test zones until commercial production is established. In addition to the waiver request, this sundry will cover running a completion packer and tubing that will allow for pressure testing the IA. Notes Regarding Wellbore Condition x Well is full with 6% KCl. x CBL has been run, AOGCC has a copy on file. x Well did not pass an MIT-IA. Will run packer and tubing after initial testing. The purpose of this work/sundry is to perform the same approved work in Sundry 320-205 under a new temporary waiver for the IA pressure test: work includes blowing the well dry with nitrogen, perforate and test zones until commercial production is established. In addition to the waiver request, this sundry will cover running a completion packer and tubing that will allow for pressure testing the IA. NOTE: new completion sundry Hilcorp is requesting a waiver from the monitorable annulus required per 20 AAC 25.200 (d) Well Prognosis Well: KU 24-32 Date: 6-1-2020 Safety Concerns x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job). x Ensure all crews are aware of their stop job authority. Coiled Tubing Procedure (Start of Sundry work) 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. 2. MU Jet nozzle. 3. RIH W/ nozzle. RU N2 pumping unit. 4. Drop ball and come online with N2 and jet well dry. a) Estimated volume of displaced 6% KCl is (+/-) 180 bbls. (Based on estimated PBTD of 8,060’). 5. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD. 6. Once well is dry, leave 1,600 psi. on the well for first perforation interval. 7. POOH w/ coil. LD BHA. 8. RDMO Coiled Tubing. E-Line Procedure 9. MIRU e-line and pressure control equipment. PT lubricator to 3,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. a) If necessary, bleed pressure down as requested by the OE to establish a drawdown on the formation. 10. PU RIH W/perf guns. Perforate each interval with 2-7/8” or 3-1/8” Perf guns 6 to 12 JSPF 60 degree phasing. 11. Proposed Perforated Intervals: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom UB 1X ±6,555' ±6,561' 6' ±4,841' ±4,847' UB 1X ±6,571' ±6,577' 6' ±4,856' ±4,862' UB 2 ±6,630' ±6,647' 17' ±4,907' ±4,924' UB 2 ±6,664' ±6,693' 29' ±4,938' ±4,967' UB 3A ±6,736' ±6,753' 17' ±5,003' ±5,020' UB 6 ±6,985' ±6,995' 10' ±5,232' ±5,242' MB 4 ±7,457' ±7,468' 11' ±5,687' ±5,698' MB 6 ±7,683' ±7,711' 28' ±5,911' ±5,939' MB 7 ±7,803' ±7,819' 16' ±6,028' ±6,044' a. Proposed perfs. also 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 Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. jet fluid out (N2). 1st Perfs upper/Middle Beluga Well Prognosis Well: KU 24-32 Date: 6-1-2020 e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. f. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. 12. POOH. 13. RD e-line. 14. Turn well over to production to test for no more than 14 days per zone. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) E-line Procedure (Contingency) a) If any zone produces sand and/or water or needs isolation b) MIRU E-line, PT lubricator to 3,500 psi Hi 250 Low. c) RIH and set 5-1/2” CIBP at depth above zone. Or d) RIH and set 5-1/2” Casing Patch across the zone. e) Jet dry with nitrogen if needed. Once production is established from well testing and the well is deemed commercial: 15. MIRU E-line unit. Pressure test lubricator to 3,500 psi Hi 250 Low. 16. PU Packer and tail pipe assembly with a plug installed and lubricate into well. RIH with same and log on depth at +/-6,300’. Set packer. POOH W/ E-line. 17. Perform a negative test on the plug by bleeding off pressure above the packer to ensure plug is set. 18. Fill well with captured 6% KCl from blow down, or produced water (8.4 PPG). Pressure test packer to 2,500 psi on chart for 30 min. HAK 401 19. MIRU HAK Rig 401. 20. NU 7-1/16” BOPE. Test to 250 psi Low/ 3,500 psi High, annular to 250 psi Low/ 1,500 psi High (hold each valve and test for 10-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Test VBR rams on test joint of the smallest diameter pipe used in the well. 21. PU Packer Latch assembly on production tubing string. Note: Drift all tubing and tools as they are picked up to be ran into well. 22. RIH W/ Production tubing to just above the Production packer. Circulate packer fluid down the back side to the packer at +/-6,300. 23. Space out and latch into Production Packer. 24. Hang off tubing. 25. Pressure test IA to 2,000 psi for 30 minutes. Chart test. 26. ND BOP, NU wellhead and test. 27. RDMO Workover Rig. MIT packer MIT-IA 2000 psi 14 days per zone. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a ygp y sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. Temporary flowtest 14 days run packer/plug with eline. Well Prognosis Well: KU 24-32 Date: 6-1-2020 SlickLine Work 28. MIRU Slickline, Pressure test lubricator to 3,500 psi Hi 250 Low. 29. RIH and Swab well dry. 30. RIH and pull plug from tail pipe. 31. Turn well over to production. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Coil Tubing Unit (contingency) 32. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low (Notify AOGCC 24 hrs. in advance of BOP test). 33. RIH and blow tubing dry with Nitrogen. Remove plug from tailpipe. 34. Turn well over to production to bleed down and place on production. Attachments: 1. Actual and Proposed Well Schematics 2. Coil BOPE Schematic 3. CT Flow Diagrams (Forward and Reverse Jetting) 4. Wellhead Diagram 5. Workover Rig BOP Schematic 6. Rig 401 Flow Diagram. 7. Blank RWO Change Form 8. Standard Well Procedure – N2 Operations Updated by DMA 05-14-20 SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = ~8,120’ MD / TVD = ~7,027’ TD = 8,155’ MD / TVD = 7,057’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf ~1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf ~8,120’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ~1,400’ 4.892” 6.875” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 140 BBL’s of cement in 9-7/8” hole – Returns to surface (50% excess) 5-1/2” 131 BBL’s of cement in 6-3/4” hole. Est. TOC @ ~1,250’ (5% excess) 6-3/4” hole Leaking swell packer/IA 5 1/2"casing Updated by DMA 05-29-20 PROPOSED SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = ~8,120’ MD / TVD = ~7,027’ TD = 8,155’ MD / TVD = 7,057’ RKB to GL = 18’ 3 2 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf ~1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf ~8,120’ TUBING DETAIL 2-7/8” Production 6.4 L-80 8 RD EUE 2.441” Surf ±6,310’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ~1,400’ 4.892” 6.875” Swell Packer 2 ±6,300’ 2.33” 3.79” 5-1/2” Packer w/snap latch assembly 3 ±6,310’ 2.313” X-Nipple OPEN HOLE / CEMENT DETAIL 7-5/8" 140 BBL’s of cement in 9-7/8” hole – Returns to surface (50% excess) 5-1/2” 131 BBL’s of cement in 6-3/4” hole. Est. TOC @ ~1,250’ (5% excess) - Sundry 320-205 6-3/4” hole PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status UB 1X ±6,555' ±6,561' ±4,841' ±4,847' 6' Proposed Sundry 320-205 ±6,571' ±6,577' ±4,856' ±4,862' 6' Proposed Sundry 320-205 UB 2 ±6,630' ±6,647' ±4,907' ±4,924' 17' Proposed Sundry 320-205 ±6,664' ±6,693' ±4,938' ±4,967' 29' Proposed Sundry 320-205 UB 3A ±6,736' ±6,753' ±5,003' ±5,020' 17' Proposed Sundry 320-205 UB 6 ±6,985' ±6,995' ±5,232' ±5,242' 10' Proposed Sundry 320-205 MB 4 ±7,457' ±7,468' ±5,687' ±5,698' 11' Proposed Sundry 320-205 MB 6 ±7,683' ±7,711' ±5,911' ±5,939' 28' Proposed Sundry 320-205 MB 7 ±7,803' ±7,819' ±6,028' ±6,044' 16' Proposed Sundry 320-205 UB 1X UB 2 UB 3A UB 6 MB 4 MB 6 MB 7 X Test IA to 2000 psi Kenai Gas Field 05/27/2020 Valve, Master, CIW-FLS, 3 1/8 5M FE, HWO, EE trim Valve, Upper master, CIW-FLS, 3 1/8 5M FE, HWO, EE trim Valve, Swab, CIW-FLS 3 1/8 5M FE, HWO, EE trim Valve, Wing, CIW-FC, 3 1/8 5M FE, HWO, EE trim BHTA, Otis, 3 1/8 5M FE x 6.5 Otis quick union top Valve, Wing, SSV, WKM-M, 3 1/8 5M FE, w/ 15'’ air operator Tubing head, Cactus C-HPS, 11 5M x 7 1/16 5M, w/ 2- 2 1/16 5M SSO 16'’ 7 5/8'’ 5 ½’’ Starting head, Cactus C-29L, 13 5/8 5M x 16 SOW, w/ 2- 2 1/16 5M SSO Tubing head, Cactus C-29L- HPS, 13 5/8 5M x 11 5M, w/ 2- 2 1/16 5M SSO Kenai Gas Field KU 24-32 16 x 7 5/8 x 5 ½ x 3 ½ Casing hanger, CW, 11 x 5 ½ DWC/C box btm x 6.125'’ LH stub acme box top, w/ 7 5/8 od neck, 5'’ type H BPV profile, DD-NL material 2 7/8'’ Tubing hanger, Cactus-EN-CL, 7 x 3 ½’’ EUE 8rd lift and susp, w/ 3 type H BPV profile, 1- ¼npt control line port Adapter, Cactus-EN, 7 1/16 5M Stdd x 3 1/8 5M prepped for 5 ½ extended neck hanger 3 ½’’ or SSV ϳͲϭͬϭϲΗϱD,zZ/>'<EEh>Z ϯϮΗd>>͕&>E'dK&>E' ϳͲϭͬϭϲΗϱD>t^>'dKW Z^^tͬsZ/>ZD^/EdKW Z^^tͬ>/EZD^/EKddKD ϮϲͲϯͬϰΗd>>͕&>E'dK&>E' ϳͲϭͬϭϲΗϱDZ/>>/E'^WKK> tͬϮͲϭͬϭϲΗϱDKhd>d^ ϭϴΗd>>͕&>E'dK&>E' ΕϳϳΗdKd>^d<,/',d EEh>Z^dz>KW^W^͗ Ͳϯ͘ϯϬŐĂůůŽŶŽƉĞŶĐŚĂŵďĞƌǀŽůƵŵĞ Ͳϯ͘ϴϲŐĂůůŽŶĐůŽƐĞĐŚĂŵďĞƌǀŽůƵŵĞ 'd^dz>KW^W^͗ Ͳϭ͘ϰϱŐĂůůŽŶƐƚŽĐůŽƐĞƉĞƌŐĂƚĞ Ͳϭ͘ϭϴŐĂůůŽŶƐƚŽŽƉĞŶƉĞƌŐĂƚĞ Ͳϱ͘ϰϱ͗ϭĐůŽƐŝŶŐƌĂƚŝŽ Ͳϭ͘ϵϯ͗ϭŽƉĞŶŝŶŐƌĂƚŝŽ ϳͲϭͬϭϲΗϱDKW ,/>KZW>^< 1 Guhl, Meredith D (CED) From:Schwartz, Guy L (CED) Sent:Tuesday, May 26, 2020 9:54 AM To:Mike Quick Cc:Donna Ambruz; Cody Dinger Subject:RE: Hilcorp KU 24-32 CBL PTD 220-037 Bond log does look pretty good. I can see the swell packer at 1400 ft. maybe a little patchy stuff below. How long has swell packer been in hole now? Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: Mike Quick <mquick@hilcorp.com> Sent: Tuesday, May 26, 2020 9:08 AM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: Hilcorp KU 24‐32 CBL PTD 220‐037 Guy – Attached is the cement bond log for Hilcorp’s KU 24‐32 well, PTD 220‐037, sundry 320‐205. Halliburton called TOC at 1766’. There is excellent cement bond from 8030’ to 6270’, ~40% bond from 6270’ to 5600’; and patchy cement from 5600’ to 1766’. We were not successful in getting a pressure test on the IA. I will call you to discuss. Thanks, Mike 1 Guhl, Meredith D (CED) From:Monty Myers <mmyers@hilcorp.com> Sent:Monday, May 18, 2020 9:28 AM To:Schwartz, Guy L (CED) Subject:RE: [EXTERNAL] RE: Hilcorp Rig 169 Casing and Cement Notification We are currently at 5665’ heading in the hole. Still pushing fluid away, but have partial returns on circulation. Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Monday, May 18, 2020 9:04 AM To: Monty Myers <mmyers@hilcorp.com> Subject: [EXTERNAL] RE: Hilcorp Rig 169 Casing and Cement Notification Thanks … I was out of cell range for a while this weekend. Is liner on bottom yet? Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: Monty Myers <mmyers@hilcorp.com> Sent: Friday, May 15, 2020 10:03 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: Fwd: Hilcorp Rig 169 Casing and Cement Notification FYI. We pumped a cement pill to try and cure losses Monty M Myers 907.538.1168 Begin forwarded message: From: "Rance Pederson ‐ (C)" <rpederson@hilcorp.com> Date: May 15, 2020 at 9:49:18 PM AKDT 2 To: "Jesse Richardson ‐ (C)" <jesrichardson@hilcorp.com>, Monty Myers <mmyers@hilcorp.com> Subject: FW: Hilcorp Rig 169 Casing and Cement Notification I went ahead and sent Jim a casing/cementing notice. Just in case! From: Rance Pederson ‐ (C) Sent: Friday, May 15, 2020 9:47 PM To: 'jim.regg@alaska.gov' <jim.regg@alaska.gov> Subject: Hilcorp Rig 169 Casing and Cement Notification Jim, rig 169 has called TD at 8155’ md, 6375’ tvd on well KU 24‐32 (PTD:220‐037). We have been fighting some serious fluid losses after reaching this depth, and after numerous failed attempts to heal wellbore with LCM products, set and squeezed a 35 bbl LCM cement plug early this morning, from 6500’ md up to 5710’ md. We are currently drilling that out now, and it appears to be holding up enough we can run our 5 ½” casing and cement same. I anticipate getting started running casing late tomorrow night 5‐16‐20, and cementing same mid‐day on 5‐17‐20. We are also due for bi‐weekly BOP test on 5‐18, will be sending notification for that in the near future. Rance Pederson Drilling Foreman Kenai Unit 907‐776‐6776 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: Initial Completion/CTCO/N2 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): 8,155'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 8,730psi Liner 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: Mike Quick Operations Manager Contact Email: Contact Phone: 777-8442 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 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: May 29, 2020 N/A ~8,120 Perforation Depth MD (ft): See Attached Schematic ~8,120 ~7,0275-1/2" 16" 7-5/8" 120' ~1,784 2,980psi 6,890psi 120' ~1,695 120' ~1,784 N/A TVD Burst N/A 10,600psi MDLength Size 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL392668, FEE AA093808 220-037 50-133-20688-00-00 Kenai Unit (KU) 24-32 Kenai Gas Field - Beluga/Upper Tyonek Gas Pool - Tyonek Gas Pool 1 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic mquick@hilcorp.com 7,057'~8,120 ~7,027 ~1,997psi N/A Swell Pkr; N/A ~1,400'MD / 1,361'TVD; N/A Perforation Depth TVD (ft): Tubing Size: Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.05.15 17:37:58 -08'00' Taylor Wellman By Samantha Carlisle at 8:20 am, May 18, 2020 320-205 10-407 Perforate f Initial Completion/CTCO/N2 Ctbg DSR-5/18/2020 * 4000 psi BOPE test (CT) x DLB 05/18/20gls 5/20/20 X Comm 5/20/2020 dts 5/20/2020 JLC 5/20/2020 Well Prognosis Well: KU 24-32 Date: 5-14-2020 Well Name: KU 24-32 API Number: 50-133-20688-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: May 29, 2020 Rig: Coil Unit/ E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-037 First Call Engineer: Michael Quick (907) 777-8442 (O) (907) 317-2969 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: 2011534C Maximum Expected BHP: ~ 2,600 psi @ 6,028’ TVD (Based on geotap side wall tool data) Max. Potential Surface Pressure: ~ 1,997 psi @ 6,028’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KU 24-32 is a grass roots development well targeting gas sands in the Upper Tyonek and Middle and Upper Beluga formations. This new well TD was reached on 5-11-2020. The purpose of this work/sundry is to evaluate cement, jet the well dry with CT, and perforate. Notes Regarding Wellbore Condition x Well will be filled with 6% KCL x Rig cleaned out well to PBTD prior to rigging down. x E-line will complete CBL prior to starting sundry work. Electronic copy of CBL to be sent to AOGCC when completed. Safety Concerns x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) x Ensure all crews are aware of stop work authority Pre-Sundry Work 1. MIRU E-line unit. RU Stripping head. PU CBL. TIH to PBTD. Run CBL log from PBTD up to top of cement or 1750’, whichever comes first. RDMO E-line unit. Coiled Tubing Procedure (Start of Sundry work) 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. 2. MU Jet nozzle. 3. RIH W/ nozzle. RU N2 pumping unit. 4. Drop ball and come online with N2 and jet well dry. a) Estimated volume of displaced 6% KCl is (+/-) 180 bbls. (Based on estimated PBTD of 8,060’). 5. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD. 6. Once well is dry, leave 1,600 psi. on the well for first perforation interval. 7. POOH w/ coil. LD BHA. 8. RDMO Coiled Tubing. MIT-IA to 2500 psi (7 5/8" x 5 1/2") Note: submit MIT and CBL data to AOGCC before perforating.1a. MIT -IA to 2500 psi (log CBL past swell packer) Well Prognosis Well: KU 24-32 Date: 5-14-2020 E-Line Procedure 9. MIRU e-line and pressure control equipment. PT lubricator to 3,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. a) If necessary, bleed pressure down as requested by the OE to establish a drawdown on the formation. 10. PU RIH W/perf guns. Perforate each interval with 2-7/8” or 3-1/8” Perf guns 6 to 12 JSPF 60 degree phasing. 11. Proposed Perforated Intervals: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom UB 1X ±6,555' ±6,561' 6' ±4,841' ±4,847' UB 1X ±6,571' ±6,577' 6' ±4,856' ±4,862' UB 2 ±6,630' ±6,647' 17' ±4,907' ±4,924' UB 2 ±6,664' ±6,693' 29' ±4,938' ±4,967' UB 3A ±6,736' ±6,753' 17' ±5,003' ±5,020' UB 6 ±6,985' ±6,995' 10' ±5,232' ±5,242' MB 4 ±7,457' ±7,468' 11' ±5,687' ±5,698' MB 6 ±7,683' ±7,711' 28' ±5,911' ±5,939' MB 7 ±7,803' ±7,819' 16' ±6,028' ±6,044' a. Proposed perfs. also 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 Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. f. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. 12. POOH. 13. RD e-line. 14. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil tubing BOPE 4. Standard Well Procedure – N2 Operations (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) UB 1X ±6,555' ±6,561' 6' ±4,841' ±4,847' UB 1X ±6,571' ±6,577' 6' ±4,856' ±4,862' UB 2 ±6,630' ±6,647' 17' ±4,907' ±4,924' UB 2 ±6,664' ±6,693' 29' ±4,938' ±4,967' UB 3A ±6,736' ±6,753' 17' ±5,003' ±5,020' UB 6 ±6,985' ±6,995' 10' ±5,232' ±5,242' MB 4 ±7,457' ±7,468' 11' ±5,687' ±5,698' MB 6 ±7,683' ±7,711' 28' ±5,911' ±5,939' MB 7 ±7,803' ±7,819' 16' ±6,028' ±6,044' Updated by DMA 05-14-20 SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = ~8,120’ MD / TVD = ~7,027’ TD = 8,155’ MD / TVD = 7,057’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf ~1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf ~8,120’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ~1,400’ 4.892” 6.875” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 140 BBL’s of cement in 9-7/8” hole – Returns to surface (50% excess) 5-1/2” 131 BBL’s of cement in 6-3/4” hole. Est. TOC @ ~1,250’ (5% excess) 6-3/4” hole ft1784 MIT-IA to 2500 psi CBL required over 5 1/2" casing Updated by DMA 05-14-20 PROPOSED SCHEMATIC Kenai Gas Field KU 24-32 PTD: 220-037 API: 50-133-20688-00-00 PBTD = ~8,120’ MD / TVD = ~7,027’ TD = 8,155’ MD / TVD = 7,057’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf ~1,784’ 5-1/2" Prod Csg 17 L-80 CDC HTQ 4.892” Surf ~8,120’ 1 16” 7-5/8” 9-7/8” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ~1,400’ 4.892” 6.875” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 140 BBL’s of cement in 9-7/8” hole – Returns to surface (50% excess) 5-1/2” 131 BBL’s of cement in 6-3/4” hole. Est. TOC @ ~1,250’ (5% excess) 6-3/4” hole PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status UB 1X ±6,555' ±6,561' ±4,841' ±4,847' 6' Proposed TBD ±6,571' ±6,577' ±4,856' ±4,862' 6' Proposed TBD UB 2 ±6,630' ±6,647' ±4,907' ±4,924' 17' Proposed TBD ±6,664' ±6,693' ±4,938' ±4,967' 29' Proposed TBD UB 3A ±6,736' ±6,753' ±5,003' ±5,020' 17' Proposed TBD UB 6 ±6,985' ±6,995' ±5,232' ±5,242' 10' Proposed TBD MB 4 ±7,457' ±7,468' ±5,687' ±5,698' 11' Proposed TBD MB 6 ±7,683' ±7,711' ±5,911' ±5,939' 28' Proposed TBD MB 7 ±7,803' ±7,819' ±6,028' ±6,044' 16' Proposed TBD UB 1X UB 2 UB 3A UB 6 MB 4 MB 6 MB 7 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool and Tyonek Gas Pool 1, KU 24-32 Hilcorp Alaska, LLC Permit to Drill Number: 220-037 Surface Location: 898’ FSL, 1835’ FEL, SEC. 31, T5N, R11W, SM, AK Bottomhole Location: 1229’ FSL, 2454’ FEL, SEC. 32, T5N, R11W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the 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 AOGCC 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 AOGCC 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 an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of April, 2020. 17 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth:12. Field/Pool(s): MD: 9,373'TVD: 7,566' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number:13. Approximate Spud Date: Total Depth:9. Acres in Property:14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 77.3 15. Distance to Nearest Well Open Surface: x- 270794 y- 2368250 Zone-4 59.3 to Same Pool:4388' to KBU 31-06X 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 49.5 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 DWC/C 1,750' Surface Surface 1,750' 1,586' 6-3/4" 5-1/2" 17# L-80 CDC HTQ 9,373' Surface Surface 9,373' 7,566' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number:Permit Approval Number:50- Date: 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: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng 4/28/2020 8383' to nearest unit boundary Monty Myers Drilling Manager Monty Myers mmyers@hilcorp.com 777-8431 KU 24-32 Kenai Gas Field Beluga/ Upper Tyonek Gas Pool Tyonek Gas Pool 1 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 898' FSL, 1835' FEL, Sec 31, T5N, R11W, SM, AK ADL392668, FEE AA093808 Authorized Name: 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 735 ft3 1740 1225' FSL, 2483' FEL, Sec 32, T5N, R11W, SM, AK 1229' FSL, 2454' FEL, Sec 32, T5N, R11W, SM, AK N/A 2120 18. Casing Program:Top - Setting Depth - BottomSpecifications 2496 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 587 ft3 / T - 182 ft3 Effect. Depth TVD (ft): Conductor/Structural LengthCasing Intermediate Effect. Depth MD (ft): Authorized Signature: Production Liner Commission Use Only See cover letter for other requirements. Perforation Depth MD (ft): Authorized Title: 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 4/13/2020 es N ype of W L l R L 1b S Class: os N es No s N o D s s s D 84 o : well is p G S S 20 S S S es No s No S G E S es No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.04.13 14:20:10 -08'00' Monty M Myers By Samantha Carlisle at 2:46 pm, Apr 13, 2020 50-133-20688-00-00 2537 220-037 SFD 4/16/2020 1911 Development - Gas DSR-4/13/2020 * Sundry approval required to perforate well * 3500 Psi BOP Test *CBL required on 5.5" liner /MIT-IA to 2500 psi MASP from L-Beluga * Diverter waived per 20 AAC 25.0359(h)(2) gls 4/16/20 4/17/2020 KU 24-32 Drilling Program Kenai Gas Field Rev 0 April 9th, 2020 KU 24-32 Drilling Procedure Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 10 10.0 N/U 16” Conductor Riser ........................................................................................................ 11 11.0 Drill 9-7/8” Hole Section .......................................................................................................... 13 12.0 Run 7-5/8” Surface Casing ...................................................................................................... 16 13.0 Cement 7-5/8” Surface Casing ................................................................................................. 19 14.0 BOP N/U and Test.................................................................................................................... 22 15.0 Drill 6-3/4” Hole Section .......................................................................................................... 23 16.0 Run 5-1/2” Production Casing ................................................................................................. 27 17.0 Cement 5-1/2” Production Casing ........................................................................................... 30 18.0 RDMO ...................................................................................................................................... 32 19.0 BOP Schematic ........................................................................................................................ 33 20.0 Wellhead Schematic ................................................................................................................. 34 21.0 Days Vs Depth .......................................................................................................................... 35 22.0 Geo-Prog .................................................................................................................................. 36 23.0 Anticipated Drilling Hazards .................................................................................................. 37 24.0 Hilcorp Rig 169 Layout ........................................................................................................... 39 25.0 FIT Procedure .......................................................................................................................... 40 26.0 Choke Manifold Schematic ...................................................................................................... 41 27.0 Casing Design Information ...................................................................................................... 42 28.0 6-3/4” Hole Section MASP ....................................................................................................... 43 29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 44 30.0 Surface Plat (NAD 27) ............................................................................................................. 45 31.0 Directional Plan (wp04) ........................................................................................................... 46 Page 2 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 1.0 Well Summary Well KU 24-32 Pad & Old Well Designation KU 24-32 is a grass roots well on KGF Pad 34-31 Planned Completion Type 5-1/2” Production Longstring (monobore) Target Reservoir(s) Beluga/Tyonek Planned Well TD, MD / TVD 9,373 MD / 7,566’ TVD PBTD, MD / TVD 9,200’ MD / 7,395’ TVD Surface Location (Governmental) 898’ FSL, 1835’ FEL, Sec 31, T5N, R11W, SM, AK Surface Location (NAD 27) X=270794.50 Y=2368250.38 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 1225’ FSL, 2483’ FEL, Sec 32, T5N, R11W, SM, AK TPH Location (NAD 27) X=275437.97, Y=2368491.65 TPH Location (NAD 83) BHL (Governmental) 1229’ FSL, 2454’ FEL, Sec 32, T5N, R11W, SM, AK BHL (NAD 27) X=275466.60, Y=2368495.10 BHL (NAD 83) AFE Number 2011534 (D, C, F) AFE Drilling Days 3 MOB, 21 DRLG AFE Completion Days AFE Drilling Amount $2,560,935 AFE Completion Amount $1,226,984 Maximum Anticipated Pressure (Surface) 1740 psi Maximum Anticipated Pressure (Downhole/Reservoir) 2496 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 77.3’(59.3 + 18) Ground Elevation 59.3’ BOP Equipment 11” 5M Control Tech Type 90 Annular BOP 11” 5M Control Tech Type 82 Double Ram 11” 5M Control Tech Type 82 Single Ram Page 3 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 2.0 Management of Change Information Page 4 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16” 15.01” 14.822 17” 84 J-55 Weld 2980 1410 - 9-7/8” 7-5/8” 6.875” 6.75” 8.5” 29.7 L-80 BTC 6890 4790 683 6-3/4” 5-1/2” 4.892” 4.767” 6.05” 17 P110HC USS-CDC 10600 8730 568 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 x Notify Drlg Manager 1. Paul Mazzolini: O: 907-777-8369 C: 907-317-1275 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to mmyers@hilcorp.com and cdinger@hilcorp.com Page 6 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic MIT -IA to 2500 psi CBL required Page 7 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 7.0 Drilling / Completion Summary KU 24-32 is an S-shaped directional grassroots development well to be drilled off of the KGF 43-31 pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Upper Tyonek sands, as well as an area with little to no production in the Middle and Upper Beluga sands. The base plan is a directional wellbore with a kick off point at 300’ MD. Maximum hole angle will be 50 deg. and TD of the well will be 9,373’ TMD/ 7566’ TVD, ending with 10 deg inclination left in the hole. Vertical section will be 4679 ft. Drilling operations are expected to commence approximately April 28th 2020. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 1,750 MD / 1,586’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 – 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to well site 2. N/U conductor riser. (No diverter, diverter waiver requested) 3. Drill 9-7/8” hole to 1,750’ MD. Run and cmt 7-5/8” surface casing. 4. ND conductor riser, N/U & test 11” x 5M Townsend BOP. 5. Drill 6-3/4” hole section to 9,373’ MD. Perform Wiper trip. 6. Make cleanout run 7. POOH laying down drill pipe. 8. Run and cmt 5-1/2” production casing. 9. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res 2. Production Hole: GR + Res 3. Mud loggers from surface casing point to TD. Page 8 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of KU 24-32. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 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. x 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 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Regulation Variance Requests: x Diverter waiver request requested due to the recent drilling of KU 11-07X and KBU 43-07Y on a nearby pad. No issues were experienced on either well drilling the surface hole. Surface casing will be set at the same depth on KU 24-32. No shallow hydrocarbon zones will be penetrated. Diverter waiver request requested due to the recent drilling of KU 11-07X and KBU 43-07Y on aqq g nearby pad. No issues were experienced on either well drilling the surface hole. Surface casing will yp p g be set at the same depth on KU 24-32. No shallow hydrocarbon zones will be penetrated. x D Recommend approving request for diverter waiver: no shallow gas hazards reported in records from the eight wells previously drilled from this pad. SFD 4/16/2020 Page 9 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8” x No diverter utilized n/a 6-3/4” x 11” x 5M Townsend Annular BOP x 11” x 5M Townsend Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Townsend Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@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) Page 10 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers on surface hole section for gas detection only. No samples required 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 9-7/8” hole section. 9.10 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 10.0 N/U 16” Conductor Riser 10.1 N/U 16” Conductor Riser x Ensure line does not direct flow from trip tank straight down the flowline. Fill up line and flowline should be oriented 90 degrees to each other at approx. the same height. x Ensure flowline outlet installed so that enough slope exists to carry cuttings to the shakers. x Consider adding additional drainage points at the bottom of the conductor riser if deemed necessary. x R/U fill up line to conductor riser. 10.2 Set wearbushing in wellhead. (Diverter waiver requested by Hilcorp) Page 12 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 10.3 Rig Orientation on KGF 34-31 pad: Page 13 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 Primary Bit: Page 14 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 11.3 4-1/2” Workstring & HWDP will come from Hilcorp. Jars will come from Weatherford. 11.4 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.5 Drill 9-7/8” hole section to 1,750’ MD/ 1,586’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale between 1700’ MD and 1800’ MD. x Take MWD surveys every stand drilled (60’ intervals). 11.6 9-7/8” 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. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason 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: 8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-1750’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 8.8 – 9.5 Page 15 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.7 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.8 TOH with the drilling assy, handle BHA as appropriate. Page 16 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 7-5/8” casing running equipment. x Ensure 7-5/8” BTC x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. x 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. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 7-5/8” DWC/C M/U Torque Casing OD Min Torque Max Torque 7-5/8” 21,700 ft-lbs 25,100 ft-lbs ggqp Ensure 7-5/8” BTC x CDS 40 XO on rig floor and M/U to FOSV. Page 17 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 Page 18 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 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. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 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. 12.11 After circulating, lower string and land hanger in wellhead again. Page 19 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 13.0 Cement 7-5/8” Surface Casing 13.1 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. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 30 bbls of 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12.0 ppg LEAD: 16” Conductor x 7-5/8” casing annulus: 120’ x .0932 bpf = 11.2 63 12.0 ppg LEAD: 9-7/8” OH x 7-5/8” Casing annulus: (1750’ – 120’) x .0382 bpf x 1.5 = 94 524 Total LEAD: 105.2 587 ft3 15.4 ppg TAIL: 9-7/8” OH x 7-5/8” Casing annulus: (1750’-1250’) x .0382 bpf x 1.5 = 28.7 161 15.4 ppg TAIL: 7-5/8” Shoe track: 80 x .04591 bpf = 3.7 21 Total TAIL: 34.2 bbl 182 ft3 149 sx 238 sx 50% open hole excess. Page 20 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 Cement Slurry Design: 13.8 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. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: 1750’- 80’ = 1670’ x .04591 bpf = 77 bbls 13.12 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. Lead Slurry (1000’ MD to surface) Tail Slurry (1250’ to 1750’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 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 Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC p 1750’- 80’ = 1670’ x .04591 bpf = 77 bbls Page 21 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 3.7 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.14 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. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 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. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 22 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 14.0 BOP N/U and Test 14.1 N/U multi-bowl wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi. 14.2 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M Type 90 annular BOP/11” x 5M Model 82 double ram /11” x 5M mud cross/11” x 5M Type 82 single ram x Double ram should be dressed with 4-1/2” solid body rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 4-1/2” solid body rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.3 Run 4-1/2” BOP test assy, land out test plug (if not installed previously). x Test BOP to 250/3500 psi for 5/10 min. Test annular to 250/2500 psi for 5/10 min. x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.4 R/D BOP test assy. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 R/U mud loggers for production hole section. 14.8 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. BOPE TEST Type text here Page 23 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray and Resistivity LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. Page 24 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 15.8 Primary Bit: Page 25 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 15.9 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason 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: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 1,750’- 9,373’ 9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.10 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7-5/8” burst is 6890 psi / 2 = 3445 psi. 15.12 Drill out shoe track and 20’ of new formation. 15.13 CBU and condition mud for FIT. 9.0 – 10.0 – g 2500 psi gls R/U and test casing to 3500 psi / 30 min. 2500 psi Page 26 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 15.14 Conduct FIT to 13.5 ppg EMW. Note: Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 11 - 13 ppg EMW. A 13.5 ppg FIT results in a 4 ppg kick margin while drilling with the planned MW of 9.5 ppg. Kick tolerance = (13.5-9.5)X(1586/7566) = 0.83 15.15 Drill 6-3/4” hole section to 9,373’ MD / 7,566’ TVD ·Pump sweeps and maintain mud rheology to ensure effective hole cleaning. ·Pump at 225 - 300 gpm. Ensure shaker screens are set up to handle this flowrate. ·Keep swab and surge pressures low when tripping. ·Make wiper trips every 500’ 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 100’ drilled. Surveys can be taken more frequently if deemed necessary. ·Take (3) sets of formation samples every 20’. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.17 TOH with the drilling assy, standing back drill pipe. 15.18 LD BHA, RU E-line to perform RFT logging and sidewall coring. 15.19 RD loggers, PU 6-3/4”clean out BHA, and TIH to TD. 15.20 Pump sweep, CBU and condition mud for casing run. 15.21 POOH LDDP and BHA 15.22 Install 5-1/2” pipe rams in BOP stack and test. Page 27 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 16.0 Run 5-1/2” Production Casing 16.1. R/U Weatherford 5-1/2” casing running equipment. x Ensure 5-1/2” CDC HTQ x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 5-1/2” production casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint across zones of interest, TBD after LWD. x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free floating. x Pick up swell packer and place in string at approximately 1400’. 16.5. Continue running 5-1/2” production casing 5-1/2” CDC HTQ M/U torques Casing OD Minimum Maximum Yield Torque 5-1/2” 8,500 ft-lbs 11,500 ft-lbs 13,900 ft-lbs glsVerify 5 1/2" rams are installed and tested. Page 28 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 Page 29 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 16.6. Run in hole w/ 5-1/2” casing to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 5-1/2” X 6-3/4” swell packer to be placed at approximately 1400’. Swell packer should have 10’ handling pups installed on both ends with bow spring centralizers on pups. 16.13. Swedge up and wash last 2 joints to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.14. Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.15. Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. PU 5-1/2” X 6-3/4” swell packer to be placed at approximately 1400’swell pkr 1400 ft Page 30 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 17.0 Cement 5-1/2” Production Casing 17.1.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. Ensure mud & water can be delivered to the cmt unit at acceptable rates. ·Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole ·How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. ·Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. ·Positions and expectations of personnel involved with the cmt operation. ·Document efficiency of all possible displacement pumps prior to cement job. 17.2.Attempt to reciprocate the casing during cmt operations until hole gets sticky 17.3.Pump 5 bbls of 12.5 ppg Mud Push spacer. 17.4.Test surface cmt lines to 4500 psi. 17.5.Pump remaining 30 bbls 12.5 ppg Mud Push spacer. 17.6.Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 5% OH excess. Section:Calculation:Vol (BBLS)Vol (ft3) 7-5/8” x 5-1/2” Csg Overlap:500’ x 0.01653 =8 46 6-3/4” OH x 5-1/2” Casing:(9373 – 1750) x 0.01487 x 1.05 =119 668 Shoe Track:80’ x 0.04591 =3.7 21 Total Volume :130.7 735 Page 31 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 17.7. Drop wiper plug and displace with 6% KCl. 17.8. If hole conditions allow – continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 17.11. Do not overdisplace by more than ½ shoe track. Shoe track volume is 1.5 bbls. 17.12. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.13. RD cementers and flush equipment. 17.14. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 32 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 18.0 RDMO 18.1. Install BPV in wellhead 18.2. N/D BOPE 18.3. N/U temp abandonment cap 18.4. RDMO Hilcorp Rig #169 + CBL required on 5 1/2" casing. MIT-IA to 2500 psi (7 5/8" x 5 1/2") + Sundry approval to perforate well required. (NU tree?) after WOC and swell packer expansion. Page 33 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 19.0 BOP Schematic Page 34 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 20.0 Wellhead Schematic SSV Page 35 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 21.0 Days Vs Depth Page 36 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 22.0 Geo-Prog Well Name:KGF 24-32 Survey Type KB Field Name:Kenai Gas Field Surface Hole:77.3 Pool Name:Upper Tyonek Beluga Gas Bottom Hole:HAK 169 State:Alaska 18 Field Location:Onshore Coord Ref Sys:59.3 County/Parish:Kenai Peninsula Borough Objective: Reference Plan: P3_A8 Sand/Coal Gas/Water 4,839 3,607.0 -3589 2,368,375.98 273,677.01 1000 0.28 P6_C1 Sand/Coal Gas/Water 6,101 4,469.0 -4451 2,368,397.93 274,595.27 250 0.06 P6_C2 Sand/Coal Gas/Water 6,288 4,620.0 -4602 2,368,405.86 274,704.82 250 0.05 U_BELUGA Sand/Coal Gas/Water 6,411 4,723.0 -4705 2,368,411.95 274,771.70 1500 0.32 M_BELUGA Sand/Coal Gas/Water 7,134 5,379.0 -5361 2,368,445.29 275,070.35 2000 0.37 L_BELUGA Sand/Coal Gas/Water 7,937 6,164.0 -6146 2,368,463.51 275,231.97 2500 0.41 TYONEK Sand/Coal Gas/Water 9,106 7,315.0 -7297 2,368,486.26 275,433.64 2500 0.34 TD Sand/Coal Gas/Water 9,373 7,566.0 -7489 2,368,490.08 275,467.12 2500 0.33 = Reservoir Objectives = Possible Geo Hazards TARGET RADIUS Mud Logging: LWD Data: Other Log Data: Coreing: Frac Half-Length SH Max Direction Surf. Inter. Prod. NOTES: DATA COLLECTION REQUIREMENTS: 90% & 3 MMCFGPD PROSED PIPE SET DEPTHS Chance of Success & Anticipated Rate ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE Drill and complete a grassroots well in northern Kenai Gas Field. COMPLETION TYPE Monobore Fault Constraints 250 FT Surface casing to total depth, 30 ft samples with 20' samples in zones of interest, two sets of dry cut cuttings, chromatograph, show reports, pixler plots. KGF 24-32 WP 02ANTICIPATED FORMATION TOPS & GEOHAZARDS Geo Summary/ Justification: Targeting Lower Beluga first. Setup completion inorder to access shallower Sterling sands as well. Will be drilling through Pool 6, which will require cement isolation. Planned TD is 9300'. TOP NAME LITHOLOGY EXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)NORTHING EASTING Est. Pressure Gradient Ground Elevation: GEOLOGICAL PROGNOSIS As-Built x = 270,794.50 y = 2,368,250.38 TVD Ref Datum: TVD Ref Elevation: Planned Rig: Rig Height: x = 275,466.60 9,373' MD 7,566' TVD y = 2,368,495.10 NAD27 Zone 4 Page 37 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 23.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. 0-1750 ft md Page 38 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. 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. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. 1750- 9273 ft md NOTE:no collision issues noted . gls Page 39 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 24.0 Hilcorp Rig 169 Layout Page 40 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 25.0 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. drill pipe pressure until appropriate surface pressure is achieved for FIT 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 41 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 26.0 Choke Manifold Schematic Page 42 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 27.0 Casing Design Information 9-7/8"Mud Density:8.8 ppg 6-3/4"Mud Density:10 ppg Mud Density: 1740 psi (see attached M ASP determination & calculation) 1740 psi (see attached M ASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.45 psi/ft) and the casing evacuated for the internal stress 1234 7-5/8" 5-1/2" 00 00 1,750 9,373 1,586 7,566 1,750 9,373 29.7 17 L-80 L-80 DWC CDC HTQ 51,975 159,341 51,975 159,341 683 428 13.14 2.69 690 3,291 4,790 6,290 6.94 1.91 475 1,740 6,890 7,740 14.51 4.45Worst case safety factor (Burst) DATE: 04/10/2020 WELL: KU 24-32 FIELD: Kenai Gas Field DESIGN BY: Monty M Myers Hole Size Hole Size Hole Size MASP: Production Mode Casing Section MASP: Drilling Mode MASP: Length Top (TVD) Minimum Yield (psi) Weight (ppf) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Collapse Resistance w/o tension (Psi) Worst Case Safety Factor (Collapse) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Calculation & Casing Design Factors Kenai Gas Field Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) Tension at Top of Section (lbs) Design Criteria: 13.14 2.69 6.94 1.91 14.51 4.45 Page 43 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 28.0 6-3/4” Hole Section MASP MD TVD Planned Top: 0 0 Planned TD: 9373 7566 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad P3_A8 3607 1000 Gas/Water 5.3 0.28 P6_C1 4469 250 Gas/Water 1.1 0.06 P6_C2 4620 250 Gas/Water 1.0 0.05 U_BELUGA 4723 1500 Gas/Water 6.1 0.32 M_BELUGA 5379 2000 Gas/Water 7.2 0.37 L_BELUGA 6164 2500 Gas/Water 7.8 0.41 TYONEK 7315 2500 Gas/Water 6.6 0.34 TD 7566 2500 Gas/Water 6.4 0.33 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date KBU 11-17X 9 - 9.2 1,587 5,464 2009 KBU 14-08 9 - 9.2 1,510 5,432 2008 KBU 41-18X 9 - 9.2 1,500 5,391 2008 KBU 24-7X 9 - 9.7 1,502 5,326 2006 KBU 32-08 9.3 - 9.8 1,446 5,401 2014 KBU 43-07Y 9.5 - 9.7 1,540 5,738 2014 Assumptions: 1. Fracture gradient at shoe (1586' TVD) is estimated at 17 ppg based on field test data. 2. Maximum planned mud density for the 6-3/4" hole section is 10.0 ppg. 3. Calculations assume "Unknown" reservoir contains 100% gas (worst case). 4. Calculations assume worst case event is 100% evacuation of wellbore to gas. Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface: TVD Frac Grad 1586 ft X 0.884 psi/ft 1402 psi 1402(psi) - [0.1(psi/ft)*1586(ft)]= 1243 psi MASP from pore pressure during production mode (Complete evacuation to gas) 7566 ft X 0.330 psi/ft 2497 psi Downhol e 2497(psi) - [0.1(psi/ft)* 7566 (ft)]= 1740 psi Surface Summary: 1. MASP while drilling 6-3/4" production hole is governed by frac pressure at 7-5/8" shoe with entire wellbore evacuated to gas KU 24-32 Kenai Gas Field 6-3/4" Hole Section Maximum Anticipated Surface Pressure Calculation 2527 - 6164(.1) = 1911 psi MASP using L_Beluga sand L_BELUGA 6164 2500 Gas/Water 7.8 0.41 Page 44 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 45 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 30.0 Surface Plat (NAD 27) X Page 46 Version 0 April, 2020 KU 24-32 Drilling Procedure Rev 0 31.0 Directional Plan (wp04) !" !" -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 85.90° (1500 usft/in) KU 24-32 wp03 TD Gringotts tgt1 16" 7 5/8" X 8 1/2" 5 1/2" x 6 1/8" 5 0 0 1 0 0 0 15002000250030003500400045005000550060006 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 3 7 3 KU 24-32 wp04 Start Dir 3º/100' : 300' MD, 300'TVD : 40° RT TF Start Dir 4º/100' : 650' MD, 648.04'TVD : 56.32° RT TF End Dir : 1727.27' MD, 1571.17'TVD0° RT TF Start Dir 2º/100' : 5503.76' MD, 4022.14'TVD : 170.69° LT TF 180° LT TF End Dir : 7520.73' MD, 5739.83'TVD0° RT TF Total Depth : 9373.07' MD, 7566.3' TVD° RT TF P3_A8 P6_C1 P6_C2 U_BELUGA M_BELUGA L_BELUGA TYONEK TD Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio WELL DETAILS: Plan: KU 24-32 59.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2368250.38 270794.50 60° 28' 34.903 N 151° 16' 13.599 W SURVEY PROGRAM Date: 2020-04-09T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1750.00 KU 24-32 wp04 (KU 24-32) 3_MWD+IFR1+MS+Sag 1750.00 9373.07 KU 24-32 wp04 (KU 24-32) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3666.30 3589.00 4955.48 P3_A8 4528.30 4451.00 6194.48 P6_C1 4679.30 4602.00 6377.02 P6_C2 4782.30 4705.00 6497.47 U_BELUGA 5438.30 5361.00 7211.51 M_BELUGA 6223.30 6146.00 8011.04 L_BELUGA 7374.30 7297.00 9178.35 TYONEK 7566.30 7489.00 9373.07 TD REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: KU 24-32, True North Vertical (TVD) Reference:As-Built RKB @ 77.30usft Measured Depth Reference: As-Built RKB @ 77.30usft Calculation Method:Minimum Curvature Project:Kenai Gas Field Site:KGF 34-31 Pad Well:Plan: KU 24-32 Wellbore:KU 24-32 Design:KU 24-32 wp04 Kenai Gas Field KGF 34-31 Pad Plan: KU 24-32 KU 24-32 KU 24-32 wp04 5.858 CASING DETAILS TVD TVDSS MD Size Name 98.00 20.70 98.00 16 16" 1585.92 1508.62 1750.00 7-5/8 7 5/8" X 8 1/2" 7566.30 7489.00 9373.07 5-1/2 5 1/2" x 6 1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD : 40° RT TF 3 650.00 10.50 40.00 648.04 24.50 20.56 3.00 40.00 22.26 Start Dir 4º/100' : 650' MD, 648.04'TVD : 56.32° RT TF 4 1727.27 49.53 88.35 1571.17 115.81 516.89 4.00 56.32 523.85 End Dir : 1727.27' MD, 1571.17'TVD0° RT TF 5 5503.76 49.53 88.35 4022.14 198.32 3388.78 0.00 0.00 3394.29 Start Dir 2º/100' : 5503.76' MD, 4022.14'TVD : 170.69° LT TF 6 6500.12 30.00 82.02 4784.60 244.25 4020.70 2.00 -170.69 4027.87 Gringotts tgt1 180° LT TF 7 7520.73 9.59 82.02 5739.83 291.98 4361.16 2.00 -180.00 4370.87 End Dir : 7520.73' MD, 5739.83'TVD0° RT TF 8 9373.07 9.59 82.02 7566.30 334.83 4666.70 0.00 0.00 4678.69 KU 24-32 wp03 TD Total Depth : 9373.07' MD, 7566.3' TVD° RT TF -1467-1100-733-3670367733110014671833South(-)/North(+) (550 usft/in)0 367 733 1100 1467 1833 2200 2567 2933 3300 3667 40334400 4767 5133West(-)/East(+) (550 usft/in)Gringotts tgt1KU 24-32 wp03 TD16"7 5/8" X 8 1/2"5 1/2" x 6 1/8"2505007501 0 0 0 1 2 5 0 1 5 0 0 1 75 0 2000 2250 2500 27 50 3000 32 50 3500 3750 4000 4250 4 5 0 0 4 7 5 0500052505500575060006250650067507000725075007566KU 24-32 wp04Start Dir 3º/100' : 300' MD, 300'TVD : 40° RT TFStart Dir 4º/100' : 650' MD, 648.04'TVD : 56.32° RT TFEnd Dir : 1727.27' MD, 1571.17'TVD0° RT TFStart Dir 2º/100' : 5503.76' MD, 4022.14'TVD : 170.69° LT TF180° LT TFEnd Dir : 7520.73' MD, 5739.83'TVD0° RT TFTotal Depth : 9373.07' MD, 7566.3' TVD° RT TFProject: Kenai Gas FieldSite: KGF 34-31 PadWell: Plan: KU 24-32Wellbore: KU 24-32Plan: KU 24-32 wp04WELL DETAILS: Plan: KU 24-3259.30+N/-S +E/-W Northing Easting Latittude Longitude0.000.002368250.38 270794.50 60° 28' 34.903 N 151° 16' 13.599 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: KU 24-32, True NorthVertical (TVD) Reference:As-Built RKB @ 77.30usftMeasured Depth Reference:As-Built RKB @ 77.30usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name98.00 20.70 98.00 16 16"1585.92 1508.62 1750.00 7-5/8 7 5/8" X 8 1/2"7566.30 7489.00 9373.07 5-1/2 5 1/2" x 6 1/8" -2333-1867-1400-933-4670467933140018672333South(-)/North(+) (700 usft/in)-467 0 467 933 1400 1867 2333 2800 3267 3733 4200 4667 5133 5600 6067West(-)/East(+) (700 usft/in)5001000150020002500300035004000450050005500600065007000750080008500900095009677KDU-5500100015002000250030003500400045005000550060006 50 0 7 0 0 07 5 00 8 0 0 0 8 5 0 0 900095009836KDU-650010001500200025003000350040004267KU 11-65 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 30 0 0 3500 400045004925 KU 14-320500100015002000250030003500400045004904KU 21-60500100015002000250030003500400045004852KU 21-6 RD500100015002000250030003500400045004987KU 22-6X500100015002000250030003500400045004985KU 33-3250010001500200025003000350040004500500055005790KU 34-31500100015002000250030003330KU WD-15001 0 0 0 15 0 0 2000 2500 3000 3500 4000 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 07566 Azimuths to True NorthMagnetic North: 14.82°Magnetic FieldStrength: 55323.1nTDip Angle: 73.42°Date: 5/9/2020Model: BGGM2019TMProject: Kenai Gas FieldSite: KGF 34-31 PadWell: Plan: KU 24-32Wellbore: KU 24-32Plan: KU 24-32 wp04-133 0 133 267 400West(-)/East(+) (200 usft/in)-1330133South(-)/North(+) (200 usft/in)1000KDU-61 0 0 0KU 14-32KU 22-6X1 0 0 0KU 24-32 wp04 # $ % & '() & *+ , ,* +-% + ./ !"#"#$ # %#%&''()#* )0 +) )*,-./ , 0 .) & %#%&''()#* 1 / & 1 .# . %$ ! )+$ # . 2 %$)+$ 2 '345 #6 , 02 '3, 0-,-,6 7) ! $ 81* 88 * " $ + 0+ % 1 /0 30 ! -0 #* 98 #* #* :( +;9< <' ''(< ') <(') )()) <): => 2(=? , ?:<> ()1 , , 0+ + 30 1 /0 #* 435, 415 % #* #* #*! +- #* #* )()) )()) <= ?)(= ') '2(?) ?2(),/3- #*)(?) <): =>(2), ?:<>(?221 ,* ) 678 "0/ 6'8 $ ) ) 0 678 . 1$.0 %! )2 ?929 ) ) (= '( ?? ()<)2) ' /( +1 )0 +) , ( ) /" $6'()8 6+&8 415 6+&8 ) 678 435, 6+&8 '9) /=()) =?(2))()))())=()) : 678 ;$+/ 678 435, 6+&8 ' " 678 415 6+&8 .+ ) / 6+&8 ( ) / 6+&8 ) 00 675+&8 <+ 675+&8 '+ 675+&8 '() %$ +& )()))()))()))()))()))())=()))()))())=())?2() )()))()))()))()))()))())))()))()))())))()) (') )()))())())()) )(?< (?)<=())()))(?)<?)())?')(' ?<( (2(< ())?<(=2?(= ?'('==(?2(? ' '( ' 2(=' )()))()))()))()) ==('=2=( ) (==(?2(?? ?)('< 2(= ')(<2)(<(2< ()) ) )(') ( ? '=(<)= () )())< ?))( ')'() =)()))()) ()) ()) <(< 2(2=? '2(== () 2(?2' ? )('? << (? )()))()))()))()) <<<(')(=' ?<<()= () 2(?22 '()'' =2()) # $ % & '() & *+ , ,* +-% + ./ !"#"#$ # %#%&''()#* )0 +) )*,-./ , 0 .) & %#%&''()#* 1 / & 1 .# .+ ) / 6+&8 : 678 ;$+/ 678 435, 6+&8 . 1 /0 6+&8 . 30 6+&8 415 6+&8 +-% ( ) / 6+&8 '() +& ) =>? ( =()) )()) =()) )()) )()))()) ') '2(?) <= ?)(=?2())()) )()) 2=()) )()) 2=()) )()) )()))()) ') '2(?) <= ?)(= )('))()) )()) @A ))()) )()) ))()) )()) )()))()) ') '2(?) <= ?)(= ('))()) )()) ))()) )()) ))()) )()) )()))()) ') '2(?) <= ?)(= ('))()) )()) ))()) )()) ))()) )()) )()))()) ') '2(?) <= ?)(= ('))()) )()) )B5CC.)C'()7 ''" ))()) ()) 22(2? () (<=)()) ') '2<( <= ? (? (<?()) (= ?))()) <()) 22(< =() <(')()) ') =)(= <= ?=( < (()) '( = <))()) 2()) ?2=('' =() ?()()) ') =)2(2< <= <=()? ('()) <(< <?)()) )(?) <=() (?) )(?<)()) ') =?(? <= '(=?')('()) ( < )B5C@=C.)@D?C'()=@?7 ''" '))()) (' <2'( (' '( '=( ') = (' <= =( <2(=()) 2(? =))()) (<2 '2(' (= ?(=?<)()< ') =( ) <= 2(2'''('()) =(2 2))()) =()? =2)( ?<(<' '(2<'('2 ') =<<('' <= )?(<<=(()) '?()' )))()) (< 2=(' <'(=2 )(='( ') =2=(2' <= <( <2)'('()) )'('= ))()) ?( )'<(= '=()' (<''<(2< ') 2'(< <= ?(')22=(==()) <(=2 ))()) 2() <?() ='(= =<(<'2(=' ') 2= (<) <= (2 )='(=)()) 2 ( ))()) (2 ?)(=) 2?(< '(= (' ' )(< <= )(2 '(?)()) (? ))()) <('' (=< )(2= 2()=() ' )2)( <= <(<< ??(?<()) ))(?2 ?))()) )(<? )(=' )'(<) ?<( =?(?= ' ? (= <= ?()2 (?'()) <() <))()) (?? =(< () (=?=<(2 ' )( <= ?(= )'(<()) )('= '))()) =(< ??( ' ?(< 2<(==()< ' 2 (2 <= ??(2 '?(2'()) ?)( = ' '( ' 2(? ?'(' ?(= ?<(=2==(? ' (?) <= ?<(2 2(='()) ? (=? 3)EE?EC.)=E?EC'()7 ''" '?)()) 2(? ?=?(2 <() ?('==(? ' )('2 <= ?<(? ?)=(< )()) ?( E=5DAFD5A =))()) 2(? <=(' '() ?' (2==(? ' <=(= <= ?<(' ?()')()) ?'2( 2))()) 2(? <=( ' 2(?= <=( ==(? ' (2) <= ?'( <)?(2')()) <??( )))()) 2(? '=(' ('' ' ( 2==(? ' ? )(2' <= ?=( <')(=')()) '( ))()) 2(? =()' (2? =))(==(? ' ?2'() <= ?=(=< '?('')()) =)'(? ))()) 2(? =''(2' <( ='<(===(? ' <'( <= ?2(?= =))(<')()) ==(< ))()) 2(? 2 (=' =( 2? (==(? ' '2(2 <= <)() =<?(?')()) 2?2(' ))()) 2(? ))'('' )(?) ) =('==(? ' = ?( < <= <() 2)(')()) )?(= ?))()) 2(? )' (<' (<2 )(? ==(? ' 2)( <= <(' 22?(')()) (= <))()) 2(? '(?' (=' =)(?'==(? ' 2''() <= < (? )<)( ')()) ='(2 '))()) 2(? ) (' '()< ?<(<==(? ' )?(' <= <(< ?(')()) <( ) =))()) 2(? <'(= 2( (<<==(? ' 2(?? <= <(== 2)()=)()) 2( 2))()) 2(? ( = ( )=('==(? ' )?(< <= <(<) ?(2=)()) ?( )))()) 2(? 2'(= (< =('?==(? ' =(<2 <= <?( 2(==)()) 2( ))()) 2(? < ()= ?(=) ?<)(=)==(? ' ?'('< <= <<() =('=)()) ?<'( ))()) 2(? ? <(2= '(2= <<(=?==(? ' (= <= <<('? 2(<=)()) <( ))()) 2(? ?2(== ?)(' ' (=2==(? ' ?)2(2) <= <'(' ?(?=)()) '2( ? ))()) 2(? <?<('= ? (? '==(2==(? ' ?=?(2= <= <=(= ?'2(=)()) '2?( < ?))()) 2(? ' (<= ?(? =<(22==(? ' << ()? <= <=(2) <(=)()) ='( ' # $ % & '() & *+ , ,* +-% + ./ !"#"#$ # %#%&''()#* )0 +) )*,-./ , 0 .) & %#%&''()#* 1 / & 1 .# .+ ) / 6+&8 : 678 ;$+/ 678 435, 6+&8 . 1 /0 6+&8 . 30 6+&8 415 6+&8 +-% ( ) / 6+&8 '() +& ) E>?D ( <))()) 2(? '=<(?= ?<(' 2()==(? ' '=( <= <2(< ')2( =)()) 2'( ' '))()) 2(? =?(= ?=(2 )'()===(? ' =(2 <= ')( ''(=)()) ) ( = =))()) 2(? 2<(= <()2 )2(==(? ' =2)( < <= '()? =2()=)()) )22( 2 2))()) 2(? 2=( = <( = <2(===(? ' 2<<( <= '('' 2)(2=)()) '?() )))()) 2(? )<(= <?(< ?( ==(? ' ) ( <= ' (2 2<=(==)()) ?( ))()) 2(? ()2 <'(<? ( '==(? ' =(= <= '( ) )('2 )()) '( ))()) 2(? '?(22 <2(= 2'( ==(? ' 2(?? <= '(2 )2=(<2 )()) )( ))()) 2(? )(=2 ' () '(<==(? ' ')(< <= '(< <(?2 )()) '2( ))()) 2(? )?('2 '( ) ?2(==(? ' <(<2 <= '?(< =(2 )()) ???( ?))()) 2(? ')(<2 '<(2 < ?(<==(? ' ('' <= '<()' 2(2 )()) <(? <))()) 2(? ?(?2 '=(?' ')(?)==(? ' 2=(= <= '<('2 ?=( 2 )()) ')'(< '))()) 2(? ?))(2 =)('< '''(??==(? ' ?'(2 <= ''(? (2 )()) '=(< =))()) 2(? ?<?(2 = (2 =?(<)==(? ' <?)(2= <= '=( ==()2 )()) =?2(' 2))()) 2(? <)( 2 =?( 2 2(<==(? ' ' '()? <= '=(2 ?? (22 )()) 2?(= 2??(= 2(? <<<() =<( 2'(===(? ' '<2( < <= '2( ?=2()))()) 2''(?? GD ? )))()) 2(? <2?(2 ='( ))?(<2==(? ' =)( <= '2(<< <'(=2 )()) )(2 ? ))()) 2(? '<)()2 =2(?) )=('==(? ' ='2( ) <= =)(= <= ('2 )()) )='() ? ))()) 2(? = (22 2(<= ?'('===(? ' 2??( ' <= =()2 ''(<2 )()) <( ? ))()) 2(? ==2(=2 2(=' (===(? ' )( <= =(= = (?2 )()) 2( ? ))()) 2(? 2?(=) 2<()? )2(====(? ' )'( <= = (? =''(?))()) ?( ? ?))()) 2(? )2(') 2=( =?(2 ==(? ' =(= <= =( ? 2 ())()) 2( ? ?)('< 2(? ) ( 2=( ==('===(? ' =<( <= =( ' 2(=)()) 2( 2 )B5C==?E@C.)?C'()E?@>7''" ? <))()) '(< )=?(=) ))(<? <)(2 ='(2 ' ?=(?) <= =( ))=(?) ()) <<() ? '))()) ?(<< ?( )(?' ?(?'='(' ' ( ) <= =?(' )''( ()) ?2()= ? =))()) (<2 ?(? )<(2= <)(=)=<(2' ' )(' <= ='('= =( ()) <)2(' ? 2))()) (' 22() )(=' <'(?=<( ' <2( ? <= 2)(' (' ()) <''(2 < )))()) 2('< '('= ?( < '<(<=?(=? ' ?( <= 2(2 2'(= ()) ' (? < ))()) '(=) ? (' )( '22()'=?( ' ?2<(2< <= 2'(? '?( ()) =)?()2 < 2(= ?(2? ? =() ?(? =??(??=(?= ' <?(? <= )()2 ?()) ()) =<('' @G < ))()) ?(=? ? ('' ?(? =?=(''=(? ' <?<(' <= )( ??(' ()) =<?() < ))()) (=2 <(= ( < 2?(<=('2 ' '(' <= )<() ?'(? ()) 2 (? < ''() (2 <'2() <() 2?'('=(? ' '??(< <= )() <) ()) ()) 2<( @G < ))()) (2 <2=('< '(? 2<2(< = (2? ' '<'(=) <= ( < < (< ()) 2'<( < 2'(' )()? '= () ()< )2(== ()? ' ='(<= <= <(= ')?()) ()) ) <(? G<3! < ?))()) )()) '=(2 ( ) )(<= () ' ==(2 <= <(22 ')'(2 ()) ) '(= < ?))( )()) '=(<) ( ? ) )(')= () ' =2()) <= '()) ')'() ()) ) '(=' D7''"!0 0 < <))()) =()) ='(2? ?)(2' )<=(<?= () ' =<'()' <= (=) '2(<? ()) )'<(= < '))()) <()) 2<() ?'( ' (<= () ' 2 ( <= =( ==(' ()) (' < =))()) ()) ? )?(<' <( ??(<= () ' 2?() <= ( 2 2'(' ()) <(< # $ % & '() & *+ , ,* +-% + ./ !"#"#$ # %#%&''()#* )0 +) )*,-./ , 0 .) & %#%&''()#* 1 / & 1 .# .+ ) / 6+&8 : 678 ;$+/ 678 435, 6+&8 . 1 /0 6+&8 . 30 6+&8 415 6+&8 +-% ( ) / 6+&8 '() +& ) =@@? ( < 2))()) ()) ? (' <=(?' 2(<= () ' 22 (=2 <= '(2'? )<<( ()) ) (< ' )))()) )()) ? 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eparation Factor0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured DepthKU 14-32KDU-6No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: KU 24-32 NAD 1927 (NADCON CONUS)Alaska Zone 0459.30+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002368250.38 270794.5060° 28' 34.903 N151° 16' 13.599 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: KU 24-32, True NorthVertical (TVD) Reference:As-Built RKB @ 77.30usftMeasured Depth Reference:As-Built RKB @ 77.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-04-09T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 1750.00 KU 24-32 wp04 (KU 24-32) 3_MWD+IFR1+MS+Sag1750.00 9373.07 KU 24-32 wp04 (KU 24-32) 3_MWD+IFR1+MS+Sag0.0035.0070.00105.00140.00175.00Centre to Centre Separation (60.00 usft/in)0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured DepthKU 14-32KDU-6KU 22-6XGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 9373.07Project: Kenai Gas FieldSite: KGF 34-31 PadWell: Plan: KU 24-32Wellbore: KU 24-32Plan: KU 24-32 wp04Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name98.00 20.70 98.00 16 16"1585.92 1508.62 1750.00 7-5/8 7 5/8" X 8 1/2"7566.30 7489.00 9373.07 5-1/2 5 1/2" x 6 1/8" MD TVD Planned Top:0 0 Planned TD:9373 7566 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad P3_A8 3607 1000 Gas/Water 5.3 0.28 P6_C1 4469 250 Gas/Water 1.1 0.06 P6_C2 4620 250 Gas/Water 1.0 0.05 U_BELUGA 4723 1500 Gas/Water 6.1 0.32 M_BELUGA 5379 2000 Gas/Water 7.2 0.37 L_BELUGA 6164 2500 Gas/Water 7.8 0.41 TYONEK 7315 2500 Gas/Water 6.6 0.34 TD 7566 2500 Gas/Water 6.4 0.33 Offset Well Mud Densities Well MW range Top (TVD)Bottom (TVD)Date KBU 11-17X 9 - 9.2 1,587 5,464 2009 KBU 14-08 9 - 9.2 1,510 5,432 2008 KBU 41-18X 9 - 9.2 1,500 5,391 2008 KBU 24-7X 9 - 9.7 1,502 5,326 2006 KBU 32-08 9.3 - 9.8 1,446 5,401 2014 KBU 43-07Y 9.5 - 9.7 1,540 5,738 2014 Assumptions: 1. Fracture gradient at shoe (1586' TVD) is estimated at 17 ppg based on field test data. 2. Maximum planned mud density for the 6-3/4" hole section is 10.0 ppg. 3. Calculations assume "Unknown" reservoir contains 100% gas (worst case). 4. Calculations assume worst case event is 100% evacuation of wellbore to gas. Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface: TVD Frac Grad 1586 ft X 0.884 psi/ft 1402 psi 1402(psi) - [0.1(psi/ft)*1586(ft)]=1243 psi MASP from pore pressure during production mode (Complete evacuation to gas) 6164 ft X 0.410 psi/ft 2527 psi Downhole 2527(psi) - [0.1(psi/ft)* 6164 (ft)]=1911 psi Surface Summary: 1. MASP while drilling 6-3/4" production hole is governed by frac pressure at 7-5/8" shoe with entire wellbore evacuated to gas KU 24-32 Kenai Gas Field 6-3/4" Hole Section Maximum Anticipated Surface Pressure Calculation 9-7/8"Mud Density:8.8 ppg 6-3/4"Mud Density:10 ppg Mud Density: 1911 psi (see attached MASP determination & calculation) 1911 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.45 psi/ft) and the casing evacuated for the internal stress 1 2 3 4 7-5/8"5-1/2" 0 0 0 0 1,750 9,373 1,586 7,566 1,750 9,373 29.7 17 L-80 L-80 DWC CDC HTQ 51,975 159,341 51,975 159,341 683 428 13.14 2.69 690 3,291 4,790 6,290 6.94 1.91 475 1,911 6,890 7,740 14.51 4.05 Collapse Pressure at bottom (Psi) Calculation & Casing Design Factors Kenai Gas Field Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) Tension at Top of Section (lbs) Design Criteria: Minimum Yield (psi) Weight (ppf) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Collapse Resistance w/o tension (Psi) Worst Case Safety Factor (Collapse) MASP (psi) Worst Case Safety Factor (Tension) Casing Section MASP: Drilling Mode MASP: Length Top (TVD) Worst case safety factor (Burst) DATE: 04/10/2020 WELL: KU 24-32 FIELD: Kenai Gas Field DESIGN BY: Monty M Myers Hole Size Hole Size Hole Size MASP: Production Mode 1 Davies, Stephen F (CED) From:Davies, Stephen F (CED) Sent:Thursday, April 16, 2020 1:36 PM To:Schwartz, Guy L (CED) Subject:RE: KU 24-32 diverter waiver Guy, Yes, see my email, below. Thanks, Steve D. CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Thursday, April 16, 2020 1:26 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: FW: [EXTERNAL] KU 24‐32 (PTD 220‐037) Guy, I’m finished with this application. I placed a note on page 8 of the application recommending approval of Hilcorp’s diverter waiver request. I reviewed the daily operations summaries for all eight wells previously drilled from this pad and found that no shallow gas hazards were recorded. I also reviewed the mud logs recorded in two wells drilled on this pad and there was not any significant gas encountered while drilling the interval down to the planned surface casing shoe in KU 24‐32 at 1750’ MD. Sorry to take so long to finish. I had to load a lot of data into Geographix and read through the well history files. Thanks, Steve D. CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. Review Notes: KENAI DEEP UNIT 5 (1780550): No shallow drilling problems reported down to 3345' MD in daily operations summary (stopped reading the well records at that depth). KENAI DEEP UNIT 6 (1780560): No shallow drilling problems reported down to 3016' MD in daily operations summary (stopped reading the well records at that depth). KENAI UNIT 14‐32 (1820150): No shallow drilling problems reported down to 3355' MD in daily operations summary (stopped reading the well records at that depth). KENAI UNIT 34‐31 (1590130): Surface casing set at 1361'. No shallow drilling problems reported down to 4464' MD in daily operations summary (stopped reading the well records at that depth). Mud log shows only a minor amounts of gas down to 3750' MD. KENAI UNIT 21‐06 (1650060): No shallow drilling problems reported down to 5232' MD in daily operations summary (stopped reading the well records at that depth). 2 KENAI UNIT 11‐06 (165017): No shallow drilling problems reported down to 4459' MD in daily operations summary (stopped reading the well records at that depth). KENAI UNIT WD‐1 (1811070): No shallow drilling problems reported down to 3300' MD in daily operations summary (stopped reading the well records at that depth). KENAI UNIT 22‐6X (2081350): No shallow drilling problems reported down to 4220' MD in daily operations summary (stopped reading the well records at that depth).Mud log: gas not recorded until 2016' MD. Mud log shows only minor amounts of gas down to 5480' MD. From: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Sent: Thursday, April 16, 2020 1:34 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: KU 24‐32 diverter waiver Steve, Im ok with the waiver… do you have any thoughts.? Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). 1 Carlisle, Samantha J (CED) From:Monty Myers <mmyers@hilcorp.com> Sent:Wednesday, April 15, 2020 5:09 PM To:Schwartz, Guy L (CED) Cc:Davies, Stephen F (CED); Cody Dinger Subject:RE: [EXTERNAL] KU 24-32 (PTD 220-037) Attachments:updated pages 26 and 30.pdf; KU 24-32 Casing Design.pdf; KU 24-32 MASP Calc.pdf 1.) According to google earth the nearest residence is about 961’ away from well center. 2 2.) The SSV is in the normal spot as all the other wells in KGF. We have a variance from the state to place them in this configuration. I will find the letter and share it with you if needed. 3.) I used the pressure gradient from TD instead of L Beluga pressure. Updated it and attached copies to the email. 4.) I appreciate that! Will update the casing test to 2500 psi. 5.) What I stated as excess as 35% is incorrect. I intended to only pump 5% excess as the calculations state. Trying to keep cement returns from reaching surface to leave a testable annulus. Will have a swell packer inside surface casing as well. 6.) I updated the rams to 5‐1/2” in section 15.22 and attached her also, as per you later email at 2 pm. Thank you for reviewing, please let me know if you have any additional questions. Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Wednesday, April 15, 2020 11:39 AM To: Monty Myers <mmyers@hilcorp.com> Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: [EXTERNAL] KU 24‐32 (PTD 220‐037) Monty, I have some questions/comments for KU 24‐32 ; 1. For diverter waiver what is the closest private home or property in the area. 2. Why is SSV placed outboard of the wing valve. Should be closest it can be to the wellhead .. even on the horz run. 3. MASP calc is slightly off .. if using the expected pressure of the L Beluga the MASP is a bit higher at 1911 psi . Not much different. 4. I lowered the 7 5/8” casing test to 2500 psi … to reduce chance of creating a micro annulus. 5. The 5.5” casing cement volume is off… you are using a 1.05 multiplier for volume . (vs 35% excess as stated) Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:KENAI UNIT 24-32Initial Class/TypeDEV / PENDGeoArea820Unit51120On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200370KENAI, TYONEK GAS - 448570KENAI, BELUGA/UP TYONEK GNA1 Permit fee attachedYesSurface location in ADL0392668; top prod int and TD in Fee AA0938082 Lease number appropriateYes3 Unique well name and numberYesKenai, Beluga/ Upper Tyonek Gas Pool-448571 and Kenai, Tyonek Gas Pool 1 - 448570, governed by4 Well located in a defined poolYesCO 510A (Corrected)), Rule 2: There shall be no restrictions as to well spacing except that no gas pay shall5 Well located proper distance from drilling unit boundaryYesbe opened in a well within 1,500’ of an external property line of the Affected Area described above where6 Well located proper distance from other wellsYesthe owners and landowners are not the same on both sides of the line.7 Sufficient acreage available in drilling unitYesAs planned, well conforms with spacing requirements.8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes16 " conductor set at 12018 Conductor string providedYes7 5/8" surf casing set at 1750 ft. Fully cemented19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes5.5 long string will be cemented back to surf casing with swell packer also.21 CMT vol adequate to tie-in long string to surf csgYescement packer completion … Swell packer at 1400 ft.22 CMT will cover all known productive horizonsYesBTC calcs supplied.23 Casing designs adequate for C, T, B & permafrostYesRig has steel l tanks. All drlling waste to be transported to KGF disposal well.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYesNo issues26 Adequate wellbore separation proposedYesDiverter waived… several wells drilled on pad.27 If diverter required, does it meet regulationsYesMax form pressure 2500 psi (.41 psi/ft ) will drill with 9-10 ppg mud28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYesMASP = 1911 psi will test BOPE to 3500 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)YesNeed sundry approval to perforate.32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)YesNearby wells did not encounter H2S gas. Measures not required.35 Permit can be issued w/o hydrogen sulfide measuresYesPlanned mud weights appear adequate to control the operator's forecast of most likely pore pressures36 Data presented on potential overpressure zonesNApresented in the geologic prognosis. Sterling to Middle Beluga intervals all expected to be under-37 Seismic analysis of shallow gas zonesNApressured to severely under-pressured with exception of the Lower Beluga sands, which are expected to38 Seabed condition survey (if off-shore)NAbe approx. normally pressured. Lost circulation materials will be on site; mitigation discussed p. 39-40.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate4/14/2020ApprGLSDate4/16/2020ApprSFDDate4/16/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateCBL and MIT -IA after rig leaves. Cement packer completion. Gls. Recommend approving request for diverter waiver: no shallow gas hazards reported in records from the eight wells previously drilled from this pad. SFDJMP4/17/2020Type text here