Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:David Douglas
To:Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL] RE: Seaview 9, PTD 221-025, sidewall core description
Date:Wednesday, September 13, 2023 3:09:53 PM
Hi Meredith,
I wanted to be sure my lack of finding anything was valid, so I asked the Geologist too. There are no
Descriptions or Photos.
David DouglasSr. Geotechnician | Hilcorp Alaska, LLCO: (907) 777-8337 | C: (907) 887-63393800 Centerpoint Drive, Suite 1400 | Anchorage, AK 99503david.douglas@hilcorp.com
From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Sent: Wednesday, September 13, 2023 11:45 AM
To: David Douglas <David.Douglas@hilcorp.com>
Subject: [EXTERNAL] RE: Seaview 9, PTD 221-025, sidewall core description
And to follow up I also assume no core photos were taken, as none have been provided?
Thanks,
Meredith
From: Guhl, Meredith D (OGC)
Sent: Wednesday, September 13, 2023 11:44 AM
To: David Douglas - (C) <David.Douglas@hilcorp.com>
Subject: Seaview 9, PTD 221-025, sidewall core description
Hi David,
I’m reviewing the data submitted for Seaview 9, PTD 221-025, and am unable to locate a description
of the sidewall cores taken. Can you please check Hilcorp’s files and provide one if one exists? Or let
me know if I’ve overlooked it in the already submitted data.
Thank you,
Meredith
Meredith Guhl (she/her)
Petroleum Geology Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
meredith.guhl@alaska.gov
Direct: (907) 793-1235
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 Meredith Guhl at 907-793-1235 or
meredith.guhl@alaska.gov.
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 herebynotified 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 deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
From:Heusser, Heather A (DNR)
To:Guhl, Meredith D (OGC)
Cc:Morgan, Kirk A (DNR)
Subject:RE: Seaview 9, PTD 221-025, API 50-231-20078-00-00, due for release
Date:Wednesday, September 13, 2023 11:14:04 AM
Hi Meredith,
We have not received a request for extended confidentiality on Seaview 9.
Thank you,
Heather Ann Heusser
Natural Resource Specialist IV
State of Alaska
Department of Natural Resources
Division of Oil and Gas
550 West 7th Avenue, Suite 1100
Anchorage AK 99501-3560
heather.heusser@alaska.gov
From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Sent: Monday, September 11, 2023 9:35 AM
To: Heusser, Heather A (DNR) <heather.heusser@alaska.gov>
Subject: Seaview 9, PTD 221-025, API 50-231-20078-00-00, due for release
Hello Heather,
Has Hilcorp Alaska, LLC, requested extended confidentiality for the exploratory well Seaview 9,
completed August 10, 2021, and due for release after September 10, 2023?
Thank you,
Meredith
Meredith Guhl (she/her)
Petroleum Geology Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
meredith.guhl@alaska.gov
Direct: (907) 793-1235
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 Meredith Guhl at 907-793-1235 or
meredith.guhl@alaska.gov.
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 01/20/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
Seaview 9
PTD: 221-025
API: 50-231-20078-00-00
ROUTINE CORE ANALYSIS (01/03/2023) **CONFIDENTIAL**
1. FINAL REPORT
2. MS EXCEL DATA FILES
a. BATCH CLEANED (25-Feb-2022)
b. RCAL FINAL (16-Dec-2022)
Please include current contact information if different from above.
By Meredith Guhl at 3:18 pm, Jan 20, 2023
221-025
T37429
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2023.01.20 15:24:28 -09'00'
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
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Date: 2022.04.22
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ŐĂƐďĞĂƌŝŶŐĂŶĚƚŚƵƐƐŚŽƵůĚďĞĐŽŶƐŝĚĞƌĞĚĂƉŽŽůŽƌŶŽƚ͘ƐƐƵĐŚǁĞ͛ůůĂůůŽǁ,ŝůĐŽƌƉƚŽƉĞƌĨŽƌĂƚĞƚŚĞ
ĞůƵŐĂƐĂŶĚƐƚŽƐĞĞŝĨƚŚĞǁĞůůǁŝůůƉƌŽĚƵĐĞ͘/Ĩ,ŝůĐŽƌƉŐĞƚƐƚŚĞǁĞůůƚŽƐƵƐƚĂŝŶĨůŽǁǁĞǁŝůůƌĞƋƵŝƌĞĂ
ƉƌŽĚƵĐƚŝŽŶůŽŐƚŽďĞƌƵŶǁŝƚŚŝŶϯĚĂLJƐƚŽƐĞĞŝĨĂŶLJŽĨƚŚĞŐĂƐŝƐĐŽŵŝŶŐĨƌŽŵƚŚĞdLJŽŶĞŬĨŽƌŵĂƚŝŽŶ͘/Ĩ
ƚŚĞdLJŽŶĞŬŝƐĐŽŶƚƌŝďƵƚŝŶŐƚŽƚŚĞŐĂƐĨůŽǁƚŚĞŶĂƉůƵŐǁŝůůŚĂǀĞƚŽďĞƐĞƚƚŽŝƐŽůĂƚĞƚŚĞdLJŽŶĞŬƵŶƚŝůƚŚĞ
ĚŽǁŶŚŽůĞĐŽŵŵŝŶŐůŝŶŐŝƐƐƵĞĐĂŶďĞĚĞĂůƚǁŝƚŚ͘/ĨƚŚĞdLJŽŶĞŬŝƐŶŽƚĐŽŶƚƌŝďƵƚŝŶŐƚŽŐĂƐĨůŽǁƚŚĞŶƚŚĞ
ǁĞůůĐĂŶƌĞŵĂŝŶŽŶƉƌŽĚƵĐƚŝŽŶǁŝƚŚŽƵƚŚĂǀŝŶŐƚŽŝƐŽůĂƚĞƚŚĞdLJŽŶĞŬ͟
EŝƚƌŽŐĞŶZŝƐŬ
x ŝƐĐƵƐƐŶŝƚƌŽŐĞŶĂƐƉŚLJdžŝĂƚŝŽŶĐŽŶĐĞƌŶƐĂŶĚŝĚĞŶƚŝĨLJĂŶLJĂƌĞĂƐǁŚĞƌĞŶŝƚƌŽŐĞŶĐŽƵůĚĐŽůůĞĐƚĂŶĚƉĞŽƉůĞ
ĐŽƵůĚĞŶƚĞƌ͘
x ŽŶƐŝĚĞƌƚĂŶŬƉůĂĐĞŵĞŶƚďĂƐĞĚŽŶǁŝŶĚĚŝƌĞĐƚŝŽŶĂŶĚĐƵƌƌĞŶƚǁĞĂƚŚĞƌĨŽƌĞĐĂƐƚ;ǀĞŶƚŝŶŐEŝƚƌŽŐĞŶ
ĚƵƌŝŶŐƚŚŝƐũŽďͿ
x ŶƐƵƌĞĂůůĐƌĞǁƐĂƌĞĂǁĂƌĞŽĨƐƚŽƉǁŽƌŬĂƵƚŚŽƌŝƚLJ
WƌŽĐĞĚƵƌĞ͗
ϭ͘ D/Zh ͲůŝŶĞ͕WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϭ͕ϱϬϬƉƐŝŚŝŐŚ͘
Ϯ͘ ZƵŶ'WdƐƵƌǀĞLJƚŽŽďƚĂŝŶĨůƵŝĚůĞǀĞů
ϯ͘ /ĨĨůƵŝĚůĞǀĞůŝƐĂďŽǀĞŝŶƚĞŶĚĞĚƉĞƌĨŽƌĂƚŝŽŶnjŽŶĞƐ͗
Ă͘ ZhŶŝƚƌŽŐĞŶƚƌƵĐŬĂŶĚƉƵƐŚĨůƵŝĚďĂĐŬŝŶƚŽƉĞƌĨŽƌĂƚŝŽŶƐ
ď͘ ^ĞƚƉůƵŐĂďŽǀĞŽƉĞŶƉĞƌĨŽƌĂƚŝŽŶƐцϭ͕ϱϬϬ͛
ϰ͘ WĞƌĨŽƌĂƚĞǁĞůůƉĞƌƉƌŽŐƌĂŵ͘
ϱ͘ Z ͲůŝŶĞ͘
ϲ͘ dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘
6SDFLQJ H[FHSWLRQ GRHV QRW DOORZ SHUIRUDWLQJ DERYH WKH
VXUIDFH FDVLQJ VKRH EMP
3URSRVHG SHUIV
DUH DERYH WKH VXUIDFH FDVLQJ VKRH EMP
tĞůů͗^ĞĂǀŝĞǁͲϬϵ
ƚƚĂĐŚŵĞŶƚƐ͗
ϭ͘ ƵƌƌĞŶƚƐĐŚĞŵĂƚŝĐ
Ϯ͘ WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ
ϯ͘ ^ƚĂŶĚĂƌĚtĞůůƉƌŽĐĞĚƵƌĞʹEϮKƉĞƌĂƚŝŽŶƐ
hƉĚĂƚĞĚďLJ:>>ϭϭͬϭϴͬϮϭ
^, Dd/
^ĞĂǀŝĞǁϵ
Wd͗ϮϮϭͲϬϮϱ
W/͗ϱϬͲϮϯϭͲϮϬϬϳϴͲϬϬͲϬϬ
Wdсϯ͕ϱϴϵ͛ͬdsсϮ͕ϲϯϲ͛
dсϳ͕ϳϰϵ͛ͬdsсϲ͕ϮϯϬ͛
Z<ƚŽ'>сϭϴ͛
W Z&KZd/KE d/>
ŽŶĞ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ ŵƚ ĂƚĞ ^ƚĂƚƵƐ
>Ͳϭϯϱ ϭ͕ϲϮϳ͛ ϭ͕ϲϯϲ͛ ϭ͕ϱϮϲ͛ ϭ͕ϱϯϮ͛ ϵ ϭϬͬϮϯͬϮϭ KƉĞŶ
dͲϲ Ϯ͕ϭϲϯ͛ Ϯ͕ϭϳϯ͛ ϭ͕ϴϱϳ͛ ϭ͕ϴϲϮ͛ ϭϬ ϭϬͬϵͬϮϭ KƉĞŶ
dͲϲ Ϯ͕ϯϯϬ͛ Ϯ͕ϯϯϯ͛ ϭ͕ϵϱϬ͛ ϭ͕ϵϱϮ͛ ϯ ϭϬͬϱͬϮϭ KƉĞŶ
dͲϭϮ ϯ͕ϲϮϳ͛ ϯ͕ϲϰϱ͛ Ϯ͕ϲϱϲ͛ Ϯ͕ϲϲϲ͛ ϭϴ ϭϬͬϱͬϮϭ /ƐŽůĂƚĞĚϭϬͬϵͬϮϭ
dͲϭϲ ϰ͕ϯϱϳ͛ ϰ͕ϯϳϬ͛ ϯ͕Ϭϳϳ͛ ϯ͕Ϭϴϱ͛ ϭϯ ϭϬͬϯͬϮϭ /ƐŽůĂƚĞĚϭϬͬϵͬϮϭ
dϭϵ ϰ͕ϱϭϱΖ ϰ͕ϱϮϳΖ ϯ͕ϭϴϵΖ ϯ͕ϭϵϴΖ ϭϮΖ ϴͬϭϰͬϮϭ /ƐŽůĂƚĞĚϭϬͬϯͬϮϭ
dϮϭͺK> ϰ͕ϴϬϮΖ ϰ͕ϴϭϮΖ ϯ͕ϰϭϱΖ ϯ͕ϰϮϯΖ ϭϬΖ ϴͬϭϰͬϮϭ /ƐŽůĂƚĞĚϭϬͬϯͬϮϭ
dϮϭͺK> ϰ͕ϴϰϰΖ ϰ͕ϴϳϬΖ ϯ͕ϰϰϵ͛ ϯ͕ϰϳϭ͛ ϮϲΖ ϴͬϭϯͬϮϭ /ƐŽůĂƚĞĚϭϬͬϯͬϮϭ
dϯϬ ϱ͕ϭϬϱΖ ϱ͕ϭϯϮΖ ϯ͕ϲϳϮ͛ ϯ͕ϲϴϵ͛ ϮϳΖ ϴͬϭϯͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϰϬ ϱ͕ϯϵϮΖ ϱ͕ϰϭϮΖ ϯ͕ϵϮϴΖ ϯ͕ϵϰϴΖ ϮϬΖ ϴͬϭϯͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϰϳ ϱ͕ϱϲϴΖ ϱ͕ϱϳϱΖ ϰ͕ϬϵϮΖ ϰ͕ϬϵϵΖ ϳΖ ϴͬϭϯͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϲϱ ϲ͕ϭϲϰΖ ϲ͕ϮϬϳΖ ϰ͕ϲϲϳΖ ϰ͕ϳϭϬΖ ϰϯΖ ϴͬϭϮͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϲϱͺ^ ϲ͕ϮϲϱΖ ϲ͕ϮϳϲΖ ϰ͕ϳϲϳΖ ϰ͕ϳϳϴΖ ϭϭΖ ϴͬϭϮͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϲϱͺ^ ϲ͕ϮϲϱΖ ϲ͕ϮϳϲΖ ϰ͕ϳϲϳΖ ϰ͕ϳϳϴΖ ϭϭΖ ϴͬϭϭͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
KW E,K> ͬ D Ed d/>
ϳͲϱͬϴΗ ϵͲϳͬϴ͗,ŽůĞ͗ϴϱďďůƐϭϮƉƉŐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďLJϯϱďďůƐϭϱ͘ϴƉƉŐƚĂŝůĐĞŵĞŶƚ͘EŽ
ůŽƐƐĞƐ͘ϭϴďďůƐĐĞŵĞŶƚƚŽƐƵƌĨĂĐĞ
ϰͲϭͬϮ͟ϲͲϯͬϰ͟ŚŽůĞ͗ϮϭϮďďůƐϭϮ͘ϬƉƉŐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďLJϭϵďďůƐϭϱ͘ϯƉƉŐƚĂŝůĐĞŵĞŶƚ͘
EŽůŽƐƐĞƐ͘ϯϳďďůƐĐĞŵĞŶƚƚŽƐƵƌĨĂĐĞ͘dŽс>ŝŶĞƌŚĂŶŐĞƌΛϭ͕Ϯϰϵ͛D;ϴͬϮͬϮϭ>Ϳ
^/E' d/>
^ŝnjĞ dLJƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ
ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ
ƚŽ^ĞƚĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϮϬ͛
ϳͲϱͬϴΗ ^ƵƌĨƐŐ Ϯϵ͘ϳ >ͲϴϬ ϲ͘ϴϳϱ͟ ^ƵƌĨ ϭ͕ϰϵϴ͛
ϰͲϭͬϮΗ WƌŽĚ>Ŷƌ ϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟ ϭ͕Ϯϰϵ͛ ϳ͕ϳϰϰ͛
dh/E' d/>
ϰͲϭͬϮΗ WƌŽĚdŝĞďĂĐŬ ϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟ ^ƵƌĨ ϭ͕Ϯϱϱ͛
ϭ
ϭϲ͟
ϳͲϱͬϴ͟
ϰͲϭͬϮ͟
EŽ͘ĞƉƚŚ
;DͿ
ĞƉƚŚ
;dsͿ / /ƚĞŵ
ϭ ϰϵϬ͛ ϰϵϬ͛ ϯ͘ϴϭϯ͟ dZ^^^s^Ͳϱy ǁŝƚŚyƉƌŽĨŝůĞ;ĂŬĞƌͿ
Ϯ ϭ͕Ϯϱϱ͛ ϭ͕ϮϮϰ͛ ϰ͘ϳϵϬ͟ ^ĞĂůĂƐƐĞŵďůLJ͗ϵ͘ϲ͛ůŽŶŐ͘ϳ͘ϯ͛ƐƚĂďďĞĚŝŶƚŽ^Z;ĂŬĞƌͿ
ϯ ϭ͕Ϯϰϵ͛ ϭ͕Ϯϭϵ͛ ϰ͘ϴϳϱ͟ >ŝŶĞƌŚĂŶŐĞƌͬ>dWƐƐĞŵďůLJͬ^Z;ĂŬĞƌͿ
ϰ ϯ͕Ϭϱϯ͛ Ϯ͕ϯϰϯ͛ ϯ͘ϵϱϴ͟ ZƚĂŐ
ϱ ϯ͕ϱϴϵ͛ Ϯ͕ϲϯϲ͛
/WƐĞƚĂƚϯϲϮϬ͛DϭϬͬϵͬϮϭ͘;ϮϬŐĂůĐĞŵĞŶƚŽŶƚŽƉ
ϭϬͬϮϮͬϮϭͿ
ϲ ϰ͕ϰϳϱ͛ ϯ͕ϭϱϵ͛ /WƐĞƚϭϬͬϯͬϮϭ
ϳ ϱ͕ϬϵϬ͛ ϯ͕ϲϱϵ͛ /WƐĞƚϴͬϭϯͬϮϭ
ϴ ϱ͕ϵϳϵ͛ ϰ͕ϰϵϲ͛ ϯ͘ϵϱϴ͟ ZƚĂŐ
Ϯ
ϯ
ϰ
ϴ
ϳ
ϱ
ϲ
hƉĚĂƚĞĚďLJ:>>ϬϮͬϮϯͬϮϮ
WZKWK^
^ĞĂǀŝĞǁϵ
Wd͗ϮϮϭͲϬϮϱ
W/͗ϱϬͲϮϯϭͲϮϬϬϳϴͲϬϬͲϬϬ
Wdсϯ͕ϱϴϵ͛ͬdsсϮ͕ϲϯϲ͛
dсϳ͕ϳϰϵ͛ͬdsсϲ͕ϮϯϬ͛
Z<ƚŽ'>сϭϴ͛
W Z&KZd/KE d/>
ŽŶĞ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ ŵƚ ĂƚĞ ^ƚĂƚƵƐ
>ͲϭϭϬ цϭ͕ϯϯϵΖ цϭ͕ϯϰϴΖ цϭ͕Ϯϵϳ͛ цϭ͕ϯϬϰ͛ цϵ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ
>ͲϭϮϮ цϭ͕ϯϴϮΖ цϭ͕ϯϵϮΖ цϭ͕ϯϯϯ͛ цϭ͕ϯϰϭ͛ цϭϬ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ
>Ͳϭϯϱ ϭ͕ϲϮϳ͛ ϭ͕ϲϯϲ͛ ϭ͕ϱϮϲ͛ ϭ͕ϱϯϮ͛ ϵ ϭϬͬϮϯͬϮϭ KƉĞŶ
dͲϲ Ϯ͕ϭϲϯ͛ Ϯ͕ϭϳϯ͛ ϭ͕ϴϱϳ͛ ϭ͕ϴϲϮ͛ ϭϬ ϭϬͬϵͬϮϭ KƉĞŶ
dͲϲ Ϯ͕ϯϯϬ͛ Ϯ͕ϯϯϯ͛ ϭ͕ϵϱϬ͛ ϭ͕ϵϱϮ͛ ϯ ϭϬͬϱͬϮϭ KƉĞŶ
dͲϭϮ ϯ͕ϲϮϳ͛ ϯ͕ϲϰϱ͛ Ϯ͕ϲϱϲ͛ Ϯ͕ϲϲϲ͛ ϭϴ ϭϬͬϱͬϮϭ /ƐŽůĂƚĞĚϭϬͬϵͬϮϭ
dͲϭϲ ϰ͕ϯϱϳ͛ ϰ͕ϯϳϬ͛ ϯ͕Ϭϳϳ͛ ϯ͕Ϭϴϱ͛ ϭϯ ϭϬͬϯͬϮϭ /ƐŽůĂƚĞĚϭϬͬϵͬϮϭ
dϭϵ ϰ͕ϱϭϱΖ ϰ͕ϱϮϳΖ ϯ͕ϭϴϵΖ ϯ͕ϭϵϴΖ ϭϮΖ ϴͬϭϰͬϮϭ /ƐŽůĂƚĞĚϭϬͬϯͬϮϭ
dϮϭͺK> ϰ͕ϴϬϮΖ ϰ͕ϴϭϮΖ ϯ͕ϰϭϱΖ ϯ͕ϰϮϯΖ ϭϬΖ ϴͬϭϰͬϮϭ /ƐŽůĂƚĞĚϭϬͬϯͬϮϭ
dϮϭͺK> ϰ͕ϴϰϰΖ ϰ͕ϴϳϬΖ ϯ͕ϰϰϵ͛ ϯ͕ϰϳϭ͛ ϮϲΖ ϴͬϭϯͬϮϭ /ƐŽůĂƚĞĚϭϬͬϯͬϮϭ
dϯϬ ϱ͕ϭϬϱΖ ϱ͕ϭϯϮΖ ϯ͕ϲϳϮ͛ ϯ͕ϲϴϵ͛ ϮϳΖ ϴͬϭϯͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϰϬ ϱ͕ϯϵϮΖ ϱ͕ϰϭϮΖ ϯ͕ϵϮϴΖ ϯ͕ϵϰϴΖ ϮϬΖ ϴͬϭϯͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϰϳ ϱ͕ϱϲϴΖ ϱ͕ϱϳϱΖ ϰ͕ϬϵϮΖ ϰ͕ϬϵϵΖ ϳΖ ϴͬϭϯͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϲϱ ϲ͕ϭϲϰΖ ϲ͕ϮϬϳΖ ϰ͕ϲϲϳΖ ϰ͕ϳϭϬΖ ϰϯΖ ϴͬϭϮͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϲϱͺ^ ϲ͕ϮϲϱΖ ϲ͕ϮϳϲΖ ϰ͕ϳϲϳΖ ϰ͕ϳϳϴΖ ϭϭΖ ϴͬϭϮͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
dϲϱͺ^ ϲ͕ϮϲϱΖ ϲ͕ϮϳϲΖ ϰ͕ϳϲϳΖ ϰ͕ϳϳϴΖ ϭϭΖ ϴͬϭϭͬϮϭ /ƐŽůĂƚĞĚϴͬϭϯͬϮϭ
KW E,K> ͬ D Ed d/>
ϳͲϱͬϴΗ ϵͲϳͬϴ͗,ŽůĞ͗ϴϱďďůƐϭϮƉƉŐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďLJϯϱďďůƐϭϱ͘ϴƉƉŐƚĂŝůĐĞŵĞŶƚ͘EŽ
ůŽƐƐĞƐ͘ϭϴďďůƐĐĞŵĞŶƚƚŽƐƵƌĨĂĐĞ
ϰͲϭͬϮ͟ϲͲϯͬϰ͟ŚŽůĞ͗ϮϭϮďďůƐϭϮ͘ϬƉƉŐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďLJϭϵďďůƐϭϱ͘ϯƉƉŐƚĂŝůĐĞŵĞŶƚ͘
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ϭϱ͘Ϳ tŚĞŶĨŝŶĂůŶŝƚƌŽŐĞŶǀŽůƵŵĞŚĂƐďĞĞŶĂĐŚŝĞǀĞĚ͕ŝƐŽůĂƚĞǁĞůůĨƌŽŵEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ
ďůĞĞĚĚŽǁŶůŝŶĞƐďĞƚǁĞĞŶǁĞůůĂŶĚEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚ͘
ϭϲ͘Ϳ KŶĐĞLJŽƵŚĂǀĞĐŽŶĨŝƌŵĞĚůŝŶĞƐĂƌĞďůĞĚĚŽǁŶ͕ŶŽƚƌĂƉƉĞĚƉƌĞƐƐƵƌĞĞdžŝƐƚƐ͕ĂŶĚŶŽŶŝƚƌŽŐĞŶŚĂƐ
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ϭϳ͘Ϳ &ŝŶĂůŝnjĞũŽďůŽŐĂŶĚĚŝƐĐƵƐƐŽƉĞƌĂƚŝŽŶƐǁŝƚŚtĞůůƐŝƚĞDĂŶĂŐĞƌ͘ŽĐƵŵĞŶƚĂŶLJůĞƐƐŽŶƐůĞĂƌŶĞĚ
ĂŶĚĐŽŶĨŝƌŵĨŝŶĂůƌĂƚĞƐͬƉƌĞƐƐƵƌĞͬǀŽůƵŵĞƐŽĨƚŚĞũŽďĂŶĚƌĞŵĂŝŶŝŶŐŶŝƚƌŽŐĞŶŝŶƚŚĞƚƌĂŶƐƉŽƌƚ͘
ϭϴ͘Ϳ ZDKEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘
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
SEAVIEW 9 (PTD 221-025) *CONFIDENTIAL*
GPT-PERF 10/22/2021
Please include current contact information if different from above.
Received By:
01/11/2022
37'
(6HW
By Abby Bell at 12:03 pm, Jan 11, 2022
1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program
Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well
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 7,749 feet See schematic feet
true vertical 6,230 feet N/A feet
Effective Depth measured 3,589 feet 1,249 feet
true vertical 2,636 feet 1,219 feet
Perforation depth Measured depth 1,627 - 2,333 feet
True Vertical depth 1,526 - 1,952 feet
Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / L-80 1,255 MD 1,224 TVD
1,249 MD 490 MD
Packers and SSSV (type, measured and true vertical depth)Baker SBR 1,219 TVD TRSSSV S-5 490 TVD
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
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:
Contact Name:
Contact Email:
Authorized Title:Contact Phone:
321-506
Sr Pet Eng:
7,500psi
Sr Pet Geo: Sr Res Eng:
Authorized Name and
Digital Signature with Date:
WINJ WAG
0
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
0
436
8,430psi
Ryan Rupert
ryan.rupert@hilcorp.com
(907) 777-8503Dan Marlowe - Operations Manager
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
0 1670
0 0
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
120'
1,498'
N/A
0
Structural
TVD
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
221-025
50-231-20078-00-00
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL392667 / Private Fee
Seaview Unit / Seaview Undefined Gas Pool
3800 Centerpoint Dr, Suite 1400
Anchorage, AK 99503
3. Address:
Seaview 9
Hilcorp Alaska, LLC
Other: N2 Operations
measuredPlugs
Junk measured
N/A
Length
120'
1,498'
Size
Conductor
Surface
Intermediate
16"
7-5/8"
Production
Liner 6,495'
Casing
120'
1,426'
4-1/2" 7,744' 6,225'
6,890psi
Burst Collapse
4,790psi
L
G
Form 10-404 Revised 10/2021 Submit Within 30 days of Operations
By Samantha Carlisle at 12:33 pm, Nov 19, 2021
Digitally signed by Dan Marlowe
(1267)
DN: cn=Dan Marlowe (1267),
ou=Users
Date: 2021.11.19 11:49:11 -09'00'
Dan Marlowe
(1267)
SFD 11/29/2021BJM 12/1/21 DSR-11/22/21
RBDMS HEW 11/22/2021
1
Winston, Hugh E (OGC)
From:Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent:Monday, October 25, 2021 4:14 PM
To:McLellan, Bryan J (OGC); Roby, David S (OGC)
Cc:Dan Marlowe; Donna Ambruz; Pete Iverson; Katherine O'connor; Chad Ebenezer; Benjamin Siks;
Anthony McConkey; Sierra Becia; Vanessa Hughes; Ryan Rupert
Subject:RE: [EXTERNAL] RE: SV-09 (PTD#221-025)
Attachments:Seaview 9 Schematic(10-25-21).pdf
Bryan, per our conversation, attached is an updated schematic for SV‐09 with the weekend’s activity. Below are the EL
records from the weekend as well. The well was left open to compression (WHP <50psi) all weekend, and still isn’t
registering any flow. No flow at it’s individual meter, nor any changes to the rate off the pad sales meter. Given this,
Hilcorp feels confident that there’s no flow from any of the 3 currently open sands in SV‐09 (T‐6A, T‐6, BEL‐135).
Hilcorp’s plan is to leave the well in its current configuration and regroup on a path forward. Hilcorp is not planning on
running a production log, not setting any plugs in the short‐term. Thanks,
Oct 22
2021
PRESENT OPERATIONS:
RIH WITH 2 3/4" GPT LOG DOWN TO 3618', FOUND FLUID @ 3530', POOH
RIH WITH 2 3/4" GPT LOG DOWN TO 3618', FOUND FLUID @ 3530', POOH
MIX UP CEMENT, RIH WITH 2 - 3 1/2" BAILOR 20', DUMP CEMENT AT 3605', POOH - TOTAL CEMENT DUMPED 20 GALS,
RIGGED DOWN FOR THE NIGHT
Oct 23
2021
PRESENT OPERATIONS:
18' FROM CCL TO BOTTOM OF GUN, RIH TAG CEMENT, TAGGED @ 3589'
RIH WITH 2 3/4" GG AND 9' OF 2 7/8" RAZOR 6/60,PERF @ 1627-1636, 8.5' FROM CCL TO TOP SHOT, CCL DEPTH = 1618.5', SHOT -
line to compressor and drew down from 640 psi to 25 psi in 30 minutes. Shut in for 30 minutes and well built from 28 psi to 56 psi. Ope
compressor and left flowing. Currently not registering any flow on meter.
Ryan Rupert
Kenai Ops Engineer (13146)
907-301-1736 (Cell)
907-777-8503 (Office)
2
From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Sent: Monday, October 25, 2021 11:54 AM
To: Roby, David S (CED) <dave.roby@alaska.gov>; Ryan Rupert <Ryan.Rupert@hilcorp.com>
Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Pete Iverson
<jpiverson@hilcorp.com>; Katherine O'connor <Katherine.Oconnor@hilcorp.com>; Chad Ebenezer
<cebenezer@hilcorp.com>; Benjamin Siks <bsiks@hilcorp.com>; Anthony McConkey <amcconkey@hilcorp.com>; Sierra
Becia <Sierra.Becia@hilcorp.com>; Vanessa Hughes <vhughes@hilcorp.com>
Subject: [EXTERNAL] RE: SV‐09 (PTD#221‐025)
I agree with the plan below, but the WRP set under step 6a isn’t considered to be adequate for long term isolation, so if
the decision is made to go for downhole commingling authorization it must be pursued expeditiously. If you can’t
submit the commingling application within a week of doing the differential well test shown in step 5 a more secure plug
should be installed while the commingling application works its way through or notice/hearing/order process.
Regards
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: Roby, David S (CED) <dave.roby@alaska.gov>
Sent: Monday, October 25, 2021 10:50 AM
To: Ryan Rupert <Ryan.Rupert@hilcorp.com>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Pete Iverson
<jpiverson@hilcorp.com>; Katherine O'connor <Katherine.Oconnor@hilcorp.com>; Chad Ebenezer
<cebenezer@hilcorp.com>; Benjamin Siks <bsiks@hilcorp.com>; Anthony McConkey <amcconkey@hilcorp.com>; Sierra
Becia <Sierra.Becia@hilcorp.com>; Vanessa Hughes <vhughes@hilcorp.com>
Subject: RE: SV‐09 (PTD#221‐025)
Hi Ryan,
That’ll work for my purposes.
Bryan,
How’s this look to you?
Dave Roby
(907)793‐1232
From: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent: Friday, October 22, 2021 8:23 AM
To: Roby, David S (CED) <dave.roby@alaska.gov>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Pete Iverson
<jpiverson@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com>; Katherine O'connor
<Katherine.Oconnor@hilcorp.com>; Chad Ebenezer <cebenezer@hilcorp.com>; Benjamin Siks <bsiks@hilcorp.com>;
3
Anthony McConkey <amcconkey@hilcorp.com>; Sierra Becia <Sierra.Becia@hilcorp.com>; Vanessa Hughes
<vhughes@hilcorp.com>
Subject: SV‐09 (PTD#221‐025)
Dave‐
Thanks for the clarification on SV‐09. Below is the scope that Hilcorp is planning to execute. Please let us know if you
concur? Hilcorp proposed steps 5 and 6 below in lieu of a production log. Is that acceptable?
1. Dump at least 25’ of cement on existing CIBP at 3620’. WoC
2. Tag ToC with junk basket on SL or EL. Confirm hard tag at expected ToC location
3. Perforate BEL‐135 per sundry
4. Flow well for 3 days
5. If sustains flow, set WRP between the BEL‐135 and T‐6 at ~2150’ MD
6. Based on change in gas rate, Hilcorp will either:
a. Progress a comingling option with AOGCC, leave WRP in place in the meantime. OR
b. Replace plug with a CIBP, or leave WRP in place. Dump 25’ cement on top of plug, either way.
Ryan Rupert
Kenai Ops Engineer (13146)
907-301-1736 (Cell)
907-777-8503 (Office)
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
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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.
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 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.
Updated by JLL 11/18/21
SCHEMATIC
Seaview 9
PTD: 221-025
API: 50-231-20078-00-00
PBTD = 3,589’ / TVD = 2,636’
TD = 7,749’ / TVD = 6,230’
RKB to GL = 18’
PERFORATION DETAIL
Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status
BEL-135 1,627’ 1,636’ 1,526’ 1,532’ 9 10/23/21 Open
T-6 2,163’ 2,173’ 1,857’ 1,862’ 10 10/9/21 Open
T-6A 2,330’ 2,333’ 1,950’ 1,952’ 3 10/5/21 Open
T-12A 3,627’ 3,645’ 2,656’ 2,666’ 18 10/5/21 Isolated 10/9/21
T-16A 4,357’ 4,370’ 3,077’ 3,085’ 13 10/3/21 Isolated 10/9/21
T19 4,515' 4,527' 3,189' 3,198' 12' 8/14/21 Isolated 10/3/21
T21_COAL 4,802' 4,812' 3,415' 3,423' 10' 8/14/21 Isolated 10/3/21
T21_COAL 4,844' 4,870' 3,449’ 3,471’ 26' 8/13/21 Isolated 10/3/21
T30 5,105' 5,132' 3,672’ 3,689’ 27' 8/13/21 Isolated 8/13/21
T40 5,392' 5,412' 3,928' 3,948' 20' 8/13/21 Isolated 8/13/21
T47 5,568' 5,575' 4,092' 4,099' 7' 8/13/21 Isolated 8/13/21
T65 6,164' 6,207' 4,667' 4,710' 43' 8/12/21 Isolated 8/13/21
T65_BASE 6,265' 6,276' 4,767' 4,778' 11' 8/12/21 Isolated 8/13/21
T65_BASE 6,265' 6,276' 4,767' 4,778' 11' 8/11/21 Isolated 8/13/21
OPEN HOLE / CEMENT DETAIL
7-5/8"9-7/8: Hole: 85bbls 12ppg lead cement followed by 35bbls 15.8ppg tail cement. No
losses. 18bbls cement to surface
4-1/2”6-3/4” hole: 212bbls 12.0ppg lead cement followed by 19bbls 15.3ppg tail cement.
No losses. 37bbls cement to surface. ToC = Liner hanger @ 1,249’ MD (8/2/21 CBL)
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 CDC 6.875” Surf 1,498’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,249’ 7,744’
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,255’
1
16”
7-5/8”
4-1/2”
No.Depth
(MD)
Depth
(TVD)ID Item
1 490’ 490’ 3.813” TRSSSV S-5 BXCE with BX profile (Baker)
2 1,255’ 1,224’ 4.790” Seal assembly: 9.6’ long. 7.3’ stabbed into SBR (Baker)
3 1,249’ 1,219’ 4.875” Liner hanger / LTP Assembly / SBR (Baker)
4 3,053’ 2,343’ 3.958” RA tag
5 3,589’ 2,636’
CIBP set at 3620’ MD 10/9/21. (20 gal cement on top
10/22/21)
6 4,475’ 3,159’ CIBP set 10/3/21
7 5,090’ 3,659’ CIBP set 8/13/21
8 5,979’ 4,496’ 3.958” RA tag
2
3
4
8
7
5
6
BEL-135 1,627’ 1,636’ 1,526’ 1,532’ 9 10/23/21 Open
T-6 2,163’ 2,173’ 1,857’ 1,862’ 10 10/9/21 Open
T-6A 2,330’ 2,333’ 1,950’ 1,952’ 3 10/5/21 Open
T-12A 3,627’ 3,645’ 2,656’ 2,666’ 18 10/5/21 Isolated 10/9/21
T-16A 4,357’ 4,370’ 3,077’ 3,085’ 13 10/3/21 Isolated 10/9/21,, ,////,
Rig Start Date End Date
E-Line 10/2/21 10/23/21
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
Seaview 9 50-231-20078-00-00 221-025
10/02/2021 - Saturday
10/04/2021 - Monday
Bled down to tank overnight, no LELs. Shot FL today, and see minimal fluid, or maybe plug. FL = 4,405' MD.
FL shot on tubing shows FL= 2,480' MD. RU N2 and push away. Trap N2 pressure on well (bleeding off). RDMO.
10/03/2021 - Sunday
ARRIVE ON LOCATION, INITIATE PERMIT, SPOT EQUIPMENT, PJSM. BEGIN RIG UP, PICK UP WIRELINE, STACK PCE, MAKE
UP TOOLSTRING, VERIFY SENSORS, AND STAB ON WELL. PRESSURE TEST 250L/3,500H. RIH W/ 1.375" FISHING NECK
CH/WB/WB/TTTCU/AUH/QPC/CTF. OAL: 25', MAX OD 2.75", TW 400#. LOG FLUID LEVEL LOG FROM 4,950'-4,500'
FINDING FLUID LEVEL AT 4,860'. START TO POOH. AT APPROXIMATELY 511', START TO PULL TENSION WORK IT FOR A
WHILE AND DECIDE TO PUMP UP THE TRSSSV SOME MORE. ABLE TO MOVE PAST IT AND TO SURFACE. AT SURFACE,
SHUT IN AND BLEED OFF. BREAK OFF LUBE AND DROP DOWN GPT. HOOK UP GPLT AND CHECK FIRE. HOOK UP CIBP AND
STAB ON WELL. RIH W/ 1.375" FISHING NECK CH/WB/GPLT/BAKER10/3.5"CIBP. OAL: 20', MAX OD 3.375", TW 400#. LOG
CORRELATION PASS FROM 4,610'-4,300'. LOG CIBP SETTING PASS STOPPING AT CCL DEPTH: 4,462.5'. CCL TO MID
ELEMENT OFFSET: 12.5'. MID ELEMENT SET AT 4,475'. LOST 400# AFTER SETTING. GOOD INDICATION OF SET. START TO
POOH. AT SURFACE, SHUT IN AND BLEED OFF. BREAK OFF LUBE AND DROP DOWN SETTING TOOL. DUE TO GUN LOADER
NOT AVAILABLE TO LOAD GUN UNTIL SUNDAY, H.E.S. DRIVES BACK TO STERLING TO PICK UP GUN NEEDED TO
PERFORATE WHILE WELL IS BEING BLED DOWN TO 100 PSI. H.E.S. ARRIVES BACK ON LOCATION WITH PERFORATING
GUN. CHECK FIRE TOOLSTRING, ARM GUN, AND STAB ON WELL. RIH W/ 1.375" FISHING NECK CH/GPLT/ 2.875" x 15' HSC
(13' LOADED). OAL: 24', MAX OD 3.375", TW 300#. LOG CORRELATION PASS FROM 4475'-4200. SEND TO TOWN FOR
APPROVAL. TOLD TO ADD 3' TO SHIFT LOG DOWN.LOG PERFORATION PASS STOPPING AT CCL DEPTH: 4,348.5'. CCL TO
TOP SHOT OFFSET: 8.5'. PERFORATE 4,357'-4,370'. LOST 500# AFTER SHOOTING. GOOD INDICATION OF FIRE. START TO
POOH. AT SURFACE, SHUT IN AND BLEED OFF. BREAK OFF LUBE AND DROP DOWN SHOT GUN. START TO RIG DOWN
ELINE. RIG DOWN COMPLETE, PUT EVERYTHING AWAY AND SECURE. LEAVE LOCATION.
PERFORATE 4,357'-4,370'
LOG CIBP SETTING PASS STOPPING AT CCL DEPTH:
MID ELEMENT SET AT 4,475'
Rig Start Date End Date
E-Line 10/2/21 10/23/21
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
Seaview 9 50-231-20078-00-00 221-025
10/05/2021 - Tuesday
BEGIN RIG UP, PICK UP WIRELINE, AND STACK PCE. PRESSURE TEST 250L/3,500H. CHECK FIRE TOOLSTRING, HOOK UP
GUN, AND STAB ON.
RIH W/ 1.375" FISHING NECK CH/GPLT/2.875" x 21' HSC (18' LOADED). OAL: 30', MAX OD 3.375", TW 350#.
LOG CORRELATION PASS FROM 4,250'-3,400'. SEND TO TOWN FOR APPROVAL. TOLD LOG WAS ON DEPTH. LOG
PERFORATION PASS STOPPING AT CCL DEPTH: 3,617.5'. CCL TO TOP SHOT OFFSET: 9.5'. PERFORATE 3,627'-3,645'. LOST
700# AFTER SHOOTING. GOOD INDICATION OF FIRE. START TO POOH.
AT SURFACE, SHUT IN AND BLEED OFF. BREAK OFF LUBE AND DROP DOWN SHOT GUN. STANDBY FOR DECISION.
DECISION MADE TO SHOOT THE NEXT GUN. CHECK FIRE, ARM GUN, AND STAB ON. RIH W/ 1.375" FISHING NECK
CH/GPLT/2.875" x 15' HSC (3' LOADED). OAL: 24', MAX OD 3.375", TW 300#.
LOG CORRELATION PASS FROM 2,500'-2,200'. SEND TO TOWN FOR APPROVAL. TOLD LOG WAS ON DEPTH.
LOG PERFORATION PASS STOPPING AT CCL DEPTH: 2,311.5'. CCL TO TOP SHOT OFFSET: 18.5'. PERFORATE 2,330'-2,333'.
LOST 250# AFTER SHOOTING. GOOD INDICATION OF FIRE. START TO POOH. AT SURFACE, SHUT IN AND BLEED OFF.
BREAK OFF LUBE AND DROP DOWN SHOT GUN. START TO RIG DOWN ELINE.
RIG DOWN COMPLETE, PUT EVERYTHING AWAY AND SECURE.
PERFORATE 3,627'-3,645'
PERFORATE 2,330'-2,333'
Rig Start Date End Date
E-Line 10/2/21 10/23/21
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
Seaview 9 50-231-20078-00-00 221-025
10/22/2021- Friday
RIH WITH 2 3/4" GPT LOG DOWN TO 3618', FOUND FLUID @ 3530', POOH. RIH WITH 2 3/4" GPT LOG DOWN TO 3618',
FOUND FLUID @ 3530', POOH. MIX UP CEMENT, RIH WITH 2 - 3 1/2" BAILOR 20', DUMP CEMENT AT 3605', POOH -
TOTAL CEMENT DUMPED 20 GALS, RIGGED DOWN FOR THE NIGHT.
10/09/2021 - Saturday
TRAVEL FROM HES SHOP TO SEAVIEW 9. ARRIVE ON LOCATION, INITIATE PERMIT, SPOT EQUIPMENT, PJSM.
BEGIN RIG UP, PICK UP WIRELINE, STACK PCE, MAKE UP WATER SAMPLE TOOLSTRING, AND STAB ON WELL. PRESSURE
TEST 250L/3,500H. RIH W/ 1.375" FISHING NECK CH/WB/WB/CCL/SPANGS/2.5" SAMPLE BAILER. OAL: 30', MAX OD
2.75", TW 400#. TAG AT 4,344' AND POOH WITH WATER SAMPLE. AT SURFACE, SHUT IN, AND BLEED DOWN. DROP
DOWN BAILER AND DUMP SAMPLE IN BUCKET. BAILER IS FOUND TO BE FULL OF "GOO". CLEAN OUT BAILER AND STAB
BACK ON FOR A WATER SAMPLE. RIH W/ 1.375" FISHING NECK CH/WB/WB/CCL/SPANGS/2.5" SAMPLE BAILER. OAL: 30',
MAX OD 2.75", TW 400#. STOP AT 4,000' TO OBTAIN WATER SAMPLE WITHOUT GOING TO BOTTOM AND INTO THE
GOO. POOH. AT SURFACE, SHUT IN, AND BLEED DOWN. DROP DOWN BAILER AND BAILER IS FOUND TO BE EMPTY.
DECISION MADE TO RIH TO FIND FLUID LEVEL. BREAK OFF BAILER AND MAKE UP FLUID LEVEL TOOLSTRING. STAB ON
WELL. RIH W/ 1.375" FISHING NECK CH/WB/WB/TTTC/AUH/QPC/CTF. OAL: 25', MAX OD 2.75", TW 400#. TAG AT 4,344'
AND LOG UP TO 2,000'. FLUID LEVEL APPEARS TO BE AROUND 2,190' BUT THE PRESSURE GRADIENT OF THE FLUID IS
ABNORMAL. LOG SENT TO ENGINEER AND GEOLOGIST TO DISCUSS. POOH. AT SURFACE, SHUT IN, AND BLEED OFF.
BREAK DOWN TOOLSTRING AND WAIT ON ORDERS. DECISION MADE TO PUMP 2,000 GAL OF NITROGEN AND THEN SET
THE CIBP. MAKE UP TOOLS, CHECK FIRE, AND HOOK UP SETTING TOOL. STAB ON WELL AND WAIT ON NITROGEN TO
FINISH PUMPING. RIH W/ 1.375" FISHING NECK CH/WB/WB/GPLT/BAKER 10/3.5" OD CIBP. OAL: 30', MAX OD 3.375",
TW 550#. LOG CORRELATION PASS FROM 3,750'-3,500'. SEND TO TOWN FOR APPROVAL. TOLD LOG WAS ON DEPTH.
LOG CIBP SETTING PASS STOPPING AT CCL DEPTH: 3,607.5'. CCL TO MID ELEMENT OFFSET: 12.5'. MID ELEMENT SET AT
3,620'. LOST 200# AFTER SETTING. GOOD INDICATION OF SET. START TO POOH.
AT SURFACE, SHUT IN AND BLEED OFF. BREAK OFF LUBE AND DROP DOWN SETTING TOOL. BLEED WELL DOWN TO 800
PSI. CHECK FIRE, ARM GUN, AND STAB ON WELL. RIH W/ 1.375" FISHING NECK. CH/WB/WB/GPLT/2.875"x11' HSC (10'
LOADED). OAL: 31', MAX OD 3.375", TW 500#. LOG CORRELATION PASS FROM 2,300'-2,000'. SEND TO TOWN FOR
APPROVAL. TOLD LOG WAS ON DEPTH. LOG PERFORATION PASS STOPPING AT CCL DEPTH: 2,155.5'. CCL TO TOP SHOT
OFFSET: 7.5'. PERFORATE 2,163'-2,173'. LOST 200# OF TOOL WEIGHT AFTER SHOOTING. GOOD INDICATION OF FIRE.
START TO POOH AT SURFACE, SHUT IN AND BLEED OFF. BREAK OFF LUBE AND DROP DOWN SHOT GUN. START TO RIG
DOWN ELINE. RIG DOWN COMPLETE, FINISH PUTTING EVERYTHING AWAY AND SECURE. LEAVE LOCATION.
LOG CIBP SETTING PASS STOPPING AT CCL DEPTH: 3,607.5'. CCL TO MID ELEMENT OFFSET: 12.5'. MID ELEMENT SET AT
3,620'.
PERFORATE 2,163'-2,173'.
RIH WITH 2 - 3 1/2" BAILOR 20', DUMP CEMENT AT 3605',
Rig Start Date End Date
E-Line 10/2/21 10/23/21
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
Seaview 9 50-231-20078-00-00 221-025
10/23/2021 - Saturday
18' FROM CCL TO BOTTOM OF GUN, RIH TAG CEMENT, TAGGED @ 3589'. RIH WITH 2 3/4" GG AND 9' OF 2 7/8" RAZOR
6/60,PERF @ 1627-1636, 8.5' FROM CCL TO TOP SHOT, CCL DEPTH = 1618.5', SHOT - POOH. Brought well on line to
compressor and drew down from 640 psi to 25 psi in 30 minutes. Shut in for 30 minutes and well built from 28 psi to 56
psi. Opened back up to compressor and left flowing. Currently not registering any flow on meter.
,PERF @ 1627-1636,
MEMORANDUM
State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg % �� �►� -Z�:'Ll DATE:
P. I. Supervisor
FROM: Matt Herrera SUBJECT:
Petroleum Inspector
7/16/2021
Leak Off Test
Hilcorp Rig 169
Seaview #9; PTD 2210250 '
Hilcorp Alaska LLC
7/15/2021: Traveled to Hilcorp Seaview drill site to witness the leak off test after drilling
out from 7 5/8 -inch casing. I met with Hilcorp Company Representative Doug Yessak
and rig personnel and went over the rig up. They had the test pump rigged up for the
pressure test and we went over the "BBL/inch ratio" for pumping and anticipated break
over point for the well. All went as anticipated and drilling operations continued as
planned.
Attachments: Operator Leak -off Test Report
2021-0715 Leak -off Test Seaview-9 mh.docx
Page 1 of 1
V
CASING AND LEAK -OFF FRACTURE TESTS
Well Name: Seaview 9 Date: 7/15/2021
Csg Size/Wt/Grade: 7 5/8" / 29.7# / L-80 Supervisor: D. Yessak
Csg Setting Depth: 1,499 TMD 1,427 TVD
Mud Weight: 8.9 ppg LOT / FIT Press = 650
LOT / FIT = 17.66 ppg Hole Depth = 1524
Fluid Pumped= 6.9 Gals Volume Back = 6.3
Test Pump Output: 2.300 Gals/Inch
LOT / FIT DATA CASING TEST DATA
Enter Gallons Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
0
0
2.3
100
4.6
400
6.9
- 700
Enter Holding Enter Holding
Time Here Pressure Here
0
0.5
1
1.5
0
750
1500
— -- - 2250
2
3000
5
3000
10
3000
Enter Holding Enter Holding
Time Here Pressure Here
->
->
->
->
->
->
->
->
->
->
->
->
->
->
0
1
-- _ - ----
2
- - - -- - --
3
700
670
-
660
-
650
->
->
->
->
->
->
->
->
->
->
->
5
3000
10
3000
15
---;- 3000
- --- 20 - --
3000
4 640
25
3000
5 630
6 625
30
- -- -
3000
-
- 7 620-
8 615-
9 610
10 605
11 600
12 600
13 600
psi
and
Gals
LOT / FIT DATA f CASING TEST DATA
njb 'ZZ� C'L
1500
--- — —
1400
1300
1200
1100
1000
900
:y
Q
800
d
7
ui
d
0.5
a
700
600
500
400
300
200
100
0
0 Strokes (# of) 10
5g -a -)o J I LOT / FIT DATA CASING TEST DATA
pv �2
1500 -- -
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
0 5 10 15 20 25 30 35
Kaitlyn Barcelona Hilcorp North Slope, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: kaitlyn.barcelona@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 10/20/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025)
Plug Perf 10/03/2021
Please include current contact information if different from above.
37'
(6HW
eceived By:
10/25/2021
By Abby Bell at 12:02 pm, Oct 25, 2021
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422
Received By: Date:
Date: 09/24/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025) **CONFIDENTIAL**
EXTENDED MICRO IMAGER (XRMI) PROCESSED INTERPRETATIONS (08/17/2021)
Folder Contents (Electronic Plots and Digital Data):
Please include current contact information if different from above.
PTD: 2210250
E-Set: 35685
09/27/2021
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 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s):
GL: 211.6' BF:211.6'
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 1,426'
4-1/2" L-80 6,225'
4-1/2" L-80 1,224'
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 Rate
July 19, 2021
July 11, 2021
ADL 392667 / Private FEE
LOCI 18-001
N/A
N/AN/A
490' MD / 490' TVD
7,749' MD / 6,230' TVD
LWD, Mudlog, Borehole Volume / Sonic, Micro Imager, SW Core, CBL, GPT Perf
Sr Res EngSr Pet GeoSr Pet Eng
Oil-Bbl: Water-Bbl:
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/A
*** Please see attached schematic for perforation details ***
Water-Bbl:
PRODUCTION TEST
N/A
Date of Test:
Flow Tubing
84#
29.7#
120'
1,249' 7,744'
Gas-Oil Ratio:Choke Size:
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#
1,255'
1,219'
Surface
DEPTH SET (MD)
1,249'
PACKER SET (MD/TVD)
Surface
CASING WT. PER
FT.GRADE
12.6#
160883
160185
TOP
SETTING DEPTH MD
Surface
SETTING DEPTH TVD
2106188
BOTTOM TOP
6-3/4"
72 bbls
Surface
9-7/8"
HOLE SIZE AMOUNT
PULLED
50-231-20078-00-00
Seaview 9
163025 2108532
1095' FSL, 2404' FEL, Sec 9, T5S, R15W, SM, AK
CEMENTING RECORD
2106791
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
8/10/2021
2425' FNL, 370' FEL, Sec 9, T5S, R15W, SM, AK
474' FSL, 2194' FWL, Sec 9, T5S, R15W, SM, AK
221-025
Seaview Unit / Seaview Undef Gas Pool
229.6'
5,090' MD / 3,660' TVD
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
Driven
Surface 1,498' L - 200 sx / T - 165 sx
Driven
L - 505 sx / T - 100 sx
Surface
1,255'4-1/2" Tibeack
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,
Tieback Assy.Tieback
TUBING RECORD
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Meredith Guhl at 8:25 am, Sep 13, 2021
G
RBDMS HEW 9/13/2021
Completion Date
8/10/2021
HEW
DLB 09/13/2021BJM 10/11/21
SFD 10/6/2021 DSR-9/13/21
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval T19(Top Perf) 4515' 3188'
349' 349'
372' 372'
394' 394'
1553' 1470'
1755' 1617'
1961' 1743'
2161' 1856'
2858' 2238'
3566' 2623'
4515' 3188'
5616' 4136'
6083' 4588'
6210' 4713'
Tyonek
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).
T19
T48
T65
T70
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.
T12A
Formation at total depth:
Beluga 135
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
T10
Permafrost - Top
Beluga 138
Sterling C2
Beluga
Sterling C1
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
Beluga 140
T6
Sidewall cores obtained at 1634'(Beluga 135), 1703' (Beluga 136), 1801'(Bel 138), 2202', 2203', 2233' MD(T6). All sand/claystone mixture.
Cores to be sent to the lab for analysis and labwork will + chips will be sent to the AOGCC thereafter.
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS
No
NoSidewall Cores: Yes No
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
9.13.2021Digitally 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: 2021.09.13 07:01:36 -08'00'
Monty M
Myers
Updated by CJD 9-9-2021
SCHEMATIC
Seaview 9
PTD: 221-025
API: 50-231-20078-00-00
PBTD = 7,659’ / TVD = 6,142’
TD = 7,749’ / TVD = 6,230’
RKB to GL = 18’
PERFORATION DETAIL
Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status
T19 4,515' 4,527' 3,188' 3,200' 12' 8/14/21 Open
T21_COAL 4,802' 4,812' 3,415' 3,425' 10' 8/14/21 Open
T21_COAL 4,844' 4,870' 3,450’ 3,462’ 26' 8/13/21 Open
T30 5,105' 5,132' 3,672’ 3,689’ 27' 8/13/21 Isolated 8/13
T40 5,392' 5,412' 3,928' 3,948' 20' 8/13/21 Isolated 8/13
T47 5,568' 5,575' 4,092' 4,099' 7' 8/13/21 Isolated 8/13
T65 6,164' 6,207' 4,667' 4,710' 43' 8/12/21 Isolated 8/13
T65_BASE 6,265' 6,276' 4,767' 4,778' 11' 8/12/21 Isolated 8/13 (reperf)
T65_BASE 6,265' 6,276' 4,767' 4,778' 11' 8/11/21 Isolated 8/13
OPEN HOLE / CEMENT DETAIL
7-5/8" 9-7/8: Hole: 85bbls 12ppg lead cement followed by 35bbls 15.8ppg tail cement. No
losses. 18bbls cement to surface
4-1/2” 6-3/4”hole: 212bbls 12.0ppg lead cement followed by 19bbls 15.3ppg tail cement.
No losses. 37bbls cement to surface. ToC = Liner hanger @ 1,249’ MD (8/2/21 CBL)
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 CDC 6.875” Surf 1,498’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 1,249’ 7,744’
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 1,255’
1
16”
7-5/8”
4-1/2”
No. Depth ID Item
1 490’ 3.813” TRSSSV S-5 BXCE with BX profile (Baker)
2 1,255’ 4.790” Seal assembly: 9.6’ long. 7.3’ stabbed into SBR (Baker)
3 1,249’ 4.875” Liner hanger / LTP Assembly / SBR (Baker)
4 3,053’ 3.958” RA tag
5 5,090’ CIBP set 8/13/21
6 5,979’ 3.958” RA tag
2
3
4
6
5
Activity Date Ops Summary
7/3/2021 Tore out aux fuel tank and HPU skid, replaced sensor on deadman, removed draw works brake bands, remove pit equalizer lines, Great Northern Hydraulics
replaced a couple hoses on manrider winch option, tore out degasser skid, cont loading floats with various equipment. Disposed of felt/liner that was;under
catwalk.;Lowered vac degasser, lowered roofs on pits 2 and 3, layed derrick over, loaded last of rig water tank into clean vac truck for re-use, PU loaded
exposed rig mats and transport to Seaview pad, change back gaskets on shakers 1 and 3,;Finish changing gaskets on shaker 1 & 3 secure objects ot top of pits,
lower pit roof 1, prep modules f/ transport, secure shelves and equipment in C Can, clean green shack and change shack prep to move, clean up location,
transport vac trucks to whiskey gulch pad for staging, fold walkways up & pin
7/4/2021 On BC pad 4, cont to clean up location and prep mod’s for tear out. CCI on location at 07:00. Tore out water tank/doghouse, spotted crane and picked centrifuge
then iron roughneck off rig floor, tore out pit 3, picked choke house with crane, tore out pit 2 and 1, tore out pump/pit jig, tore out pump;1, spotted crane and
removed derrick house then layed down windwalls, spotted 2nd crane, RU and picked derrick off carrier, picked carrier off sub base, picked sub off pony walls,
loaded rig mats and one pony wall, loaded another trailer with rig mats and second pony wall, PU and stacked;loaded another trailer with rig mats and second
pony wall, PU and stacked remaining rig mats on pad 4, relocated crane and picked wellhouse out of oil storage berm, set same on side of pad 4, loaded up jig
and pit mod 2 stairs, Tool Push and crew traveled to Seaview pad with DSA, wear ring;and running tool to mark and measure for felt, liner. and mats. Rig
mechanic servicing floor motor at BC next to rig's shop. Called Tom Clark to Seaview pad to discuss needed gravel for better leveling around cellar boxes and
flowline sumps. CCI chasing loader bucket and 4' x 8' sheet iron to lay;over #10 cellar box and flowline sumps.;Prep location mark out rig foot print, set DSA and
spacer spool on starting head, get load of gravel and steel plates, get grade on pad with loader, fill in holes and cover flow line holes with steel plates, lay felt
and liner mark out;rig layout, lay mats around cellar and set back yard, hauling trailers to Whiskey gulch pad for staging;Continue laying mats for backyard, finish
setting all mats, orient and set Diverter T and bag on well, spot pony subs and Iron roughneck HPU, organize pad prep f/ rig components, send crews back to
beaver creek to police pad and prep to move complexes.
7/5/2021 Installed new brake bands on draw-works drum, replaced front seal on floor motor, removed new deadman sensor, bled off air and re-installed on deadman.
Assisted wellhead rep and production foremen stacking tree and assembly of flow line on BCU-04RD. Found 1000 psi gauge had pegged out over night,;on
BCU-04RD. Brought in productions small bleed tank, bled off 130 gallons dropping pressure to 600 psi, tubing was also at 1000 psi. Bled off 20 gallons to zero
psi. Notified workover Engineer, decision made to bring in larger bleed tank and attempt to bleed IA to zero.;RD meeting trailer, change house and rig shop in
prep to move same. Rig mechanic replaced valve cover gasket on floor motor, assisted at BA yard with inventory and organizing, CCI traveld to Seaview and set
one last rig mat, organized pad. On BCU-04RD we bled off 26 bbls diesel from IA. Could not;get IA below 95 psi, had steady rate of 6.7 bph flow rate. Bled a
total of 26 bbls and notified workover Engineer. Decision made to shut in and monitor/document pressure vs time. Bled tubing from 150 psi to zero with 6 gallons
and shut in both tubing and IA. Tubing built to 380 psi over 4 hours, IA;built to 1450 psi over 4 hours. Tri-Point Rep, Pollard Slickline boom truck and unit and
HotOil truck all on location at 18:00 hrs, spotted same.;Pollard RU lubricator, MU PX plug and MU lubricator on tree, production brought in tri-plex test pump and
tested lubricator for Pollard, RIH with slickline,;Crews prepping to move rig when trucks arrive, ETA of trucks 0700hrs, prep load organize modules and clean
7/6/2021 Crew double checked all loaded items on BC pad 1 to ensure everything secure for rig move, CCI on standby for rig move until BCU-04RD packer reset and IA
flow stopped. Rig crew cont to perform maintenance at BA yard. Could not get plug set in BCU-04RD with slickline, called out e-line, RD slickline.;Worked on
topdrive compensators and measured topdrive extend arms for modification. Rig support replacing valves on dragon boxes. On BCU-04RD, e-line RIH to set
plug, POOH due to lack of wire, snagged and lost tool string down hole, POOH RD e-line, called out slickline to retrieve tool string.;Rig crew cont rig
maintenance. Spot unit, RU lubricator and M/U JD pulling tool w/ bell guide, spang jars, oil jars, & 10' of weight bar back to rope socket. stab lubricator on tree,
RU production tri-plex and test lubricator, 250 psi Low & 3000 psi High.;RIH w/ slickline and fishing assembly, got P/U weight @ 10,782' -P/U-600 LBS. Cont.
RIH w/ slickline F/10,782', latched onto fish @ 10,834' WLM, attempted to move fish up hole w/ no luck, started jarring on fish w/ 650 lbs. over pull multiple time
w/ no luck, cont. staging up over pull weight,;w/ 1150 lbs. of over pull fish came free and started moving up hole w/ 230 lbs of extra weight on the hook.;POOH
w/ slickline tools and fish F/10,834'-T/Surface.;Blew down lubricator, broke Bowen connection, L/D E-line tools w/ plug shearing tool but no plug. M/U 2.79"
gauge ring, spang jars, oil jars, and 18' of weight bars back to rope socket, stab lubricator on tree, RU production tri-plex and test lubricator, 250 psi Low & 3000
psi High.;RIH w/ slickline assembly F/Surface-T/10791', got new P/U weight-660 lbs. Cont. RIH and tagged top of plug @ 10,853'. Attempted to free plug and
move down hole multiple times w/ no luck.;POOH w/ slickline F/10,853'-T/Surface. IA pressure 1480 psi;R/D Pollard slickline unit & lubricator. Released Pollard
slickline. Cont. monitoring IA pressure-1480 psi and tubing pressure 0 psi.;Cont. monitoring well while waiting on orders. IA pressure-1480 psi and tubing
pressure 40 psi.
18
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
SV Seaview 9
Seaview
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
HEC 169
Job Name:211-00047 Seaview 9 Drilling
Spud Date:
7/7/2021 Crew cont working with Rig Foreman in yard. Discussed with Area Ops Manager and Workover Engineer on plan forward, decision made to attempt pressure up
on tubing and communicate with 9 5/8" packer at 10.954'.;Staged hot oil truck on BCU-04RD, started bleed off of 3 1/2" x 9 5/8" IA to production bleed tank while
RU hot oil truck on tree top. Bled total 13.3 bbls to achieve 95 psi.;Hot oil truck pressured up on 3 1/2" tubing to 4950 psi and IA flow began to taper off. Appears
we are able to pump through or around the composite plug that was lost down hole. Held tubing pressure 1 hour and IA flow eventually reduced to nothing.;Bled
tubing back to truck with no increase in IA flow. Pressured back up to 5300 on tubing, what little flow from IA (tubing expansion) reduced to nothing. Notified
Area Ops Manager and Workover Engineer. Held 5300 on tubing for 1 hour, then bled off with no sign of IA flow. RD hot oil truck from;tree. Monitored IA at bleed
off tank for 1 hour and had no flow. Shut in IA on two gauges (One a digital recording gauge) and monitored 1 hour with no IA pressure increase. Notified Area
Op's Manager and obtained approval to move rig to Seaview pad.;Notified Tool Pusher, CCI drivers, BC office and Susan Dionne office of upcoming rig move.
Cont to monitor IA, CCI in field at 14:30 loading gen skid, pit 1, both pumps and doghouse/water tank on BC pad 1.;Started out of BC field with crane and empty
bed truck, followed with sub base, derrick, carrier, gen skid, pit 1, pumps 1 and 2 and doghouse/water tank and pilot cars. All trucks on main highway at 17:00
hrs.;Traveled to Seaview pad in Anchor Point, taking the long way around Old Sterling Highway, total 90 miles one way.;Moved in and spotted both CCI cranes,
set w/ crane, sub on pony walls, carrier on sub, derrick on carrier and pinned derrick to sub. Started hooking up electrical cables & HYD lines. R/D and parked
one crane, tailed in and spotted & set rig water tank/dog house w/ winch truck..;At 21:00 hrs. Toolpusher contacted night DSM regarding equip. damage. While
traveling to Seaview pad by way of old Sterling Hwy with rig modules being moved by CCI rig movers and pilot cars in front and back of loads. The rig water
tank/ dog house at 16.3' caught a overhead fiber optic cable;and tore it off a telephone pole. Moving permits were good for 17' in height. DOT & the state
troopers were both notified along with Hilcorps safety representative and the project drilling engineer. Equip. damage on top of dog house-Pason radio box, light,
and gas alarm horns (see photos).;Spotted & set Gen 1&2 skid, started running and hooking up interconnects from gen skid to sub and dog house. Raised &
pinned V-door wind wall w/ crane. Craned in set and pinned iron roughneck on rig floor, scoped dog house out of rig water tank and extended dog house to rig
floor. Spotted & set TDS;HPU skid and pit module #1 w/ winch truck. R/U walk ways on gen skid & and along water tank. Picked, set, & pinned choke house w/
crane onto outriggers on ODS. Spotted & set walk way jig between pumps & pits w/ fork lift.;Crew change. Cont. R/U electric cables & HYD lines. Raised &
pinned derrick, craned in and set clam shell on back side of derrick. Fired up Gen #1, turned on power & lights to dog house and sub, spotted & set MP skids to
jig. Ran cable and got the lights on in derrick. raised roof on pit module #1.;Spotted & set auxiliary fuel tank w/ winch truck, R/U stand pipe, hooked up TDS HYD
to rig floor, hooked up mud line to sub and MP suction to pit module #1. Laid liner for cat walk, CCI night rig support working on clean up perimeter of pad it prep
for mud docks, office trailers, and sleeper.;Cont. to R/U on Seaview 9 at report time.
7/8/2021 Cont RU on Seaview pad, RD office trailers, safety shack and sleeper on BC pad 4. CCI on BC pad 1 at 09:00 and loading pits 2-3, boiler skid and catwalk.
Transported same to Seaview, offloaded and returning for office trailers.;Set pits 2-3, set boiler skid, set catwalk and lay over beaver slide. Set upright water
tank, installed shaker slides, equalizer lines, flow line. Burned in new brake bands on draw works, set centrifuge and control panel. Staged rig shop;Set poorboy
degasser skid in place, installed vent line and stood vessel. Set safety shack, office trailer, push shack, sleeper shack, change shack and shop. Set genset and
bang box, wired in same and on power. Raised pit 2-3 roof tops and installed lights, spooled up drill line on drum, bridled up.;Installed turn buckles on top
section of TQ tube, Inspected derrick, pinned lower section of TQ tube, scoped derrick to drill position. Installed T-bar on TQ tube, bridle down, R/U second
weight indicator, hooked up crown Pason cord and plugged in crown section lights.;Installed choke hose on rig floor, spotted & set Baroid and Geo-Log shacks.
Off loaded and set shaker screen and drilling conex.;Held PTSM, crew change. Cont. R/U- Ran & plugged in power cords for centrifuge, staged TDS TQ
bushing and TDS on catwalk, held PJSM on picking TDS, R/U TDS hoisting equip. pulled TDS to rig floor, pinned dog bones on TDS to blocks.;Installed TQ
bushing to TQ tube, pinned TDS to TQ bushing, hooked up TDS HYD ram lines, ran and plugged in power cables for Baroid and Geo-log shack, brought on
location and off loaded spill and Handy berm conex, R/U Geronimo line.;Bump tested hopper/gun line centrifugal pumps, agitators, and shakers, R/U service
loop and Kelley hose to TDS, Safety out grating in cellar. Cont. working on organizing pad. Currently cont. to R/U and work through rig acceptance check list.
7/9/2021 Set dumpsters, built wet/dry docks for mud product and bermed same, cont working diverter “T” for vent line clearance of catwalk, dehydrator building and
compressor building, RU office and service shack comm’s, Handy Berm bermed in rig footprint, set Sperry shack, started trucking in rig water,;removed shim's
from rig transmission valve body, functioned draw works in various gears to collect lockup data for Allison Transmission Engineer, cont working on rig
acceptance checklist.;Cont running draw works for lockup data, cont truck in rig water, inspected centrifuge drive belts, cont working diverter vent line routing,
took on rig fuel, cont offload various equipment trailers, received rig loader and attachments, received Sperry tools and source box, offloaded trailer of mud;mud
product.;Cont. N/U diverter system, checked koomey bottle pre-charge, changed out schrader valve on koomey bottle, changed oil on floor motor transmission,
offloaded CCI hurricane vac and spotted by cutting box. Finish hauling and filled rig tank, vertical tank, and pits 1-3 & 7 w/ water. R/U koomey lines to;knife valve
and diverter annular. Chained & centered stack. Finished N/U diverter, diverter gun barrel end is 80' from any ignition source. Installed 4" valves on conductor
and function tested (ok). installed flow line to flow nipple, cont. organizing pad and offloading misc. trailers.;Held PTSM, crew change. Cont. R/U and working on
rig acceptance check list. Cleaned up cellar area and put up tools. Function tested annular and knife valve. Annular closing time 35 sec. Knife valve opening
time 2 sec. Hydro tested diverter stack (no leaks). Vac'd out stack, pulled test plug,;installed 14" ID wear ring & RILD's, pressure tested surface lines to 4,000 psi
(ok). R/U pipe racks, changed air filters on gen 1-3. Racked & drifted 7-5/8" 29.7 ppf L-80 CDC surface casing. L/D test jt and test plug. Verified TQ against TDS,
IR, and tongs.;P/U DP and RIH and tagged bottom @ 125' RKB. Currently adjusting drill TQ.;Hauled 0 bbls of solids to KGF G&I
Cumulative: 0 bbls
Hauled 0 bbls of fluid to KGF G&I
Cumulative: 0 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
7/10/2021 MU wash tool and singled in hole tagging bottom of conductor at 125.5’, racked back two stands, installed anchor block at diverter vent line tail pipe and secured
with chain, Quadco Rep replaced cracked glass on weight indicator in doghouse, replaced damaged audio/visual alarm on top of doghouse,;, then tested and
calibrated all sensors and alarms. Crew removed chains off diverter stack and shock hose from choke house to poorboy degasser, raised and shimmed off side
sub base, re-installed chains on stack and shock hose. Racked and tallied DP while welder repaired broken suction valve in pit;6, trucked in more mix water and
started mixing gel in pits, PU and MU stands. Rig acceptance checklist complete. Accepted Rig at 12:00 on 7-10-21;Finished racking a
total of 43 stands DP in derrick, received jars, racked, tallied, PU and racked back 8 stands HWDP in derrick. Cont. mixing spud mud. Scheduled with AOGCC
Rep to witness diverter test at 09:00 Sunday morning. Strapped surface casing. Dummy ran hanger. Racked back more DP.;Cont. P/U & racking back 4.5" DP in
derrick. Cleaned casing thread on shoe track. Finish building 508 bbls of spud mud.;Held PTSM, crew change, had weekly Sunday safety meeting w/ rig crew.
Cont. P/U & racking back 42 more stds. of 4.5" DP in derrick. Set TDS drill TQ to 16.5K, P/U & racked back drilling jars & flex collars in derrick.;Performed rig
service-greased crown, blocks, TDS, DWKS, IR, drive shaft, and brake linkage. MP pulsation dampeners= MP1= 650 psi MP2= 750 psi;R/U DD/MWD monitor
in dog house, cleaned and organized pad, completed PM's on DWKS, crew van, MP 1 & 2 gear end, and rig loader. Currently re-shimming torque bushing of
TDS to level TDS.;Hauled 0 bbls of solids to KGF G&I
Cumulative: 0 bbls
Hauled 0 bbls of fluid to KGF G&I
Cumulative: 0 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
MU wash tool and singled in hole tagging bottom of conductor at 125.5’,
ggg p
Finished N/U diverter, diverter gun barrel end is 80' from any ignition source.
7/11/2021 Adjust satellite hyd hoses on topdrive to clear extend arms etc, finish up PM’s on loader and mud pumps, verified with pad operator on ESD locations around
pad and pad entrance. AOGCC Rep on location at 09:00.;Did walk around and inspection of diverter vent line, signage, diverter stack, koomey room. Pulled tape
for measurements on vent line and nearest ignition sources. Discussed chain link fence and cut window in same at end of vent line. Function tested annular and
knife valve with joint 4 1/2";½” in hole, verified annular element holding, Quadco Rep on location at 09:30 and tested all audio/visual alarms. Functioned PVT’s
and performed draw down test of koomey unit. Had no failures.;L/D single joint, staged BHA #1 and bit.;PU motor w/1.5° bend, MU HDBS tricone bit jetted w/3 x
20’s, MU DM collar and scribed with an RFO of 175.48°, MU DGR, PWD, ADR, ALD, CTN, TM and XO, MU topdrive, plugged in and downloaded MWD, lined
up and shallow pulse tested tools, held PJSM and loaded sources, C/O XO, MU stand HWDP and topdrive.;Flooded stack and checked for leaks, no leaks,
started pumping at 422 gpm-840 psi, 50 rpm-1655 ft/lbs on bottom torque drilled from 125’ to 238', wob 6K, 106 ft/hr ROP. At 180' increased pump rate to 485
gpm-1160 psi. 137 ft/hr ROP, MW 8.7/vis 152, ECD's at 8.4 ppg, BGG 0 units. CBU at 238'.;Pulled up hole two stands, RIH with NM flex DC's and 1 stand
HWDP.;Resumed drilling 9 7/8" surface from 238' to 304', rotating wob 8K, 501 gpm-1272 psi, 100 ft/hr ROP, 74 rpm-2300 ft/lbs on bott torque, MW 8.8/vis 210,
ECD's at 9.1 ppg, BGG 0 units.;Cont. drilling 9 7/8" hole F/304'-T/613'. Started our kick off at 550' . P/U-45K S/O-45K ROT-45K GPM-550 SPP-1640 psi Diff-50
psi WOB-10K RPM--70 TQ-2.6K;Held PTSM, crew change. Cont. directional drilling 9 7/8" hole F/613'-T/934'. P/U-49K S/O-50K ROT-50K GPM-550 SPP-1864
psi Diff-50 psi WOB-13K RPM--70 TQ-3K Max gas 36 units ROP-140 ECD-9.42 Distance to well plan: 1.72' 1.66' High 0.48' Left.;Hauled 38 bbls of solids
to KGF G&I
Cumulative: 38 bbls
Hauled 77 bbls of fluid to KGF G&I
Cumulative: 77 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
7/12/2021 Cont directional drilling 9 7/8” surface hole from 934’ to 1041’, wob 17 to 19K, 551 gpm-1842 psi, 69 rpm-3100 to 3200 ft/lbs on bott torque, 76 to 100 ft/hr ROP,
MW 9.0/vis 93, ECD's at 9.4 ppg, BGG 18 units, max gas 33 units. Wiper trip planned at this depth.;Mad passed and obtained survey. Pumped a 20 bbl hi-vis
condet sweep around at 545 gpm-1736 psi, 60 rpm-1738 to 1800 ft/lbs off bott torque, sweep came back 5 bbls early with 25% increase in cuttings. Flow
checked for 10 minutes, appears static.;Pulled up hole on elevators from 1044' to jars, then slacked off and parked string at 367'. No issues pulling pipe. Up wt
50K coming off bottom. Cont to run trip tank to monitor during rig service.;Serviced rig and topdrive, checked driveline bolts (ok), checked suction screens on
both pumps (clean). Lost 1/2 bbl over 30 minutes in trip tank.;TIH on elevators from 367' to 981', MU last stand and topdrive, filled pipe then washed down to
1041'. No issues during trip in. Made hook.;Resumed drilling from 1041’ to 1413', sliding wob 24K, 553 gpm-1926 psi, 165 to 170 psi diff, 69 ft/hr ROP. Rotating
wob 16 to 19K, 552 gpm-1943 psi, 71 rpm-3450 ft/lbs on bott torque, 19 to 80 ft/hr ROP, MW 9.3/vis 86, ECD’s at 9.6 ppg, BGG 14 units, max gas 94 units at
1320’.;Cont directional drilling 9-7/8" hole F/1413' to TD called by Geologist @ 1504' MD 1431' TVD. P/U-57K S/O-53K ROT-56K GPM-550 SPP-2000 psi Diff-
100 psi WOB-20K RPM-70 TQ-4.3K;CBU X2, shot survey for directional, flow check (static). GPM-550 SPP-1900 psi RPM-70 TQ-2.6K;POOH on elevators
F/1504'-T/370'. P/U-59K S/O-55K. Calculated hole fill-11.1 bbls Act-11.9 bbls Diff--.8 bbls;RIH on elevators F/370'-T/1504', w/ no fill on bottom. P/U-59K S/O-
53K. Calculated pipe Disp-22 bbls Act-22.5 bbls Diff-.5 bbls;CBU, pumped 20 bbl Hi-Vis sweep w/ walnut & condet. GPM-550 SPP-1875 psi RPM-80 TQ-
3K;Held PTSM, crew change. Sweep came back 15 bbls late w/ a 25% increase in cuttings. Cont. circulating till shakers cleaned up. Flow check( static). Gave
Halliburton E-liners 4 hr. notice.;POOH on elevators w/ 9-7/8" drilling BHA #1 F/1504' to HWDP. Racked back HWDP, jars, & flex collars in derrick, removed
sources, down loaded MWD tools, B/O and L/D MWD tools, bit came back green and in gauge. Bit graded 1-1 WT A E I PN TD, Calculated hole fill-11.8 bbls
Act-12.4 bbls Diff-.6 bbls;Cleaned & cleared rig floor. Started 2nd 300 bbl batch of 6% KCL PHPA mud;Held PJSM w/ Halliburton E-liners, Currently MIRU E-
line. Distance to well plan: 10.63' 10.61' High .57' Right;Hauled 99 bbls of solids to KGF G&I
Cumulative: 136 bbls
Hauled 136 bbls of fluid to KGF G&I
Cumulative: 214 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
7/13/2021 RU E-line, M/U sonic tool string, Gamma/directional & caliper tools, transmitter receiver and head, RIH and tag on depth at 1504' md, log up hole @ 1200 fph,
RD and release Haliburton E-line.;Service the Rig and Top Drive;PJSM, MU cleanout BHA, RR 9 7/8'' tri cone bit, bit sub, XO, stab, 2 NMFCs, XO, 4 jts HWDP,
jars, 13 jts HWDP=631.95, RIH on stands 4 1/2'' DP TO 738' with 20k set down,
M/U TD, wash and ream down to 750' x3 cleaning up tight spot 407 gpm, 512 psi, 30 rpm, 1.1k tq, RIH on elevators to 1439';MU TD, break circulation, pump 23
bbl hi vis sweep 550 gpm, 960 psi, 50 rpm, 2.5k tq working pipe, sweep back 7 bbls late with 10% increase,
condition mud lowering YP from 28 to 20, final MW 9.3+ in/out, vis 63 in/68 out, flow check the well, static
PU 52K, SO 45K;TOOH on elevators from 1504' to 630', rack back HWDP, L/D BHA, bit grade= 1-1, in gauge,
Note: L/D flex collars the piston seal on iron ruffneck failed, L/D remaining BHA using rig tongs.;Clear and clean the rig floor, drained stack & pulled 14'' ID wear
bushing.;R/U Weatherford casing equip. loaded racks w/ 7-5/8" 29.7 ppf L-80 CDC shoe track & casing for surface. R/U fill up line. Held PJSM w/ rig crew,
Weatherford hands, & DSM.;P/U shoe jt. flash lighted and Baker locked shoe track, filled shoe track and tested floats (ok). Cont. running 7-5/8" 29.7 ppf L-80
CDC surface casing as per run tally filling on the fly and topping off after every ten jts.;P/U & M/U hanger, landing jt. and pup. P/U-56K S/O-45K. Drained stack,
landed hanger on seat. M/U drive sub to pup. M/U TDS. Gave Vetco wellhead Rep Chris Rich 3 hr. notice;Broke circ. 3.2 bpm, staged up pump to 4 bpm. GPM-
180 SPP-10 psi. Cont. circ. & conditioning mud for cmt job. R/D Weatherford casing equip. R/U bail extensions. Got cmt head to rig floor. laid out liner for cmt
trucks, spotted cmt trucks & equip. R/U HES cmts.;Held PTSM, crew change. Cont. circ. & conditioning mud while R/U HES cmts. Finished R/U HES cmts,
landed hanger on seat, shut down pump. loaded plugs into plug launcher, M/U cmt head to casing stump. broke circ. through cmt head. P/U-52K S/O-50K GPM-
186 SPP-974 psi.;Held PJSM w/ rig crew, HES hands, Baroid, CCI, & DSM. HES loaded lines with 5 bbls of water & check for leaks, HES pressure tested cmt
lines 337 psi Low / 3319 psi High (ok). HES pumped 38.6 bbls of 10.5 ppg Tuned Prime spacer at 4 bpm-95 psi, dropped bottom plug, and pumped 85.2 bbls
(200sx) of;12 ppg lead cmt at 4 bpm-87 psi, followed by 35.1 bbls (165 sx) of 15.8 ppg tail cmt at 4 bpm-140 psi. HES dropped top plug, then displaced w/ 9.3
ppg spud mud at 4.2 bpm. Slowed pump to 2 bpm w/ 10 bbls to go. Bumped plug at 64.8 bbls into displacement (Calculated 65 bbls). Held 1211 psi;(FCP of 497
psi) for 3 minutes, bled off and floats held. Bled back 1 bbl to truck. Had 38.6 bbls of spacer returns to surface and 18 bbls of lead cmt to surface. Added Bridge
maker LCM to lead cmt 5.65 lbs per/bbl. Mix water temp 38 deg. Pumped 50% excess on lead & tail.;Lost 0 bbls throughout the job. Did reciprocate casing in till
cmt rounded the shoe. CIP at 03:35 hrs.;Flushed HES cmt lines, broke down cmt lines and removed cmt head from landing jt. drained stack to cellar, backed out
& L/D landing jt. P/U & M/U Johnny Wacker to E-Kelly, flushed stack, L/D Johnny Wacker and E-Kelly. Currently M/U landing jt. to pack off running tool & pack
off.;Hauled 43 bbls of solids to KGF G&I
Cumulative: 179 bbls
Hauled 197 bbls of fluid to KGF G&I
Cumulative: 411 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
ppg p ( )
Had 38.6 bbls of spacer returns to surface and 18 bbls of lead cmt to surface.
p
;Resumed drilling from 1041’ to 1413',
gqp pp g p g
;P/U shoe jt. flash lighted and Baker locked shoe track, filled shoe track and tested floats (ok). Cont. running 7-5/8" 29.7 ppf L-80
CDC surface casing
drilled from 125’ to 238', w
pp q
drilling 9-7/8" hole F/1413' to TD called by Geologist @ 1504' MD
p
HES pumped 38.6 bbls of 10.5 ppg Tuned Prime spacer at 4 bpm-95 psi, dropped bottom plug, and pumped 85.2 bblsppg()pp ppg ppp
(200sx) of;12 ppg lead cmt at 4 bpm-87 psi, followed by 35.1 bbls (165 sx) of 15.8 ppg tail cmt at 4 bpm-140 psi.
Cont. directional drilling 9 7/8" hole F/613'-T/934'
E-line, M/U sonic tool string,
g
Max gas 36 units
pp pp
Bumped plug at 64.8 bbls into displacement (Calculated 65 bbls)ppg p ( )
)ppg pp
Gamma/directional & caliper tools,
1431' TVD.
;Lost 0 bbls throughout the job.
Cont directional drilling 9 7/8” surface hole from 934’ to 1041’, w
BGG 18 units, max gas 33 units.
7/14/2021 Finish M/U packoff running tool, install pack off as per WH rep, RILDS, test packoff body seals to 3000 psi for 10 minutes, good. L/D running tool and landing
joint
Simops: clean in pits;PJSM, N/D diverter system, pressure wash and cleanout flowline, flow nipple, annular, knife valve, diverter tee, spool and DSA, R/D
diverter line.
AOGCC Jim Regg waived test witness via phone call @ 10:30 am.;NU multi-bowl wellhead assy, WHR test P-seals to 3000 psi for 10 minutes, good. Stage
BOPs and cradle near cellar and crane into position.;R/U cellar crane to stack, installed 24" spacer spool, set BOP's in place, N/U BOPE. Installed kill & choke
lines, bell nipple, flow box, & flow line. Chained and centered stack to well. R/U hole fill line. Hooked up koomey lines, energized koomey,
Simops: C/O ram on iron roughneck, test same.;function tested rams & HCR's. Built 4.5" test plug, set test plug, filled stack, mud lines, and choke manifold w/
water. Purged air out of system. Obtained RKB's. Had Quadco on location at 18:00 hrs. to test gas alarm system. Hauled off Spud mud in pits 1-3 and cleaned
pits.;Off line: On the south side of the pad, we wired 4x8 sheets of plywood to the fence to create a sound dampening barrier. Due to the fact we had noise
complaints.;Performed BOP's testing on 4.5" as per state regulation. 250/Low 3500/High 5/5 min. Witness waved by AOGCC Jim Regg. Started testing at 10:00
hrs.;Held PTSM, crew change. Cont. testing BOP's on 4.5". Had 1 F/P on test #3, HYD IBOP, functioned and re-tested-PASS.;R/D testing equip, drained stack,
blew down mud lines & choke manifold, greased choke manifold. Installed 9" wear ring & RILD's.;Staged BHA #3 components on catwalk,. Currently testing
surface casing to 3000 psi on chart for 30 min.;Hauled 31 bbls of solids to KGF G&I
Cumulative: 210 bbls
Hauled 376 bbls of fluid to KGF G&I
Cumulative: 787 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
7/15/2021 Finish testing 7 5/8'' casing to 3000 psi for 30 charted min, good test. Bleed off pressure, open blind ram, R/D test equipment.
29.3 gal pumped, 29.2 gal bled back.;MU 6 3/4" directional BHA (#3) as follows: 6 3/4" HDBS bit jetted with 5 x11's, 1.5 deg mtr, DM, GM, ADR, ALD, stab,
CTN, PWD, TM HOC collars,
upload MWD, MU TD, shallow tested tools, good, PJSM- load sources, RIH with NM flex DC's, HWDP and jars = 740.56'.;Continue TIH on 4 1/2" DP from 740'
to 1358', M/U top drive, obtain SPRs and parameters
PU 50K, SO 45K, ROT 47K;Wash down 260 gpm, 1585 psi, tag cement stringer @ 1406', continue to wash tagging plug at 1416' on depth, drill cement and FE
f/ 1416' to 1499' at 40 rpm, 3-4k torque, 2-3k wob, cleanup rathole to 1504';Drill 20' new formation f/ 1504' to 1524', 260 gpm, 1540 psi, 40 rpm, 2.5k torque, 6-
7k wob. 30u max gas.;Pump 20 bbl spacer, displace to new 8.9 ppg, 6% KCL PHPA mud, 253 gpm, 1000 psi, 40 rpm, working pipe, condition mud until good
8.9 ppg in/out. Rack back stand and park in 7 5/8 casing @ 1483';RU test equipment, close UPR, purge lines, Perform LOT, with 8.9 ppg existing MW, using
test pump apply 700 psi down DP and Ann, leveled at 650 psi @ 17.6 ppg EMW, bleed off press, open UPR. RD test equip.
6.9 gallons pumped, 6.3 gallons bled back.
AOGCC rep M. Herrera witnessed test.;M/U stand DP, wash to bottom, Drill 6 3/4'' hole F/1524'-T/1932'. loaded HI-Vis sweep w/ walnut & condet into the pipe
after 30' slide, rotated our remaining 30' of std. while pumping sweep around, sweep came back 8 bbls late w/ a 10% increase in cuttings. P/U-58K S/O-45K
ROT- 53K GPM-300;SPP-1560 psi Diff-200 psi RPM-70 TQ-3.4K WOB-9K Max gas 16 units ECD-9.8 ppg Flow out 25%.;Cont. directional drilling 6-3/4" hole
F/1932'-T/2012'. P/U-57K S/O-46K ROT- 52K GPM-300 SPP-1600 psi Diff-170 psi RPM-80 TQ-3.4K WOB-9K Max gas 65 units ECD-9.9 ppg Flow out
25%.;Held PTSM, crew change. Cont. directional drilling 6-3/4" hole F/2012' to wiper trip depth at 2534'. P/U-58K S/O-46K ROT- 52K GPM-300 SPP-1650 psi
Diff-200 psi RPM-80 TQ-3.6K WOB-9K Max gas 128 units ECD-9.9 ppg Flow out 25%. Got SPR's on pumps @ 2040'.;Circ. till hole cleaned up. GPM-300 SPP-
1500 psi RPM-60. Flow check (static).;POOH on elevators F/2535' to current depth 2349'. Distance to well plan: 4.02' 2.63' Low 3.04' Left;Hauled 34
bbls of solids to KGF G&I
Cumulative: 244 bbls
Hauled 317 bbls of fluid to KGF G&I
Cumulative: 1104 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
7/16/2021 Continue with wiper trip, POOH on elevators F/2349' to 1485' parking inside 7 5/8'' casing. No issues
Correct displacement;Service the TD, blocks, crown, draworks, brake linkage and driveshaft, adjust the bale clamps;TIH on elevators F/ 1485' to 2508' M/U TD,
fill pipe, wash to bottom at 2534', survey, load 20 bbl hi vis sweep w/ walnut marker in DP;Directional drill 6-3/4" hole F/2534'-T/2937'. P/U-66K S/O-58K ROT-
56K GPM-300 SPP-1700 psi Diff-200 psi RPM-80 TQ-3.8K WOB-8K Max gas 144 units ECD-10.5 ppg Flow out 25.8%.
Sweep back 7 bbls early w/ 25% increase, mostly clay, sand and some coal.
Hold 56.8 deg tangent;Crew change, PTM, Directional drill 6-3/4" hole F/2937'-T/3585'
GPM-300, SPP-1900 psi Diff-250 psi RPM-80 TQ-5.2K WOB-6-9K
MW 9.15 ppg, vis 56, ECD-10.8 ppg. Flow out 25%. Max gas 119u
PU-75K/ SO-50K/ ROT- 59K
Hold 56.8 deg tangent;Circ. hole clean, obtained SPR's, flow check (static). Off line brought out 192 jts of 4.5" 12.6 ppf DW C-HT L-80 liner along w/ 2 additional
jts. w/ RA markers.;POOH on elevators F/3585'-T/2475' w/ no issues, had calculated hole fill for the trip out. P/U-80K S/O-54K .;RIH on elevators F/2475'-
T/3585' w/ no issues, had calculated pipe displacement for the trip in. Washed last std to bottom, no fill on bottom. P/U-80K S/O-54K . Off line racked,
strapped, and tallied our 4.5" liner.;Pumped 20 bbl HI-Vis sweep w/ walnut & condet, sweep came back 4 bbls late w/ a 10% increase in cuttings. Cont.
directional drilling 6-3/4" hole F/3585-T/3833'. PU-70K/ SO-50K/ ROT- 61K GPM-300, SPP-1950 psi Diff-290 psi RPM-80 TQ-5.3K WOB-6-9K ECD-10.8 ppg.
Flow out 25%. Max gas 144 units.;Held PTSM, crew change. Cont. directional drilling 6-3/4" hole F/3833'-T/4140'. PU-81K/ SO-53K/ ROT- 64K GPM-285, SPP-
1900 psi Diff-300 psi RPM-80 TQ-6.3K WOB-7-8K ECD-10.9 ppg. Flow out 25%. Max gas 150 units. Started our initial drop of 4 degree per 100 at 4140'.;Cont.
directional drilling 6-3/4" hole F/4140' to current depth of 4382'. PU-84K/ SO-52K/ ROT- 64K GPM-290, SPP-1988 psi Diff-300 psi RPM-80 TQ-6.3K WOB-7-8K
ECD-11.3 ppg. Flow out 25%. Max gas 117 units. Distance to well plan: 7.22' 3.56' Low 6.28' Left.;Hauled 112 bbls of solids to KGF G&I
Cumulative: 355 bbls
Hauled 222 bbls of fluid to KGF G&I
Cumulative: 1325 bbls
Hauled 0 bbls of cement G&I
Cumulative: 18 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
drill cement and FE
f/ 1416' to 1499' at 40 rpm,
Drill 6 3/4'' hole F/1524'-T/1932'
gpp
with 8.9 ppg existing MW, using pg@qp
test pump apply 700 psi down DP and Ann, leveled at 650 psi @ 17.6 ppg EMW,
pq
condition mud until good g
8.9 ppg in/out. ppg
pg g@ ggg
cleanup rathole to 1504';Drill 20' new formation f/ 1504' to 1524',
yy
Directional drill 6-3/4" hole F/2937'-T/3585'
pp
directional drilling 6-3/4" hole F/4140' to current depth of 4382'
6.9 gallons pumped, 6.3 gallons bled back.
ppppy p
Finish testing 7 5/8'' casing to 3000 psi for 30 charted min, good test.
jp
;Directional drill 6-3/4" hole F/2534'-T/2937'
ygypp
On the south side of the pad, we wired 4x8 sheets of plywood to the fence to create a sound dampening barrier. Due to the fact we had noisep
complaints.;
AOGCC Jim Regg waived test witness via phone call @ 10:30
7/17/2021 Cont. directional drilling 6-3/4" hole F/4382' to 4572'. PU-93K/ SO-54K/ ROT- 68K, GPM-285, SPP-2100 psi Diff-300 psi RPM-80 TQ-6.9K, WOB-8K ECD-
11.3 ppg. Flow out 25%. Max gas 81 units
Continue to drop 4 deg/100';Circulate the hole clean @ 2 BU, 290 gpm, 1750 psi, 70 rpm, 4-5k tq working pipe, survey, record SPRs, flowcheck the well,
static;Wiper to shoe, POOH on elevators F/ 4572' to 2166', work thru tight spots at 3945', 3805', 3633' to 3585', 3585' and 3378', seeing 10-20k over pulls, work
thru each several times cleaning up same,;MU TD, pulling slow CBU X2 at base of tangent F/ 2166' to 2041', seeing 10% increase at the shakers, pull on
elevators to 1486' parking in 7 5/8'' casing
1.9 bbls over calc displacement tripping to shoe;Service top drive, blocks and draworks, inspect brake linkage.;Drift and singl e in with 60 joints of 4 1/2'' drill pipe
F/ 1486' to 3342', TIH on elevators with stands 4 1/2'' DP to 4515' seeing some slight bobbles at previous tight spots, MU TD, wash last stand to bottom @
4572', no fill.
1.5 bbls over calculated displacement on TIH
PU 94K, SO 47K;Cont. directional drilling 6-3/4" hole F/4572' -T/5132'. PU-107K/ SO-59K/ ROT- 76K, GPM-285, SPP-2040 psi Diff-275 psi RPM-80 TQ-7.6K,
WOB-6.9K ECD-10.8 ppg. Flow out 25%. Max gas 125 units
Start 2 deg/100' at 4575', Pump 20 bbl hi vis sweep @ 4586', back 7 bbls early, 25% increase.;Held PTSM, crew change. Cont. directional drilling 6-3/4" hole
F/5132' -T/5390'. PU-117K/ SO-61K/ ROT- 80K, GPM-285, SPP-2100 psi Diff-300 psi RPM-80 TQ-8.2K, WOB-8K ECD-10.9 ppg. Flow out 25%. Max gas 113
units. Cont. w/ our 2 degree drop per 100' till 6,066'.;Cont. directional drilling 6-3/4" hole F/5132' to wiper trip depth of 5564'. PU-122K/ SO-64K/ ROT- 83K,
GPM-285, SPP-2125 psi Diff-300 psi RPM-80 TQ-9.2K, WOB-8K ECD-10.9 ppg. Flow out 25%. Max gas 113 units;CBU X2 GPM-285 SPP-1825 psi RPM-80.
Got SPR's. Flow checking well at report time. Distance to well plan: 8.83' 8.47' Low 2.50' Left;Hauled 135 bbls of solids to KGF G&I
Cumulative: 490 bbls
Hauled 220 bbls of fluid to KGF G&I
Cumulative: 1545 bbls
Hauled 0 bbls of cement G&I
Cumulative: 18 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
7/18/2021 Flow checking well, static, pull wiper trip, POOH on elevators racking stands in the derrick f/ 5564' to 4512', seen 15k overpull at 5112', work thru cleaning up
same, no other issues
.9 bbls over calculated displacement;Inspect and service TD, blocks, crown, draworks, brake linkage and driveshaft;TIH on elevators f/ 4512' to 5504', 8k set
down at 5074', work thru 1 time with no issues, MU TD, wash to bttm @ 5564', no fill
Correct displacement on TIH;Cont. directional drilling 6-3/4" hole F/5564' -T/5874'. PU-130K/ SO-67K/ ROT- 87K, GPM-285, SPP-2050 psi Diff-300 psi RPM-80
TQ-9.7K, WOB-8K ECD-10.86 ppg. Flow out 25%. Max gas 128 units
Pump 20 bbl hi vis sweep @ 5586', back on time, 25% increase mostly clay
Continue to drop 2 deg/100';Crew change, PTM. Cont. directional drilling 6-3/4" hole F/5874' -T/6550'. PU-154K/ SO-71K/ ROT- 101K, GPM-285, SPP-2150 psi
Diff-250 psi RPM-80 TQ-11.1K, WOB-6-8K ECD-10.7 ppg. Flow out 25%. Max gas 172 units @ 6270' (sand).
Cont. 2 deg/100' to 6066', then hold 10 deg;At approximately 18:00 hrs. We had the day Toolpusher and the pit watcher go to South Peninsula Hospital due high
fevers. Both hands were tested for COVID and came back positive. Hilcorp safety Rep Jacob Nordwall and drilling engineer Frank Roach were notified.;CBU x2
to clean up hole, shot survey on bottom, got SPR's, flow check (static). GPM-285 SPP-1880 psi RPM-80 TQ-11.1K;POOH on elevators F/6550'-T/5504' w/ no
issues, had calculated hole fill for the trip. P/U-165K S/O-79K;Turned right around and RIH on elevators F/5504'-T/6367', set down 10K @ 6340', worked
through on elevators. P/U-155K S/O-73K;Held PTSM outside on the pad, crew change. Cont. RIH on elevators F/6367'-T/6491', washed last std to bottom @
6550', seen 10K set down @ 6543', washed right through it. Pumped 20 Hi-Vis sweep w/ walnut & condet, sweep came back 2 bbls late, w/ a 25% increase in
cuttings.;Cont. directional drilling 6-3/4" hole F/6550' -T/6983'. PU-167K/ SO-76K/ ROT- 105K, GPM-285, SPP-2300 psi Diff-300 psi RPM-80 TQ-12K, WOB-7-
9K ECD-10.7 ppg. Flow out 25%. Max gas 190 units. Holding 10% till TD. Distance to plan: 6.72' 6.72' Low .12' Left.;Hauled 180 bbls of solids to KGF G&I
Cumulative: 670 bbls
Hauled 180 bbls of fluid to KGF G&I
Cumulative: 1725 bbls
Hauled 0 bbls of cement G&I
Cumulative: 18 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
7/19/2021 Cont. directional drilling 6-3/4" hole F/6983' -T/7480'. PU-183K/ SO-79K/ ROT- 108K, GPM-285, SPP-2400 psi Diff-350 psi RPM-80 TQ-12.9K, WOB-7-9K
ECD-10.7 ppg. Flow out 25%. Max gas 166u. Holding 10% till TD
submit 24 hr BOP test notification to AOGCC;PTM with oncoming crew. Cont. directional drilling 6-3/4" hole F/7480' -T/7749' at TD, TVD 6230'. PU-183K/ SO-
79K/ ROT- 108K, GPM-285, SPP-2400 psi Diff-350 psi RPM-80 TQ-12.9K, WOB-7-9K ECD-10.7 ppg. Flow out 25%. Max gas 259u. Holding 10% to TD;Pump
20 bbl hi vis swee4p around with nut plug marker, circulate the hole clean, 285 gpm, 2050 psi, 80 rpm, 13 k tq, sweep back on time with 10% increase, flow
check the well, static.
Final survey: MD 7712.50 / INC 10.82 / AZI 186.23 / TVD 6194.29;POOH on elevators F/7749'-T/1486', worked through multiple tight spots w/ 10-20K over pull.
Had calculated hole fill for the tip. PU-205K SO-88K AOGCC Rep Brian Bixby waived witness for upcoming BOP test.;Serviced rig. Greased crown, blocks,
TDS, wash pipe, IR, DWRK, brake linkage, and drive shaft.;RIH on elevators F/1486'-T/3651'. Filling pipe every 2000'. PU-77K SO-45K;Crew change. Cont.
RIH on elevators F/3651'-T/7749'. Had to wash through 3 set downs @ 5398', 7763, and 7685'. Washed last std. to bottom w/ no fill. Had calculated pipe
displacement for the trip. PU-203K SO-88K GPM-225 SPP-1200 psi.;Pumped 20 bbl Hi-Vis sweep w/ walnut & condet, sweep came back on time w/ no
increase in cuttings. Got SPR's, Flow checked well (static). GPM-285 SPP-2050 psi RPM-80 Max gas 202 units at BU.;POOH on elevators F/7749' to current
depth of 5933'. PU-145K SO-72K Distance to well plan: 38.39' 5.53' High 37.99 Left.;Hauled 77 bbls of solids to KGF G&I
Cumulative: 747 bbls
Hauled 194 bbls of fluid to KGF G&I
Cumulative: 1919 bbls
Hauled 0 bbls of cement G&I
Cumulative: 18 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
directional drilling 6-3/4" hole F/4382' to 4572'
@gg
directional drilling 6-3/4" hole F/6550' -T/6983'.
TVD 6230'.
@
;Cont. directional drilling 6-3/4" hole F/5564' -T/5874'.
pp
directional drilling 6-3/4" hole F/5132' to wiper trip depth of 5564'
at TD, T directional drilling 6-3/4" hole F/7480' -T/7749'
p
directional drilling 6-3/4" hole F/4572' -T/5132'
ggppy
Both hands were tested for COVID and came back positive.
directional drilling 6-3/4" hole F/6983' -T/7480'
7/20/2021 Continue TOOH on elevators from 5933' to 740' at the HWDP, no issues, flow check the well, static, rack back HW, jars and flex collars.
Correct displacement TOOH.;PJSM, remove sources as per HES rep, clean ports, download data, L/D remaining BHA, directional tools, mud motor and bit, 6
3/4'' bit grade= 1-1-CT-G-X-I-NO-TD;Clean and clear the rig floor, pull the wear bushing R/U to test BOPE, flood lines and purge air from system
AOGCC Rep Brian Bixby waived test witness @ 15:28 on 7-19-20 via phone call.;Test BOPS w/ 4.5'' test jt t/ 250/3500 psi as per state regulations, test CMV 1-
15 TIW and Dart, Auto and Man choke and Kill, Auto and Man IBOP, Upper lower and Blind rams, Kill line 4'', Man and Super Choke, perform Accumulator Draw
down test, Annular had 1 FP on inside kill line man, replaced;valve and retested good.;R/D test equipment, pull test plug and set wear ring.;R/U Haliburton Eline,
Hang Sheave and R/U equipment P/U Dipole sonic and bore hole imager tool string RIH t/ 2448' losing down weight, work tools for approximately an hour with
no progress tools picking up clean no over pull, decision made to pull out of the hole;R/D Eline, R/U t/ make clean out Assembly
7/21/2021 Clear rig floor, M/U cleanout BHA, 6 3/4'' RR HDBS bit, bit sub w/ flt, 6 5/8'' IB stab, 2-NMFCs, XO, 6 HWDP, XO, Jar, XO, 11 HWDP to 628.97'
Quadco tested Rig gas alarms at 06:30 this morning.;TIH on elevators w/ stds 4 1/2'' DP to 7121', no issues passing thru 2488', had 10-15k set downs at 3622',
3700', 4450', 4510' and 4995', work thru easily with 1 pass, fill DP @ 2500' then every 2000';PTM, crew change, RIH f/ 7121', tag at 7720' with 10k set down,
wash and ream f/ 7720 to 7749' @ TD.
Correct displacement on TIH;Pump 20 bbl hi vis sweep around with nut plug marker, 246 gpm, 961 psi, 30 rpm, 12-13k tq, working the pipe 20', at BU seen 25%
increase in coal at shakers, sweep back 14 bbls late w/ 10% increase. Add 2% NXS lube in open hole, flow check well, static.
PU 205K, SO 83K, ROT 124K;TOOH f/ 7749' t/ Surface L/D Clean out BHA, clean and clear rig floor;R/U Halliburton Eline RIH w/ diploe sonic tools, set down @
2328' work string down t/ 2440' decision made t/ POOH, L/D Sonic Tool, RIH w/ imaging tool string only t/ 7737' WLM Begin logging out of the hole @
6590';Cumulative: 789 bbls
Hauled 68 bbls of fluid to KGF G&I
Cumulative: 2154 bbls
Hauled 0 bbls of cement G&I
Cumulative: 18 bbls
Daily Metal: 0 lbs
Cumulative: 0 lbs
7/22/2021 With E-line continue logging out of the hole with the imaging tool string from 6590' to the shoe @ 20-25 fpm, POOH, L/D imaging tools;M/U diploe sonic tools
with standoff removed-replaced with load spring centralizers and cabbage head, RIH to 7730' WLM, log out of hole at 28 fpm to the casing shoe, POOH L/D
tools.;M/U sidewall coring tools, RIH unable to work past 2280', POOH getting 6 side wall coring samples from stations, POOH R/D Eline clear tolls and
equipment f/ floor;M/U clean out Assembly RIH t/ 1490';Slip and cut drilling line 107' Service draworks;RIH f/ 1490' to 7749' seen one set down @ 7720' hole had
correct displacement;Circulate Hi Vis Sweep w/ walnut around bottoms up gas was 152 max units, bottoms up 20% increase in cuttings, circulating sweep to
surface building dry job
7/23/2021 Continue to circulate hi vis sweep around, sweep back 21 bbls late with 10% increase, shakers cleaned up, flow check the well, static, pump dry job, drop 2.46"
OD drift on wire,;POOH with cleanout assy on elevators racking 22 stands 4 1/2'' DP f/ 7749' to 6379', no issues;Continue to POOH on elevators L/D singles 4
1/2'' DP f/ 6379' to 628', flow check the well, static. L/D jars, rack back 9 stds HWDP, recover drift, L/D remaining BHA,
3.4 bbls over calculated hole fill on TOOH.;Clean and clear the rig floor. R/U 4 1/2'' casing handling tools, power tongs, set top drive torque to 6500 ft/lbs, load
casing on pipe racks, Hold PJSM for running casing.;Ensure no debris with flashlight, Baker lock and M/U 4 1/2'' shoe track assy to 124', ensure float operation,
good.;P/U and RIH with 4 1/2'' DWC/C-HT, 12.6# L-80 casing as per tally, TQ to 6500 ft/lbs, RIH to 1472' just above casing shoe.
Fill on the fly and top off every 10 jts, install 1 centralizer free floating on ea. joint;R/U and Circulate 2 BU, obtain parameters, 207 gpm, 80 psi, 30 rpm, 1.1k
torque, PU 30K, SO 30K, ROT 32K;Continue to run 4 1/2'' casing as per tally from 1472' to 6457' at joint #152, ( 152 centralizers ran )
Correct displacement at this point running casing;C/O to 3 1/2'' handling equipment, PU 4.5" x 5.5'' x 7.625" HRD-E ZXP LTP w/ flex lock hanger assy as per
BOT rep
7/24/2021 Verify pipe count ( 40 remain on rack )Continue to PU LTP assy as per BOT rep, verify 5 pins ea in flex lock liner hanger, shear set @ 2188 psi, 7 pins ea. in
ZXP LTP set at 50k shear, 10- 7/16'' pins ea. in pusher tool, set pressure 2594 psi, fill tie back extension w/ Xanplex down to RS pickoff;C/O rotary slip dies to
accommodate the 3 1/2'' lift pup on top of running tool, MU drifted stand 4 1/2'' HWDP, MU TD, pump 1 liner volume 70 spm, 330 psi, good flow, record
parameters.
PU 93K, SO 57K, Attempt to rotate with torque limit set at 6200 ft/lbs, unable to rotate- release torque gently;TIH with 4 1/2'' casing conveyed on 8 drifted stands
4 1/2'' HWDP then 12 stands of drifted 4 1/2'' DP to 7749' stage to 220 gpm, 550 psi, wash the last stand to bottom, no fill, 220 gpm, no fill, set down 5k seeing
pressure increase to verify tag.
Calculated displacement RIH on DP;Circulate and condition for cement job, work pipe, Circulate 2 BU, 220 gpm, 500 psi working pipe slow, unable to rotate. PU
122K, SO 73K with pumps on. lower YP to 17, MW 9.4, tag with pumps off @ 7753', space out length 14.2'
Spot and RU cementers.;Crew change. finish RU cemeters. Shut down pump, L/D jt HWDP and pup joint, space out with 10' and 15' pup, XO, cement head and
5' pup, M/U TD,
PJSM with HES cement crew, drilling crew, RU cement hose, secure same.;Line up cmtrs, pump 5 bbls water, test lines to 1000 psi low / 4600 psi high, Mix and
pump 20 bbl, 10.5 ppg spacer 5 bpm, 400 psi, (6.86( 38.543 gal bbl ) 19 bbls mix water, Yield ft/sk 1.27 ) followed with 212 bbls, 12 ppg lead cement, 4 bpm,
120 psi.;( 505sx, 170 bbls mix water, yield ft/sk 2.394 ) followed with 19 bbls 15.3 ppg tail cement 4.5 bpm, 130 psi, ( 100 sx, 14 bbls mix water, yeild ft/sk 1.239,
water 5.577 gal sk ), pump 10 bbls water, Drop DP dart, displace with 9.4 ppg mud 5bpm, 500 psi, slowing to 2 bpm after;5 bbls away, dart latched LWP at 14.5
bbls, Pipe started getting sticky on down stroke, park in tension at 7744', PU 137K, SO 80K, displace 5 bpm, 1200 psi slowing to 2 bpm on last 20 bbls, FCP
1250 psi, plug bumped 600 psi over FCP and latched at 111.5 bbl at calculated, CIP @ 16:10;90 bbls away dump spacer returns to cuttings box,;Stage pressure
to 2400 psi, set hanger, S/O to block wt, stage to 2700 psi, saw pusher tool activate at 2635 psi, stage to 3200 psi then 3600 psi, saw pusher tool neutralize at
3540 psi, held a 4000 psi f/ 1 min, bled off pressure, floats held. PU to verify release at 50k PU;Line up to pump with rig, 74 spm, 160 psi, 870 stks start seeing
clean mud at surface, R/D cement head, and cementers, drop wiper ball, pump 5 bbl rack stand, continue to circulate
20 bbls of spacer and 37.5 bbls cement returned to surface
No losses throughout entire job;Cont to circulate at a reduced rate through Baker liner run tool, 208 gpm-84 psi. Start sanitizing throughout the rig due to a good
amount of rig personnel feeling ill.;Cont to circulate at a reduced rate through Baker liner run tool, 208 gpm-84 psi. Cont sanitizing throughout the rig, prep to
send hands in for covid testing.
7/25/2021 Ship out excess drilling mud for disposal, cont circulating at reduced rate. Cont sanitizing throughout the rig and office trailers. Start sending personnel to Homer
for Covid testing.;Cont sanitizing throughout the rig and office trailers. Cont sending personnel to Homer for Covid testing.;W ork on PM's, sanitizing and
circulating.;Work on PM's, sanitizing and circulating.
p
;M/U sidewall coring tools, RIH
g p
RIH w/ imaging tool string only t/ 7737' WLM Begin logging out of the hole @
6590';C
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RIH with 4 1/2'' DWC/C-HT, 12.6# L-80 casing as per tally,
Cont sanitizing throughout the rig, prep to
send hands in for covid testing.
ppp
continue to circulate
20 bbls of spacer and 37.5 bbls cement returned to surface
;Line up cmtrs, pump 5 bbls water, test lines to 1000 psi low / 4600 psi high, Mix and gpppppg
pump 20 bbl, 10.5 ppg spacer 5 bpm, 400 psi, (6.86( 38.543 gal bbl ) 19 bbls mix water, Yield ft/sk 1.27 ) followed with 212 bbls, 12 ppg lead cement, 4 bpm,p p ppg p p p ( ( g ) )ppg p
120 psi.;( 505sx, 170 bbls mix water, yield ft/sk 2.394 ) followed with 19 bbls 15.3 ppg tail cement 4.5 bpm, 130 psi, ( 100 sx, 14 bbls mix water, yeild ft/sk 1.239, p(
water 5.577 gal sk ), p
gg y p
plug bumped 600 psi over FCP and latched at 111.5 bbl at calculated,
PU 4.5" x 5.5'' x 7.625" HRD-E ZXP LTP w/ flex lock hanger assy
pg
/U Dipole sonic and bore hole imager tool string
gg
POOH getting 6 side wall coring samples from stations,
;Test BOPS w/ 4.5'' test jt t/ 250/3500 psi as per state regulations,
No losses throughout entire job;C
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Start sanitizing throughout the rig due to a goodgg g g
amount of rig personnel feeling ill.;gp g
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gj p gp
run 4 1/2'' casing as per tally from 1472' to 6457' at joint #152, ( 152 centralizers ran )j()
Cont sanitizing throughout the rig and office trailers. Start sending personnel to Homer pgpg ggg
for Covid testing.;Cont sanitizing throughout the rig and office trailers. Cont sending personnel to Homer for Covid testing.;W
7/26/2021 Cont circulating through Baker's liner run tool at 1208'. Cleaned pit's 9 and 10, brought in water and built 250 bbls brine. Cont cleaning pits 1-2-3 and 8.;Finished
up pit cleaning of 1-2-3 and 8. Called out Baker Rep, prep to POOH.;POOH from 1208' to 535', swap elevators, cont POOH LD 16 jnts HWDP. CCI vac'd wiper
balls through joints on pipe rack. Inspected and LD Baker run tool. MU wash tool and RIH one stand HWDP from derrick. LD two singles and recovered hollow
drift from jnt HWDP.;PU Baker cement head and broke off XO's and pup joints, LD same.;PU Baker polish mill, MU XO, TIH from 22' to 1231', MU topdrive and
broke circ at 136 gpm-34 psi, obtained rotating parameters: 20 rpm=1175 ft/lbs, 30 rpm=1600 ft/lbs.;Eased down at 20 rpm-1175 ft/lbs, 137 gpm-24 psi, saw
pump pressure increase to 40 psi as polish mill entered liner top at 1249', tagged up on no go with end of mill at 1262', torque increased to 1616 ft/lbs, pump
pressure at 90 psi. PU 3', rotated 30 rpm-1315 ft/lbs, S/O and set down 5K, torque at;2600 to 3100 ft/lbs as per Baker Rep. PU 3' and increased pump rate to
231 gpm-79 psi, no rotary and CBU one time. Had a slight show of cement at bottoms up. Shut down pump.;POOH from 1262' to surface. Inspected and LD
Baker polish mill assembly and XO. Had very good indication of contact with liner top.;RU test equipment, flooded test hose, choke manifold and choke line to
BOP stack. Pumped 69 gallons to achieve 3000 psi on 7 5/8" x 4.5" casing and liner. Held 30 minutes on chart, good test. Bled off 69 gallons. RD test
equipment.;Load 2 7/8" workstring on drillers side pipe racks;Cont loading 2 7/8" workstring on drillers side pipe racks, stage d 4 1/2" and 2 7/8" test joints on
catwalk, staged scrapers and XO's on catwalk, loaded 2 7/8" workstring on offside pipe racks. Tallied pipe and jewelry, obtained OD/ID's. Cont sanitizing
throughout the rig.
7/27/2021 Finished strapping 215 jnts 2 7/8" workstring, drained BOP stack and removed wear ring.;Replaced sealing rubber on test plug then set same with 4 1/2" test
joint. MU TIW and dart on test joint, flooded surface lines and choke manifold, installed test sub on topdrive and flooded same. Purged all air and shell tested
stack. Witness waived by AOGCC Rep Jim Regg at 09:24 am.;Tested all BOPE at 250 low, 3500 high for 5 min each. Tested with both 4 1/2" and 2 7/8" test
joints. Quadco rep on location at 10:30 am and tested all audio/visual gas alarms with no issue. Had one F/P on outside mezz kill valve. Replaced valve and re-
tested OK. Called out Weatherford Rep.;RD test equipment, installed wear ring and closed annulus valve. Lined up stack and choke manifold for drilling.;RU
Weatherford tongs and Yellow Jacket handling equipment. Staged Yellow Jacket scraper assemblies and XO's.;MU 3 3/4" tri-cone, bit sub, 4.5" scraper
assembly, PU and singled in hole with 211 jnts 2 7/8" PH-6 pipe, drifting as we picked up, using the white pipe dope on PH-6 threads, torqued to 4000 ft/lbs. No
issue entering 4.5" liner top at 1249'. At 6450' RD Weatherford, swapped handling equipment;PU single jnt 4 1/2" DP, MU XO's and 7 5/8" scraper, XO to CDS-
40 DP. TIH out of derrick 19 stands to 7606' and MU topdrive. Aired out pump then filled pipe.;At 45 spm-1066 psi, S/O with no rotary and tagged bottom (top of
landing collar/wiper plug) at 7661' twice. PU 5' and parked bit at 7656'. CBU at 73 spm-180 gpm-1449 psi.
7/28/2021 Pulled up hole from 7656' to upper scraper at 6511' on elevators, up wt 85K. TIH from 6511' to 7658' and parked string.;MU topdrive and broke circ at 47 spm-
111 gpm-1386 psi. Cleaned out trip tank, cleaned up rig floor and drip pan area. Held PJSM with rig crew, mud man and CCI Supervisor on displacement to
brine.;Pumped 22 bbls Hi-Vis spacer using pump 1, then swapped to pump 2 and chased with 185 bbls inhibited brine, reciprocated pipe with no rotation.
Removed shaker screens and washed up tubs and possum bellies while displacing. Took all returns to cuttings box. Pumped 64 extra bbls once brine;back to
surface then shut down. Transferred clean brine into trip tank and flushed fill up line into cellar box. Staged thread protectors for 4 1/2" DP and vac truck to vac
wiper balls on pipe rack. Up wt 87K, dwn wt 44K with brine in hole.;POOH LD 39 jnts CDS-40 DP, RIH 3 stands from derrick and LD same to 6452'., LD 7 5/8"
scraper assembly, swapped handling equipment, RU Weatherford tongs, cont POOH LD 2 7/8" workstring from 6452' to surface and LD 4 1/2" scraper
assembly.;PU test joint and removed wear ring, stage 4 1/2" tubing, seal assembly and SSSV. CO handling equipment, crew change (fresh crew on tour-short 3
hands due to positive covid tests).;PU Baker 5.75" bullet seal assembly, PU and single in hole with 4 1/2" 12.6# L-80 DWC/C-HT tubing, torqued at 6150 ft/lbs to
758', MU Baker SSSV, offload Pollard control line spool and stand, staged on rig floor. Fixed control line to SSSV and pressured up to 5000 psi, cont PU single
in hole slow;a total of 29 jnts as per run tally to 1225'. PU jnt #30, S/O and tagged no-go 32' in. Need 2' pup for space out. LD jnt #30, MU IBT XO pup jnt on
hanger pup, then 2' space out pup, MU landing jnt/hanger on stump. Wellhead Rep terminated control line through hanger. Pollard Rep pressured up control;line
to 3000 psi and isolated with needle valve to hold SSSV open. Drained stack leaving annulus valve open, pulled bushings, S/O and landed hanger, up wt 29K,
dwn wt 29K. Ran a total of 15 SS bands on control line.;Wellhead Rep RILD's, removed landing joint, flooded BOP stack and choke manifold, RU test
equipment.;Closed blinds, lined up on choke manifold and choke line with test pump, opened annulus, pumped 46 gallons down through hanger to test 4 1/2"
tieback tubing and liner at 2500 psi for 30 min on chart. Pressure dropped 4 psi over 30 minutes. Good test.
7/29/2021 Bled off 46 gallons from 4.5" tieback tubing/liner, RU test pump on 7 5/8" x 4 1/2" annulus, opened blinds to allow tubing to atmosphere, pumped 19 gallons
down annulus to achieve 2500 psi and held on chart for 30 minutes. Pressure dropped 5 psi over 30 minutes. Good test. Bled back 20 gallons, RD;test
equipment, Wellhead Rep installed 2 way check in tubing hanger. Witness of MIT-T and MIT-IA was waived by AOGCC Rep Jim Regg at 09:49 on 7-29-
21.;Flushed all surface lines, topdrive, mud pumps, BOP stack, choke manifold and blew everything down. CCI tore out Sperry and GeoLog shacks, tore out
upright water tank and shipped those to Whiskey Gulch pad.;Removed flow riser, flowline, drip pan and installed trolly beam in cellar. Bled off koomey unit,
opened, cleaned, inspected, greased and buttoned up all ram doors on stack. Secured bridge cranes to lift plate, broke flange bolts, hoisted stack and moved to
cellar entrance. Removed 2' spacer spool;from wellhead, staged dry hole tree at cellar entrance, RU and worked tree into cellar, stabbed same on wellhead.
Wellhead Rep terminated control line through tree and applied 3400 psi to keep SSSV open. Tested hanger void, tested tree at 500 low, 5000 high for 5 min
each. Removed 2 way check and;installed tree cap. CCI cont loading assorted equipment on trailers and transported to Whisky pad. Released rig at 18:00
hrs on 7-29-21;Removed rig tongs, RD pits and pumps, RD removed torque bushing from torque tube, staged stand on rig floor and RD topdrive. RD and lay
over poorboy degasser, removed vent line. Removed topdrive from rig floor.;Removed "T" bar form torque tube, removed stand pipe manifold, bridled up on
blocks, inspected derrick, scoped down upper mast section, LD lower torque tube section, unspooled drill line from drum and cut 42', secured drill line, kelly
hose, service loop, geronimo line, tong lines and weight bucket;to derrick for move. RD gen 3, RD topdrive HPU and aux fuel tank, lay over beaver slide.
ygqpg(
single in hole with 4 1/2" 12.6# L-80 DWC/C-HT tubing,
yyg pqp
Pumped 69 gallons to achieve 3000 psi on 7 5/8" x 4.5" casing and liner. Held 30 minutes on chart, good test. Bled off 69 gallons.
Witness of MIT-T and MIT-IA was waived by AOGCC Rep Jim Regg at
pgj
equipment.;Closed blinds, lined up on choke manifold and choke line with test pump, opened annulus, pumped 46 gallons down through hanger to test 4 1/2" qp p p p p p p
tieback tubing and liner at 2500 psi for 30 min on chart. Pressure dropped 4 psi over 30 minutes. Good test.
pumped 19 gallonsggpppg
down annulus to achieve 2500 psi and held on chart for 30 minutes. Pressure dropped 5 psi over 30 minutes. Good test. pp p
q
Fixed control line to SSSV and pressured up to 5000 psi,
g
jp
Witness waived by AOGCC Rep Jim Regg at 09:24 am.;Tested all BOPE at 250 low, 3500 high for 5 min each.
gp
Bled back 20 gallons,g
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Activity Date Ops Summary
8/2/2021 Yellowjacket RIH W/ 2 3/4" SCBL TAGGED BOTTOM @7655' LOGGED UP TO 1200'. RDMO to SV-08
8/4/2021 PTW, JSA with Petrospec, Cruz. SIMOPS with yellow jacket E-line working on SV-8.,Spot in coil equipment and spot aux. equipment. RIg up petrospec.,24 hr
BOPE test witness notification sent 8/3/21 @ 0930. Witness waived by Jim Regg via email on 8/3/21 @0942 hrs. Start BOPE test. test all rams and valves
250/3500 psi. Shut down awaiting sundry approval.
8/5/2021 PTW, JSA with crew.,Pick injector head and install 1.75" DFCV, jet nozzle.,Stab on well. PT stack 250/3500 psi. Open master and swab 23.5 turns. RIH Start
cooling down N2. Tag 7691' CTMD. Blow N2 and recovered 114 bbls of water. POOH with coil Close choke and pressure up well bore to 2500 psi.,Rig down
Petrospec CTU.
8/10/2021 RIH W/ 11' X 2 7/8" 6SPF HSC.
BLED WELL DOWN FROM 2300PSI TO 1400PSI. Town confirmed tie-in (no shift)
PERF THE LOWER T-65 SAND @ 6265'-6276'
Initial WHP was 1402psi.
5/10/15 pressures: 1406/1404/1407psi
GUN WAS DRY, all shots fired
8/12/2021 07:30-RIH W/ 11' X 3 3/8" 6SPF HSC BLED WELL TO 100PSI SHOT LOWER T-65 SAND @ 6265'-6276' / GUN WAS DRY
10:30-RIH W/ 23' X 2 7/8" 6SPF HSC SHOT BOTTOM OF UPPER T-65 ZONE @ 6184-6207 / GUN WAS DRY WITH A LITTLE SAND
12:30- 20' X 2 7/8" 6SPF HSC SHOT TOP OF THE UPPER T-65 ZONE @ 6164'-6184' / GUN WAS DRY WITH SAND ON THE WHOLE GUN
8/13/2021 RIH W/ GR-CCL & 7' X 2 7/8" 6SPF HSC PERF. THE T-47 SAND @ 5568-5575 GUN WAS DRY
RIH W/ GR-CCL 7 20' X 2 7/8" 6SPF HSC PERF. THE T-40 SAND @ 5392-5412 GUN WAS DRY
RIH W/ GPT & 27' X 2 7/8" 6SPF HSC / FLUID LEVEL @ 6520' PERF. THE T-30 SAND @ 5105-5132 GUN WAS DRY
RIH W/ GR-CCL & 3.5" CIBP SET @ 5090'
RIH W/ GR-CCL & 26' X 2 7/8" 6SPF HSC SHOT THE T-21 COAL ZONE @ 4844-4870
8/14/2021 RIH W/ GPT & 10' X 2 7/8" 6SPF HSC PERF. THE T-21 SAND @ 4802-4812, GUN WAS DRY
RIH W/ GR-CCL & 12' X 2 7/8" 6SPF HSC PERF THE T-19 SAND @ 4515-4527, GUN WAS DRY
RIG DOWN / 13:00 ON 8/14/21
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
SV Seaview 9
Seaview
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:211-00047 Seaview 9 Completion
Spud Date:
SHOT BOTTOM OF UPPER T-65 ZONE @ 6184-6207 /
THE T-40 SAND @ 5392-5412
See email attached regarding results of CBL. bjm
THE T-21 SAND @ 4802-4812,
UPPER T-65 ZONE @ 6164'-6184' /
@
@
PERF THE T-19 SAND @ 4515-4527,
@
3.5" CIBP SET @ 5090'
SHOT LOWER T-65 SAND @ 6265'-6276' @
T-30 SAND @ 5105-5132
Yellowjacket RIH W/ 2 3/4" SCBL TAGGED BOTTOM @7655' LOGGED UP TO 1200'.
SHOT THE T-21 COAL ZONE @ 4844-4870
PERF. THE T-47 SAND @ 5568-5575 @
PERF THE LOWER T-65 SAND @ 6265'-6276'
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9@?0 9@?
?
Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2021.07.26 14:53:15 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2021.07.27 10:09:27 -08'00'
TD Shoe Depth: PBTD:
Jts.
2
34
Yes X No X Yes No 80
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes 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?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:
Type II 200 2.4
Type II with UCS 165 1.16
4
23.20
Hanger 16 CDC Vault 0.95 23.20 22.25
1,417.60 25.61
Pup 7 5/8 29.7 L-80 CDC USS 2.41 25.61
1.49 1,419.09 1,417.60
Casing 7 5/8 29.7 L-80 CDC USS 1,391.99
Float 8 5/8 API BC Innovex
We ran a total of 29 centralizers up to 300'
Casing 7 5/8 29.7 L-80 CDC USS 78.11 1,497.20 1,419.09
www.wellez.net WellEz Information Management LLC ver_04818br
4
Type of Shoe:Innovex Casing Crew:Weatherford
12 85.2
1,498.471,504.00 1,417.60
CEMENTING REPORT
Csg Wt. On Slips:37,000
Spud Mud
3:35 7/14/2021 0
15.8 35.1
Bump press
Visual
Bump Plug?
64.8/65
1211
72.3
HalliburtonFIRST STAGE10.5Tune Prime 38.6
9.3 4.2
100
497
Csg Wt. On Hook:52,000 Type Float Collar:Innovex No. Hrs to Run:2.5
API BC Innovex 1.27 1,498.47 1,497.20
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.SV Seaview 9 Date Run 13-Jul-21
CASING RECORD
County State Alaska Supv.R Pederson / J Richardson
1,417.60
Floats Held
59 120.3
18 102.3
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.3
Shoe @ 1498.47 FC @ Top of Liner
52.8 57.8 10
Casing (Or Liner) Detail
Shoe 8 5/8
TD Shoe Depth: PBTD:
Jts.
1
1
153
Yes X No X Yes No
Fluid Description:
Liner hanger Info (Make/Model):Liner top Packer?:X Yes 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?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 5
177.68 16153.7
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 7749 FC @ Top of Liner 1254.177,704.62
Floats Held
165.41 231
37.5 193.5
3000
6% KCL
CASING RECORD
County State Alaska Supv.D. Yessak / J Riley
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.SV Seaview 9 Date Run 23-Jul-21
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
DWC Innovex 1.38 7,744.00 7,742.62
Csg Wt. On Hook:122,000 Type Float Collar:Innovex No. Hrs to Run:15.5
9.4 5
100
1260FIRST STAGE10.5Tuned Spacer 22
111.5/111.5
1900
37.5
Halliburton
15.3 19
Bump press
Visual / CBL indicated Cement at Liner hanger
Bump Plug?
16:10 7/24/2021 1,249'
7,744.007,749.00 7,659.00
CEMENTING REPORT
Csg Wt. On Slips:
6% KCL
12 212
Type of Shoe:Bullnose Casing Crew:Weatherford
HRD-E ZXP Flex Lock V
www.wellez.net WellEz Information Management LLC ver_04818br
2
We ran a total of 152 centralizers to top of liner
Liner 4 1/2 12.6 L-80 DWC 41.70 7,742.62 7,700.92
Float Collar 5 DWC Innovex 1.30 7,700.92 7,699.62
Liner 4 1/2 12.6 L-80 DWC 39.35 7,699.62 7,660.27
Landing Collar 5 DWC JHobbs (Baker) 1.09 7,660.27 7,659.18
Liner 4 1/2 12.6 L-80 DWC 6,375.97 7,659.18 1,283.21
Pup Joint 4 1/2 DWC Baker 1.80 1,283.21 1,281.41
Liner Hanger/Packer 7 5/8 H563 Baker 32.24 1,281.41 1,249.17
Lead 505 2.39
Tail 100 1.24
4.5
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:Seaview 9 Date:7/15/2021
Csg Size/Wt/Grade:7 5/8" / 29.7# / L-80 Supervisor:D. Yessak
Csg Setting Depth:1,499 TMD 1,427 TVD
Mud Weight:8.9 ppg LOT / FIT Press =650 psi
LOT / FIT =17.66 ppg Hole Depth =1524 md
Fluid Pumped=6.9 Gals Volume Back =6.3 Gals
Test Pump Output:2.300 Gals/Inch
LOT / FIT DATA CASING TEST DATA
Enter Gallons Enter Pressure Enter Gallons Enter Pressure
Here Here Here Here
->0 0 ->0 0
->2.3 100 ->8 750
->4.6 400 ->15 1500
->6.9 700 ->23 2250
-> ->30 3000
-> ->
-> ->
-> ->
-> ->
-> ->
-> ->
-> ->
-> ->
-> ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 700 ->5 3000
->1 670 ->10 3000
->2 660 ->15 3000
->3 650 ->20 3000
->4 640 ->25 3000
->5 630 ->30 3000
->6 625 ->
->7 625 ->
->8 615 ->
->9 610 ->
->10 605 ->
->11 600 ->
->12 600 ->
->13 600 ->
0
2.3
4.6
6.9
0
8
15
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
010203040Pressure (psi)Strokes (# of)
LOT / FIT DATA CASING TEST DATA
700
670660650640630625625615610605600600600
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 5 10 15 20 25 30Pressure (psi)Time (Minutes)
LOT / FIT DATA CASING TEST DATA
1
Guhl, Meredith D (CED)
From:Frank Roach <Frank.Roach@hilcorp.com>
Sent:Tuesday, July 20, 2021 10:25 AM
To:McLellan, Bryan J (CED)
Subject:RE: [EXTERNAL] RE: Seaview 9 (PTD 221-025)
Attachments:Seaview 9 7.625 Caasing and LOT.xls
Bryan,
To answer your questions:
I would call this an FIT. From the discussion with the company man out there, the test pump was acting
erratically as they were bringing up the pressure. To avoid overshooting leakoff and accidentally breaking down
the shoe, they shut the pump down. When the pressure stabilized at 700psi, they decided not to risk taking the
test higher since 700psi exceeded the value needing to achieve our minimum kick tolerance. Confirm this with
Matt Herrera since he was out there, witnessing the test.
Also in talking with the company man, there is some formatting error in the Excel sheet. I attempted to find and
fix the sheet without success so I rebuilt the sheet to make the two tables consistent and have the plot correctly
display the table data. With the data correctly displayed in the plot, it shows a close overlay between the casing
test and the shoe test. From the mechanical test chart (image in the previous email), the casing test and FIT
trends track each other as well, corroborating the tabular data. See the attached, fixed test sheet. We use the
test pump on these tests and not the rig pumps. The test pump output is small (0.195 gal/stk).
Agreed. Casing test volume in the old Excel sheet is incorrect. Please see the attached, corrected Excel sheet and
the information on the mechanical test chart (image in the previous email) to show it took a little over 29 gallons
to reach 3,000psi on the casing test.
Regards,
Frank V Roach
Drilling Engineer
907.854.2321 (c)
907.777.8413 (o)
From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Sent: Monday, July 19, 2021 13:20
To: Frank Roach <Frank.Roach@hilcorp.com>
Subject: [EXTERNAL] RE: Seaview 9 (PTD 221‐025)
Frank,
The FIT plot looks unusual and I’d like to discuss with you.
Usually there are more data points on the LOT/FIT curve so we can see it start to break over. Are you calling this
an FIT or LOT?
We normally overlay the casing curve to see that the FIT more or less follows it until reaching frac pressure. In
the Seaview 9 plot, the units for the two different curves are different, so the overlay is not useful. You could
convert the casing test from strokes to gallons and then overlay the two curves for a more meaningful
comparison. What is your pump output in bbls/stroke?
Also, the casing test looks strange, since it took only 2 strokes to reach 3000 psi.
Thanks
Bryan McLellan
2
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250‐9193
From: Frank Roach <Frank.Roach@hilcorp.com>
Sent: Thursday, July 15, 2021 5:47 PM
To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Cc: Monty Myers <mmyers@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>
Subject: Seaview 9 (PTD 221‐025)
Mel and Bryan,
This afternoon, we conducted the planned LOT on Seaview 9 with Matt Herrera witnessing. Please see the attached test
chart and Excel workbook.
The test was stopped at 700psi. Over the shut‐in monitoring period, the pressure decreased with signs of stabilization
from 700psi to 600 psi. In discussion between the company rep and State inspector, a value of 650psi was agreed to for
this test. That pressure, along with the 8.9ppg test fluid, gives us a 17.66ppg EMW shoe test, exceeding our 15.3ppg
EMW minimum from the PTD.
From this test, the plan is to drill to the planned TD of 7,763’ MD (6,230’ TVD).
Let me know if you need any additional information.
Regards,
Frank V Roach
Drilling Engineer
907.854.2321 (c)
907.777.8413 (o)
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 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.
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 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
Guhl, Meredith D (CED)
From:Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent:Wednesday, August 4, 2021 1:03 PM
To:McLellan, Bryan J (CED); Frank Roach
Cc:Donna Ambruz; Taylor Wellman; Jennifer Starck
Subject:RE: [EXTERNAL] Seaview 9 (PTD 221-025) Cement report for 4-1/2" liner
Attachments:RE: [EXTERNAL] Seaview 9 (PTD 221-025) perf sundry
Not an expert myself, but with the amended sundry now only asking for perfs up to 4515’ MD, I believe that all proposed
perfs fall within the good bond section per your note below. Any other outstanding questions on the sundry?
Ryan Rupert
Kenai Ops Engineer (13146)
907-301-1736 (Cell)
907-777-8503 (Office)
From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Sent: Wednesday, August 4, 2021 10:06 AM
To: Frank Roach <Frank.Roach@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: FW: [EXTERNAL] Seaview 9 (PTD 221‐025) Cement report for 4‐1/2" liner
Thanks for the cement report. The job seemed to go according to plan with good returns and cement seen at surface.
What is your interpretation of the CBL log?
It looks to me like pretty good bond from TD up to about 2500’, with some small sections of questionable bond. It looks
like poor bond from 2500’ up to the surface casing shoe at 1500’, then it looks very good across the liner lap up to the
LTP.
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: Frank Roach <Frank.Roach@hilcorp.com>
Sent: Tuesday, August 3, 2021 4:02 PM
To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] Seaview 9 (PTD 221‐025) Cement report for 4‐1/2" liner
2
Bryan,
Please see the 4‐1/2” liner cement report.
I also saw that Ryan Rupert forwarded the weekly summaries to you.
Regards,
Frank V Roach
Drilling Engineer
907.854.2321 (c)
907.777.8413 (o)
From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Sent: Tuesday, August 3, 2021 13:32
To: Frank Roach <Frank.Roach@hilcorp.com>
Subject: [EXTERNAL] Seaview 9 (PTD 221‐025) Cement report for 4‐1/2" liner
Frank,
Could you send me the cement report form for the 4‐1/2” liner on Seaview 9?
Thanks
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
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 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.
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
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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.
t�a �-cDZS
Hilcnrp :I1urkM7 LLs.
Date: 09/09/2021
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
RECEIVED
SEP 0 9 2021
AOGCC
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025) "CONFIDENTIAL"
Washed and Dried Well Samples (07/19/2021)
B Set (5 Boxes):
WELL
Box
SAMPLE MTE WAL (FEET f PAD)
SEAVIEW 9
BOX 1 OF 5
1504' - 2760' MD
SEAVIEW 9
BOX 2 OF 5
2760' - 4020' MD
SEAVIEW 9
BOX 3 OF 5
4020' - 5400' MD
SEAVIEW 9
BOX 4 OF 5
5400- 6720' MD
SEAVIEW 9
BOX 5 OF 5
6720' - 7749' MD (TD)
Please include current contact information if different from above.
�-�-qbZ
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422
Received y: Date:
co(2��
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422
Received By: Date:
Date: 09/08/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025) **CONFIDENTIAL**
Radial Cement Bond Log (08/02/2021)
Folder Contents (Electronic Plots and Digital Data):
Please include current contact information if different from above.
37'
(6HW
Received By:
09/09/2021
By Abby Bell at 4:52 pm, Sep 08, 2021
AOGCC
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422
Received By: Date:
Date: 09/08/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025) **CONFIDENTIAL**
PERF RECORD (08/19/2021)
Folder Contents (Electronic Plots and Digital Data):
Please include current contact information if different from above.
37'
(6HW
Received By:
09/09/2021
By Abby Bell at 4:51 pm, Sep 08, 2021
AOGCC
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422
Received By: Date:
Date: 09/08/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025) **CONFIDENTIAL**
GPT-PERF (08/10/2021)
Folder Contents (Electronic Plots and Digital Data):
Please include current contact information if different from above.
37'
(6HW
Received By:
09/09/2021
By Abby Bell at 4:49 pm, Sep 08, 2021
AOGCC
1
Davies, Stephen F (CED)
From:Cody Terrell <cterrell@hilcorp.com>
Sent:Monday, August 16, 2021 9:15 AM
To:Davies, Stephen F (CED)
Cc:Roby, David S (CED)
Subject:Re: [EXTERNAL] Re: Seaview 9 Spacing Exception Revision- CO 791
Thanks again for the quick response Steve. I’ll get them sent out today.
Sent from my iPhone
On Aug 16, 2021, at 9:05 AM, Davies, Stephen F (CED) <steve.davies@alaska.gov> wrote:
Hi Cody,
Yes, that’s the Commission’s decision.
Thanks and stay safe,
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
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: Cody Terrell <cterrell@hilcorp.com>
Sent: Monday, August 16, 2021 9:02 AM
To: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Cc: Roby, David S (CED) <dave.roby@alaska.gov>
Subject: Re: [EXTERNAL] Re: Seaview 9 Spacing Exception Revision‐ CO 791
Thanks for your quick response.
Just to clarify, you’re saying that the commissioners are requiring us to re‐notice all landowners even if
they were sent notice in the original spacing exception? My concern is this will create a lot of confusion
among the landowners.
Sent from my iPhone
On Aug 16, 2021, at 8:51 AM, Davies, Stephen F (CED) <steve.davies@alaska.gov>
wrote:
2
Hi Cody,
The decision regarding notification ultimately lies with the Commissioners and not Dave
or me.
Thanks and stay safe,
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
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: Cody Terrell <cterrell@hilcorp.com>
Sent: Monday, August 16, 2021 8:37 AM
To: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Cc: Roby, David S (CED) <dave.roby@alaska.gov>
Subject: Re: [EXTERNAL] Re: Seaview 9 Spacing Exception Revision‐ CO 791
Steve,
After talking with Roby, he instructed me that only owners would weren’t noticed in the
original needed to be notified. The other landowners were originally notified in the
original exception.
The only change is the TPH was moved up hole (notice wasn’t sent out to all affected
owners). The work and well location and everything is the same as the original spacing
exception.
Please let me know if this isn’t correct so I can move on this ASAP, it will require 80‐100
more mail outs. Thanks in advance Steve.
Sent from my iPhone
On Aug 16, 2021, at 8:29 AM, Davies, Stephen F (CED)
<steve.davies@alaska.gov> wrote:
HI Cody,
The spacing regulation requires Hilcorp to notify all owners, landowners
and operators within 3,000 feet of the entire Seaview 9 well regarding
Hilcorp’s proposed amendment to CO 791.
Thanks and stay safe,
Steve Davies
3
Alaska Oil and Gas Conservation Commission (AOGCC)
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: Cody Terrell <cterrell@hilcorp.com>
Sent: Monday, August 16, 2021 8:24 AM
To: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov>
Cc: Salazar, Grace (CED) <grace.salazar@alaska.gov>; Davies, Stephen F
(CED) <steve.davies@alaska.gov>; Roby, David S (CED)
<dave.roby@alaska.gov>
Subject: RE: [EXTERNAL] Re: Seaview 9 Spacing Exception Revision‐ CO
791
Hi Samantha,
Can you or Grace please let me know ASAP when the hearing will
be scheduled for? I am getting a lot of pressure on my end. The
deeper gas zones proved not successful so we would like to move
up hole ASAP.
Thanks in advance!
Regards,
Cody T. Terrell
Landman
Hilcorp Alaska, LLC
Direct: 907-777-8432
Cell: 713-870-4532
From: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov>
Sent: Thursday, August 12, 2021 9:13 AM
To: Cody Terrell <cterrell@hilcorp.com>
Cc: Salazar, Grace (CED) <grace.salazar@alaska.gov>; Davies, Stephen F
(CED) <steve.davies@alaska.gov>; Roby, David S (CED)
<dave.roby@alaska.gov>
Subject: [EXTERNAL] Re: Seaview 9 Spacing Exception Revision‐ CO 791
Hi Cody,
We have not scheduled this hearing yet. We will notify you when we
do.
Thanks,
Samantha Carlisle
4
Executive Secretary III
(907) 793‐1223
On Aug 12, 2021, at 8:56 AM, Cody Terrell
<cterrell@hilcorp.com> wrote:
Hi Samantha,
Since Grace is out, can you let me know when the
hearing for this is scheduled please?
Regards,
Cody T. Terrell
Landman
Hilcorp Alaska, LLC
Direct: 907-777-8432
Cell: 713-870-4532
From: Cody Terrell
Sent: Thursday, August 12, 2021 8:47 AM
To: Salazar, Grace (CED) <grace.salazar@alaska.gov>
Subject: RE: Seaview 9 Spacing Exception Revision‐ CO
791
Hi Grace,
Just checking in on this to see when the public
hearing was set for.
Regards,
Cody T. Terrell
Landman
Hilcorp Alaska, LLC
Direct: 907-777-8432
Cell: 713-870-4532
From: Cody Terrell
Sent: Monday, August 9, 2021 3:36 PM
To: Salazar, Grace (CED) <grace.salazar@alaska.gov>
Cc: steve.davies@alaska.gov; Roby, David S (CED)
<dave.roby@alaska.gov>
Subject: Seaview 9 Spacing Exception Revision‐ CO 791
Grace,
Please see Hilcorp Alaska, LLC’s application to
revise CO 791 for the Seaview No. 9 Well. I am in
5
the process of getting the certified mailings
complete and copies sent over to you. Please let me
know if you have any questions.
Regards,
Cody T. Terrell | Landman | Hilcorp Alaska, LLC
O: 907-777-8432 | C: 713-870-4532 |
cterrell@hilcorp.com
3800 Centerpoint Dr., Suite 1400 | Anchorage |
Alaska | 99503
This email may contain confidential and / or privileged
information
and is intended for the recipient(s) only. In the event you
receive
this message in error, please notify me and delete the message.
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 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.
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
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While all reasonable care has been taken to avoid the transmission of viruses, it is the
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accepted by the company in this regard and the recipient should carry out such virus and other
checks as it considers appropriate.
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
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If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to
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virus and other checks as it considers appropriate.
6
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 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.
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
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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,
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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: ___Patch / 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):
7,749'none
Casing Collapse
Structural
Conductor
Surface 4,790psi
Intermediate
Production
Liner 7,500psi
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date:GAS WAG GSTOR SPLUG
Commission Representative: GINJ Op Shutdown Abandoned
Taylor Wellman 777-8449 Contact Name: Ryan Rupert
Operations Manager Contact Email:
Contact Phone: 777-8503
Date:
Conditions of approval: Notify Commission so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by:COMMISSIONER THE COMMISSION Date:
Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng
ryan.rupert @hilcorp.com
6,230'7,659'6,142'~1774psi none
Baker LTP ; Baker TRSSSV S-5 BXCE planned 1249' MD / 1219' TVD; 500' MD / 500' TVD planned
Perforation Depth TVD (ft): Tubing Size:
COMMISSION USE ONLY
Authorized Name:
8,430psi
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
ADL392667; Private Fee
221-025
50-231-20078-00-00
Seaview-09
Seaview Undefined gas Pool
Length Size
CO 791
Hilcorp Alaska, LLC
3800 Centerpoint Dr, Suite 1400
Anchorage Alaska 99503
PRESENT WELL CONDITION SUMMARY
L-80 planned
TVD Burst
1249' MD planned
MD
6,890psi
120'
1,428'
120'
1,499'
16"
7-5/8"
120'
1,499'
Perforation Depth MD (ft):
See Attached Schematic
4-1/2"
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 30, 2021
7,744'6,495'
4-1/2" planned
6,225'
Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval.
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143),
ou=Users
Date: 2021.07.27 16:41:32 -08'00'
Taylor Wellman
(2143)
By Meredith Guhl at 10:25 am, Jul 28, 2021
321-374
AOGCC
X bjm
DSR-7/29/21SFD 7/28/2021
10-407
CT BOP test to 3500 psi
This sundry only authorizes perforating the gas sands including the T19 and deeper. Shallower perfs will require a new spacing exception, which
requires additional landowner notification and notice of public hearing. Perfs Shallower than the T17 will also require a review of the wellbore
conditions and pore pressure / frac gradient data to ensure the wellbore pressure can not exceed the frac pressure of the shallowest perf interval.
X
In accordance with 20 AAC 25.215 perfs in the Beluga and Tyonek formations cannot be open at the same time without prior order of the AOGCC.
BJM 8/4/2021
dts 8/5/2021 JLC 8/5/2021
Jeremy Price
Digitally signed by Jeremy
Price
Date: 2021.08.05 12:07:07
-08'00'
RBDMS HEW 8/6/2021
Well: Seaview-09
Date: 7/26/2021
Well Name:Seaview-09 API Number:50-231-20078-00-00
Current Status:New drill (gas)Leg:N/A
Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:221-025
First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C)
Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C)
Max. Expected BHP:~ 2,280 psi @ 5,066’ TVD Based on 0.45psi/ft gradient
Max. Potential Surface Pressure ~ 1,774 psi Based on 0.1psi/ft to surface
Well Summary
Seaview-09 is a new drill that had its liner cemented on 7/26/21. Per PTD 221-025 the rig will run the upper
completion tubing and SSSV and then RDMO. A CBL of the 4-1/2” liner is required per that PTD. Additionally,
the well will be blown down with nitrogen, and perfs shot.
The goal of this project is to finish completion activities for the well, and perforate initial zone(s).
Notes Regarding Wellbore Condition
x Min ID = 3.812” (drift ID of 4-1/2” TRSSSV)
x Max Inclination = 59 degrees at 2869’ MD
Nitrogen Risk
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
E-Line CBL
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250psi low / 2,500 psi High.
3. MU radial CBL tool with GR/CCL
4. RIH and log up from PBTD to Liner hanger at 1,249’ MD
5. Report CBL data to state
6. RDMO EL
Confirm the rig has obtained a passing MIT-IA and MIT-T to 2500psi. If not, will need to be completed before CT
blowdown
Report CBL data to state
o finish completion activities for the well, and perforate initial zone(s).
Well: Seaview-09
Date: 7/26/2021
CT Nitrogen Blow Down
1. MIRU Petrospec coil
2. Perform BOP test to 250psi low / 3500 high (notify AOGCC 24hrs in advance)
Contingency: If CBL data hasn’t been acquired yet, will need to run a memory CBL or EL CBL during this CT rigup
3. Confirm CBL data has been reported to state and prepare for blow down
4. RU nitrogen
5. MU nozzle BHA, and RIH to PBTD displacing all fluid out of well with N2 (expected WBV ~116bbls)
6. Consult OE for what nitrogen pressure to leave on well
7. RDMO CT
E-Line Perf
1. MIRU EL and pressure control equipment
2. PT lubricator to 250psi low / 2,500 psi High.
3. Rig up perf gun (Likely 2-7/8” 4-6 spf)
4. RIH and perforate the sand listed in the table below, per Geo/RE.
Sand Perforation
Top (MD)
Perforation
Bottom (MD)
Perforation Top
(TVD)
Perforation
Bottom (TVD)
Total Footage
(MD)
BEL_135 ±1,627'±1,638'±1,525'±1,536'11'
BEL_138 ±1,766'±1,806'±1,624'±1,664'40'
T6A ±2,329'±2,337'±1,950'±1,958'8'
T8 ±2,596'±2,639'±2,096'±2,139'43'
T9 ±2,752'±2,792'±2,182'±2,222'40'
T10 ±2,870'±2,964'±2,244'±2,338'94'
T10_BASE ±3,218'±3,277'±2,433'±2,492'59'
T12A ±3,619'±3,647'±2,652'±2,680'28'
T14B ±4,064'±4,076'±2,895'±2,907'12'
T17 ±4,341'±4,375'±3,066'±3,100'34'
T19 ±4,515'±4,527'±3,188'±3,200'12'
T21_COAL ±4,802'±4,812'±3,415'±3,425'10'
T21_COAL ±4,844'±4,873'±3,449'±3,478'29'
T30 ±5,105'±5,158'±3,672'±3,725'53'
T40 ±5,392'±5,412'±3,928'±3,948'20'
T47 ±5,568'±5,575'±4,092'±4,099'7'
T65 ±6,164'±6,207'±4,667'±4,710'43'
T65_BASE ±6,265'±6,276'±4,767'±4,778'11'
T70 ±6,384'±6,404'±4,885'±4,905'20'
T70_BASE ±6,506'±6,519'±5,005'±5,018'13'
T70_BASE ±6,546'±6,568'±5,044'±5,066'22'
Confirm CBL data has been reported to state a
Well: Seaview-09
Date: 7/26/2021
Consult with OE for what WHP’s to use. Some intervals may be shot while flowing
Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist.
a.Use Gamma/CCL to correlate.
b. Record initial and 5/10/15 minute tubing pressures after firing
c. Consult with RE/Geo between each perf interval:
i. Trudi Hallett (RE): 301-6657
ii. Ben Siks (Geo): 229-0865
7. RD E-Line Unit and turn well over to production.
Note: The SSSV and SSV must be performance-tested within 5 days after return to production.
Contingency EL Plug or Patch
1. MIRU EL and pressure control equipment
2. PT lubricator to 250psi low / 2,500 psi High.
3. RU Nitrogen Truck
a. Push water back into formation
b. Use GPT tool to confirm water level is below interval to perf
c. Consult OE for pressure to leave on well for perforating
4. Once fluid level is below interval to isolate, MU 4-1/2” patch or plug
5. RIH and set plug or patch per OE.
6. RD E-Line Unit and turn well over to production.
Attachments:
1. Current schematic
2. Proposed Schematic
3. Standard Well procedure – N2 Operations
Updated by CRR 07-27-2021
SCHEMATIC
Seaview 9
PTD:221-025
API:50-231-20078-00-00
PBTD = 7,659’ / TVD = 6,142’
TD = 7,749’ / TVD = 6,230’
RKB to GL = 18’
OPEN HOLE / CEMENT DETAIL
7-5/8"9-7/8: Hole: 85bbls 12ppg lead cement followed by 35bbls 15.8ppg tail cement. No
losses. 18bbls cement to surface
4-1/2”6-3/4” hole: 212bbls 12.0ppg lead cement followed by 19bbls 15.3ppg tail cement.
No losses. 37bbls cement to surface. ToC = Liner hanger @ 1,249’ MD
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 CDC 6.875”Surf 1,499’
4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,249’7,744’
TUBING DETAIL
1
16”
7-5/8”
4-1/2”
No.Depth ID Item
1
2
3 1,249’4.875”Liner hanger / LTP Assembly
2
3
37bbls cement to surface.
18bbls cement to surface
Updated by CRR 07-26-2021
PROPOSED SCHEMATIC
Seaview 9
PTD:221-025
API:50-231-20078-00-00
PBTD = 7,659’ / TVD = 6,142’
TD = 7,749’ / TVD = 6,230’
RKB to GL = 18’
PERFORATION DETAIL
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status
BEL_135 ±1,627'±1,638'±1,525'±1,536'11'TBD Proposed
BEL_138 ±1,766'±1,806'±1,624'±1,664'40'TBD Proposed
T6A ±2,329'±2,337'±1,950'±1,958'8'TBD Proposed
T8 ±2,596'±2,639'±2,096'±2,139'43'TBD Proposed
T9 ±2,752'±2,792'±2,182'±2,222'40'TBD Proposed
T10 ±2,870'±2,964'±2,244'±2,338'94'TBD Proposed
T10_BASE ±3,218'±3,277'±2,433'±2,492'59'TBD Proposed
T12A ±3,619'±3,647'±2,652'±2,680'28'TBD Proposed
T14B ±4,064'±4,076'±2,895'±2,907'12'TBD Proposed
T17 ±4,341'±4,375'±3,066'±3,100'34'TBD Proposed
T19 ±4,515'±4,527'±3,188'±3,200'12'TBD Proposed
T21_COAL ±4,802'±4,812'±3,415'±3,425'10'TBD Proposed
T21_COAL ±4,844'±4,873'±3,449'±3,478'29'TBD Proposed
T30 ±5,105'±5,158'±3,672'±3,725'53'TBD Proposed
T40 ±5,392'±5,412'±3,928'±3,948'20'TBD Proposed
T47 ±5,568'±5,575'±4,092'±4,099'7'TBD Proposed
T65 ±6,164'±6,207'±4,667'±4,710'43'TBD Proposed
T65_BASE ±6,265'±6,276'±4,767'±4,778'11'TBD Proposed
T70 ±6,384'±6,404'±4,885'±4,905'20'TBD Proposed
T70_BASE ±6,506'±6,519'±5,005'±5,018'13'TBD Proposed
OPEN HOLE / CEMENT DETAIL
7-5/8"9-7/8: Hole: 85bbls 12ppg lead cement followed by 35bbls 15.8ppg tail cement. No
losses. 18bbls cement to surface
4-1/2”6-3/4” hole: 212bbls 12.0ppg lead cement followed by 19bbls 15.3ppg tail cement.
No losses. 37bbls cement to surface. ToC = Liner hanger @ 1,249’ MD
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 CDC 6.875”Surf 1,499’
4-1/2"Prod Lnr 12.6 L-80 DWC/C HT 3.958”1,249’7,744’
TUBING DETAIL
4-1/2"Prod Tieback 12.6 L-80 DWC/C HT 3.958”Surf 1,249’
1
16”
7-5/8”
4-1/2”
No.Depth ID Item
1 500’3.812”TRSSSV S-5 BXCE with BX profile (Baker)
2 1,249’4.790”Seal Stem
3 1,249’4.875”Liner hanger / LTP Assembly
2
3
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.
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422
Received By: Date:
Date: 07/30/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025) **CONFIDENTIAL**
OPEN HOLE WIRELINE LOGS (07/13/2021 to 07/22/2021)
1.BOREHOLE VOLUME PLOT (RUN 1: 07/13/2021)
2.WAVEFORM SONIC/SIX ARM CALIPER RAW & PROCESSED (RUN 1: 07/13/2021)
3.WAVEFORM SONIC/SIX ARM CALIPER RAW & PROCESSED (RUN 2: 07/20/2021)
4.EXTENDED MICRO IMAGER RAW & PROCESSED (RUN 2: 07/20/2021)
5.ROTARY CORY TOOL (RUN 7: 07/22/2021)
Folder Contents (Electronic Plots and Digital Data):
Please include current contact information if different from above.
07/30/2021
PTD: 2210250
E-Set: 35440
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422
Received By: Date:
Date: 07/30/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025) **CONFIDENTIAL**
OPEN HOLE WIRELINE LOGS (07/13/2021 to 07/22/2021)
1.BOREHOLE VOLUME PLOT (RUN 1: 07/13/2021)
2.WAVEFORM SONIC/SIX ARM CALIPER RAW & PROCESSED (RUN 1: 07/13/2021)
3.WAVEFORM SONIC/SIX ARM CALIPER RAW & PROCESSED (RUN 2: 07/20/2021)
4.EXTENDED MICRO IMAGER RAW & PROCESSED (RUN 2: 07/20/2021)
5.ROTARY CORY TOOL (RUN 7: 07/22/2021)
Folder Contents (Electronic Plots and Digital Data):
Please include current contact information if different from above.
07/30/2021
PTD: 2210250
E-Set: 35441
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422
Received By: Date:
Date: 07/30/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025) **CONFIDENTIAL**
OPEN HOLE WIRELINE LOGS (07/13/2021 to 07/22/2021)
1.BOREHOLE VOLUME PLOT (RUN 1: 07/13/2021)
2.WAVEFORM SONIC/SIX ARM CALIPER RAW & PROCESSED (RUN 1: 07/13/2021)
3.WAVEFORM SONIC/SIX ARM CALIPER RAW & PROCESSED (RUN 2: 07/20/2021)
4.EXTENDED MICRO IMAGER RAW & PROCESSED (RUN 2: 07/20/2021)
5.ROTARY CORY TOOL (RUN 7: 07/22/2021)
Folder Contents (Electronic Plots and Digital Data):
Please include current contact information if different from above.
07/30/2021
PTD: 2210250
E-Set: 35442
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422.
Received By: Date:
Date: 7/29/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025)
FINAL LWD FORMATION EVALUATION LOGS (07/11/2021 to 07/19/2021)
•DGR, GM, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
•Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
07/29/2021
PTD: 2210250
E-Set: 35435
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, 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 907 564-4422
Received By: Date:
Date: 07/29/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SEAVIEW 9 (PTD 221-025)
GEOLOG: EOW DRILLING REPORTS (07/11/2021 to 07/19/2021)
1.DAILY DRILLING REPORTS
2.FINAL EOW REPORT
3.DIGITAL DATA
4.LWD LOG PRINTS
5.MUDLOG PRINTS
6.SHOW REPORTS
Folder Contents:
Please include current contact information if different from above.
07/29/2021
PTD: 2210250
E-Set: 35436
MEMORANDUM
State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg % �� �►� -Z�:'Ll DATE:
P. I. Supervisor
FROM: Matt Herrera SUBJECT:
Petroleum Inspector
7/16/2021
Leak Off Test
Hilcorp Rig 169
Seaview #9; PTD 2210250 '
Hilcorp Alaska LLC
7/15/2021: Traveled to Hilcorp Seaview drill site to witness the leak off test after drilling
out from 7 5/8 -inch casing. I met with Hilcorp Company Representative Doug Yessak
and rig personnel and went over the rig up. They had the test pump rigged up for the
pressure test and we went over the "BBL/inch ratio" for pumping and anticipated break
over point for the well. All went as anticipated and drilling operations continued as
planned.
Attachments: Operator Leak -off Test Report
2021-0715 Leak -off Test Seaview-9 mh.docx
Page 1 of 1
V
CASING AND LEAK -OFF FRACTURE TESTS
Well Name: Seaview 9 Date: 7/15/2021
Csg Size/Wt/Grade: 7 5/8" / 29.7# / L-80 Supervisor: D. Yessak
Csg Setting Depth: 1,499 TMD 1,427 TVD
Mud Weight: 8.9 ppg LOT / FIT Press = 650
LOT / FIT = 17.66 ppg Hole Depth = 1524
Fluid Pumped= 6.9 Gals Volume Back = 6.3
Test Pump Output: 2.300 Gals/Inch
LOT / FIT DATA CASING TEST DATA
Enter Gallons Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
0
0
2.3
100
4.6
400
6.9
- 700
Enter Holding Enter Holding
Time Here Pressure Here
0
0.5
1
1.5
0
750
1500
— -- - 2250
2
3000
5
3000
10
3000
Enter Holding Enter Holding
Time Here Pressure Here
->
->
->
->
->
->
->
->
->
->
->
->
->
->
0
1
-- _ - ----
2
- - - -- - --
3
700
670
-
660
-
650
->
->
->
->
->
->
->
->
->
->
->
5
3000
10
3000
15
---;- 3000
- --- 20 - --
3000
4 640
25
3000
5 630
6 625
30
- -- -
3000
-
- 7 620-
8 615-
9 610
10 605
11 600
12 600
13 600
psi
and
Gals
LOT / FIT DATA f CASING TEST DATA
njb 'ZZ� C'L
1500
--- — —
1400
1300
1200
1100
1000
900
:y
Q
800
d
7
ui
d
0.5
a
700
600
500
400
300
200
100
0
0 Strokes (# of) 10
5g -a -)o J I LOT / FIT DATA CASING TEST DATA
pv �2
1500 -- -
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
0 5 10 15 20 25 30 35
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, Inc.
3800 Centerpoint Drive, Suite 400
Anchorage, AK 99503
Re: Seaview Field, Seaview Undefined Gas Pool, Seaview 9
Hilcorp Alaska, LLC
Permit to Drill Number: 221-025
Surface Location: 2425' FNL, 370' FEL, Sec 9, T5S, R15W, SM, AK
Bottomhole Location: 486' FSL, 2153' FWL, Sec 9, T5S, R15W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is
contingent upon issuance of a conservation order approving a spacing exception. Hilcorp Alaska,
LLC assumes the liability of any protest to the spacing exception that may occur.
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 June, 2021.
Jeremy
Price
Digitally signed
by Jeremy Price
Date: 2021.06.24
13:10:59 -08'00'
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: 7,763'TVD: 6,230'
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): 229'15.Distance to Nearest Well Open
Surface: x-163025 y- 2108532 Zone-4 211' to Same Pool: 1380' to Seaview 8
16.Deviated wells: Kickoff depth: 550 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 57 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 1,500' Surface Surface 1,500' 1,432'
6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 6,463' 1,300' 1,266' 7,763' 6,320'
Tieback 4-1/2" 12.6# L-80 DWC/C HT 1,300' Surface Surface 1,300' 1,266'
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: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:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Seaview 9
Seaview Unit
6/17/2021
2187' to nearest unit boundary
Frank Roach
frank.roach@hilcorp.com
777-8413
Total Depth MD (ft): Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL CONFIDENTIAL
20 AAC 25.005
L - 1173 ft3 / T - 104 ft3
2180
1086' FSL, 2427' FEL, Sec 9, T5S, R15W, SM, AK
486' FSL, 2153' FWL, Sec 9, T5S, R15W, SM, AK
LOCI 18-001
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
2425' FNL, 370' FEL, Sec 9, T5S, R15W, SM, AK ADL392667; Private Fee
724
18.Casing Program: Top - Setting Depth - BottomSpecifications
2803
Cement Quantity, c.f. or sacks
Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 393 ft3 / T - 182 ft3
Conductor/Structural
LengthCasing
Authorized Signature:
Production
Liner
Intermediate
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Commission Use Only
See cover letter for other
requirements.
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):
Perforation Depth MD (ft):
Tieback Assembly
Effect. Depth MD (ft): Effect. Depth TVD (ft):
et
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
5.10.2021
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: 2021.05.10 17:46:38 -08'00'
Monty M
Myers
By Meredith Guhl at 8:47 am, May 11, 2021
Provide 24 hrs notice for AOGCC to witness liner/tieback pressure test to 2500 psi.
SFD 5/11/2021
Variance to 20 AAC 25.033(f)(4)(C) approved
see procedure page 8 for details.
Seaview Undefined Gas Pool
SFD 5/11/2021
Exploratory Well
Maximum well depth will be determined by LOT pressure achieved.See attached LOT vs. Allowable TVD table.
SFD 5/11/2021
Surface csg test pressure to 3000 psi (43.5% of burst). Variance to 20 AAC 25.030(e) approved.
50-231-20078-00-00221-025
DSR-5/11/21BJM 6/16/21
BOP test to 3500 psi. Annular to 2500 psi. 7-day BOP test frequency.
CBL required across 4.5" liner. Can be part of completion Sundry.
6230' bjm
Pool Rules or Spacing Exception Order required prior to spud.
dts 6/24/2021
JLC 6/24/2021
6/24/21
Jeremy Price Digitally signed by Jeremy Price
Date: 2021.06.24 13:11:19 -08'00'
SEAVIEW 9
Drilling Program
Confidential
Delineation
Tight Hole
Seaview Unit
Rev 1
May 3, 2021
SFD 5/10/2021
Exploratory (See 20 AAC 25.990(25).)
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 21-1/4” Diverter ..................................................................................................................... 11
11.0 Drill 9-7/8” Hole Section ............................................................................................................... 13
12.0 Run 7-5/8” Surface Casing ........................................................................................................... 15
13.0 Cement 7-5/8” Surface Casing ..................................................................................................... 18
14.0 BOP N/U and Test ......................................................................................................................... 21
15.0 Drill 6-3/4” Hole Section ............................................................................................................... 22
16.0 Run 4-1/2” Production Liner ....................................................................................................... 25
17.0 Cement 4-1/2” Production Liner ................................................................................................. 28
18.0 4-1/2” Liner Tieback Polish Run and Cleanout Run ................................................................. 32
19.0 4-1/2” Tieback Run ....................................................................................................................... 32
20.0 RDMO ............................................................................................................................................ 33
21.0 Diverter Schematic........................................................................................................................ 34
22.0 BOP Schematic .............................................................................................................................. 35
23.0 Wellhead Schematic ...................................................................................................................... 36
24.0 Days Vs Depth ............................................................................................................................... 37
25.0 Geo-Prog ........................................................................................................................................ 38
26.0 Anticipated Drilling Hazards ....................................................................................................... 39
27.0 Hilcorp Rig 169 Layout ................................................................................................................ 41
28.0 FIT/LOT Procedure...................................................................................................................... 42
29.0 Choke Manifold Schematic .......................................................................................................... 43
30.0 Casing Design Information .......................................................................................................... 44
31.0 6-3/4” Hole Section MASP ........................................................................................................... 45
32.0 Spider Plot (Governmental Sections) .......................................................................................... 46
33.0 Surface Plat (As-Built NAD27) .................................................................................................... 47
Page 2 Version 1 May, 2021
SEAVIEW 9
Drilling Procedure
Rev 1
1.0 Well Summary
Well SEAVIEW 9
Pad & Old Well Designation Seaview Pad / grass roots well
Planned Completion Type 4-1/2” Cemented Production Liner
Target Reservoir(s) Sterling/Beluga/Tyonek Gas Sands
Planned Well TD, MD / TVD 7,763’ MD / 6,229’ TVD
PBTD, MD / TVD 7,863’ MD / 6,151’ TVD
Surface Location (Governmental) 2425’ FNL, 370’ FEL, Sec 9, T5S, R15W, SM, AK
Surface Location (NAD 27) X=163025.69 Y=2108532.94
Top of Productive Horizon
(Governmental) 1086’ FSL, 2427’ FEL, Sec 9, T5S, R15W, SM, AK
TPH Location (NAD 27) X=160860.24, Y=2106782.57
BHL (Governmental) 486’ FSL, 2153’ FWL, Sec 9, T5S, R15W, SM, AK
BHL (NAD 27) X=160144.56, Y=2106202.59
AFE Number
AFE Drilling Days 4 MOB, 35 DRLG
AFE Completion Days 6
AFE Drilling Amount $4,502,267
AFE Completion Amount $820,450
Maximum Anticipated Pressure
(Surface) 2180 psi
Maximum Anticipated Pressure
(Downhole/Reservoir) 2803 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB – GL 229.0’ (211 + 18)
Ground Elevation 211’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
Page 3 Version 1 May, 2021
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Drilling Procedure
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2.0 Management of Change Information
must be approved in advance by the AOGCC. (See 20 AAC 25.015.)
SFD 5/10/2021
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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” - 84 X-56 Weld 2980 1410 -
9-7/8” 7-5/8” 6.875” 6.750” 8.500” 29.4 L-80 DWC/C 6890 4790 683
6-3/4” 4-1/2” 3.958” 3.833” 5.000” 12.6 L-80 DWC/C-HT 8430 7500 288
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
Cleanout 2-7/8” 2.323 2.265” 3.438” 7.9 P-110 PH-6 16,896 16,082 194k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
Page 5 Version 1 May, 2021
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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, Frank.Roach@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. Monty M Myers: O: 907-777-8431 C: 907-538-1168
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, Frank.Roach@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,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
SEAVIEW 9 is a grassroots development well to be drilled off of Seaview Pad. This well will be targeting
the Tyonek sands for initial gas production.
The base plan is deviated wellbore with a kickoff point at ~550’ MD. Maximum hole angle will be 57 deg
before dropping to 10 deg and TD of the well will be 7,763’ TMD/ 6,229’ TVD.
Drilling operations are expected to commence approximately June 17th, 2021. The Hilcorp Rig # 169 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to ~1,500’ MD / 1,432’ 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 diverter and test.
3. Drill 9-7/8” hole to 1,500’ MD. Run and cement 7-5/8” surface casing.
4. ND diverter, N/U & test 11” x 5M BOP.
5. Drill 6-3/4” hole section to 7,763’ MD. Perform wiper trips as needed.
6. POOH w/drill pipe. Perform logging.
7. Make cleanout run
8. POOH laying down drill pipe.
9. Run and cmt 4-1/2” production liner.
10. PU clean out assembly and RIH to clean out 4-1/2” to landing collar
11. Displace well to 6% KCL completion fluid.
12. POOH and LD clean out assembly.
13. RIH and land 4-1/2” tieback string in liner top.
14. N/D BOP, N/U tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: Triple Combo w/e-line sonic after TD
2. Production Hole: Triple Combo w/e-line sonic after TD
3. Mud loggers from surface casing point to TD.
e Hilcorp Rig # 169 w
exploratory (See 20 AAC 25.990 (25).)
e targetinggp
the Tyonek sands for initial gas production.
Reservoir Evaluation Plan:
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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 SEAVIEW 9. 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 permits are posted on the rig floor and in Co Man office.
Regulation Variance Requests:
Variance approved based on above justification and with Seaview 8 having been drilled recently in the vacinity and Seaview 9 being a
delineation well. bjm
Hilcorp requests a variance to 20 AAC 25.033(f)(4)(C) for constant drilling fluid salinity monitoring. The risk of water flows in the gas fields of southern
Kenai Peninsula are negligible to zero as shown in the offset producing fields and in Seaview 8. Pore pressure (kick) detection using (A),(B), and (D)
is the standard with the rig. Frequent mud density/viscosity checks by the pit watcher ensure our constant data is in line with physical measurements.
Also, full mud checks are performed by the mud engineer to confirm all mud properties, including salinity. These mud checks are performed at a more
frequent rate than the required “once each tour” as specified in 20 AAC 25.033(d).
BOPs tested every 7 days. Exploration well. - bjm
Surface csg test pressure to 3000 psi (43.5% of burst). Variance to 20 AAC 25.030(e) approved. See step 15.10. bjm
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/8” x 21-1/4” x 2M Hydril MSP diverter Function Test Only
6-3/4”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M 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
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@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)
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9.0 R/U and Preparatory Work
9.1 16” conductor already set on pad.
9.2 Dig out and set impermeable cellar.
9.3 Install 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.
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10.0 N/U 21-1/4” Diverter
10.1 N/U 21-1/4” Diverter
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure. Ensure to notify AOGCC inspector to witness
function test of diverter.
x NOTE: Ensure closing time on diverter annular is in line with API RP 64:
o Annular element ID 20” or smaller: Less than 30 seconds
o Annular element ID greater than 20”: Less than 45 seconds
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
N/U 21-1/4” Diverter
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10.5 Rig 169 Orientation:
Note: Actual layout may be different on location
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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.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2” Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 9-7/8” hole section to 1,500’ MD/ 1,432’ 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 past 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 1,450’ and 1,550’MD.
x Take MWD surveys every stand drilled (60’ intervals).
11.5 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
120-1500’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
Page 14 Version 1 May, 2021
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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
11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe.
11.7 TOH with the drilling assy, handle BHA as appropriate.
11.8 RU Halliburton e-line unit and run sonic tool assembly. RD e-line.
11.9 PU 9-7/8” cleanout assembly and RIH to TD, noting any tight spots along the way. CBU at least
once at TD to ensure hole is clean for casing run. POOH and LD cleanout assembly.
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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” DWC 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” 29.7# DWC/C M/U torques
Casing OD Minimum Maximum Yield Torque
7-5/8” 21,700 ft-lbs 25,100 ft-lbs 28,500 ft-lbs
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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.
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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 10.5 ppg spacer. Test surface cmt lines.
13.5 Pump remaining 35 bbls of 10.5 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 .16239 bpf = 19.49 109.4
12.0 ppg LEAD:
9-7/8” OH x 7-5/8” Casing
annulus:
(1000’ – 120’) x .03825 bpf x
1.5 =
50.49 283.5
Total LEAD: 69.98 392.9 ft3
15.4 ppg TAIL:
9-7/8” OH x 7-5/8” Casing
annulus:
(1500’- 1000’) x .03825 bpf x
1.5 =
26.69 161.1
15.4 ppg TAIL:
7-5/8” Shoe track:
80 x .04592 bpf = 3.67 20.6
Total TAIL: 32.36 bbl 181.7 ft3
TOTAL CEMENT VOL: 102.34 bbl 574.6 ft3
Verified cement calcs - bjm
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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:
1500’- 80’ = 1420’ x .04592 bpf = 66 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.
13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 3.6 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.
Lead Slurry (1000’ MD to surface) Tail Slurry (1500’ to 1000’ MD)
System Extended Conventional
Density 12 lb/gal 15.8 lb/gal
Yield 2.40 ft3/sk 1.16 ft3/sk
Mixed Water 14.25 gal/sk 5.04 gal/sk
Mixed Fluid 14.25 gal/sk 5.04 gal/sk
Contact AOGCC about remedial plan if cement returns are not observed at surface. -bjm
Verified cement calcs - bjm.
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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
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 ND Diverter line and diverter
14.2 N/U multi-bowl wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi.
14.3 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore 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.
14.4 Run 4-1/2” BOP test assy, land out test plug (if not installed previously).
x Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
14.5 R/D BOP test assy.
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 9.0 ppg 6% KCL PHPA mud system.
14.8 R/U mud loggers for production hole section.
14.9 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section.
Provide 24 hours notice to AOGCC for witness of BOP test.
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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 all 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.
15.8 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
1,500’- 7,763’ 9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0
gg ,
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
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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)
15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
15.10 R/U and test casing to 3000 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. We are
requesting to test to 3000 psi.
15.11 Drill out shoe track and 20’ of new formation.
15.12 CBU and condition mud for LOT.
15.13 Conduct LOT. Target minimum: 14.0 ppg EMW.
Note: Sonic data from Seaview 8 calculates frac gradient at shoe depth > 15.5 ppg EMW.
Including Seaview 8’s FIT from 2018, offset field test data predicts frac gradient at the 7-5/8”
shoe to be between 12.5 – 15.5 ppg EMW. A 14.0 ppg FIT results in a 4.5 ppg kick margin
while drilling with the planned MW of 9.5 ppg.
Kick tolerance = (14.0-9.5)X(1432/6229) = 1.03
15.14 Drill 6-3/4” hole section to 7,763’ MD / 6,229’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x On the third wiper trip (around 4,500’ MD), trip back to the 7-5/8” shoe to split the hole
section in half
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
Variance to 20 AAC 25.030(e) approved. Test pressure is 43.5% of csg burst, well above MPSP
of 2180 psi.
This calculation does not take into account hole size and is therefore not
applicable, unless being compared to an index of wells with the same hole
size, DP and Drill collar configuration.
If LOT is less than 15.3 ppg EMW, the maximum TVD the well can be drilled to will be governed by the attached table. Notify AOGCC if LOT
is less than 15.3 ppg EMW before drilling 6.75" hole section.
15.3 ppg EMW minimum required to achieve desired hole depth of 6230' TVD.
Conduct LOT.
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x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed
necessary.
x Take (3) sets of formation samples every 20’.
15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe.
15.16 TOH with the drilling assy, standing back drill pipe.
15.17 LD BHA
15.18 RU E-Line and perform wireline logging plan.
15.19 RD E-Line. 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 and LD BHA
15.22 2-7/8” x 5-1/2” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
Confirm return fluid density is equal to density going in and condition mud as per 20 AAC 25.033(g) prior to tripping drillpipe - bjm.
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16.0 Run 4-1/2” Production Liner
16.1. R/U Weatherford 4-1/2” casing running equipment.
x Ensure 4-1/2” CDC HTQ x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill liner while running.
x Ensure all liner has been drifted prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U liner 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 (1) Joint with Baker landing collar bucked on pin end & threadlocked.
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 4-1/2” production liner
x Fill liner 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.
16.5. Continue running 4-1/2” production liner
4-1/2” 12.6# DWC/C-HT M/U torques
Casing OD Minimum Maximum Yield Torque
4-1/2” 5,800 ft-lbs 6,500 ft-lbs 9,240 ft-lbs
Install centralizers across entire hole section due to probable gas sands throughout the interval. bjm
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16.6. Run in hole w/ 4-1/2” liner to the 7-5/8” casing shoe.
16.7. Fill the liner 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 liner.
16.9. Circulate 2X bottoms up at shoe, ease liner thru shoe.
16.10. Continue to RIH w/ liner no faster than 1 jt./minute. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
16.11. Set liner slowly in and out of slips.
16.12. PU 4-1/2” X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight, and torque
parameters of the liner.
16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
16.14. Monitor PUW & SOW. Circulate BU if needed. Highlight zones of interest before running past,
ex: coals
16.15. Swedge up and wash last stand to bottom. P/U 2-5’ off bottom. Note slack-off and pick-up
weights.
16.16. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner 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.
16.17. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good
condition for cementing.
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17.0 Cement 4-1/2” Production Liner
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.
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, regardless of how unlikely it is that this should occur.
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.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls of 10.5 ppg spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining 15 bbls 10.5 ppg 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 40% OH excess.
Estimated Total Cement Volume:
Section: Calculation: Vol (BBLS) Vol (ft3)
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” drillpipe
annulus:
200’ x .02624 bpf = 5.25 29.5
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” liner
annulus:
200’ x .02624 bpf = 5.25 29.5
12.0 ppg LEAD:
6-3/4” OH x 4-1/2” annulus:
(7263’ – 1300’) x .02459 bpf x
1.2 =
198.39 1113.9
Total LEAD: 208.89 bbl 1172.8 ft3
15.4 ppg TAIL:
6-3/4” OH x 4-1/2” annulus:
(7763’- 7263’) x .02459 bpf x
1.2 =
17.21 96.6
15.4 ppg TAIL:
4-1/2” Shoe track:
80 x .01522 bpf = 1.22 6.8
Total TAIL: 18.43 bbl 103.5 ft3
TOTAL CEMENT VOL: 227.32 bbl 1276.3 ft3
Verified cement volumes - bjm
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Cement Slurry Design:
17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating
and reciprocating liner throughout displacement. This will ensure a high quality cement job with
100% coverage around the pipe.
17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP
dart into liner wiper plug. Note plug departure from liner hanger running tool and resume
pumping at full displacement rate. Displacement volume can be re-zeroed at this point.
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 up as required by Baker procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
17.11. Slack off total liner weight plus 30k to confirm hanger is set.
17.12. Do not overdisplace by more than ½ shoe track. Shoe track volume is 1.2 bbls.
17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from
the liner.
17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight.
17.17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the
Lead Slurry (7263’ MD to 1300’ MD) Tail Slurry (7763’ to 7263’ MD)
System Extended Conventional
Density 12 lb/gal 15.3 lb/gal
Yield 2.4 ft3/sk 1.24 ft3/sk
Mixed Water 14.09 gal/sk 5.58 gal/sk
Mixed Fluid 14.09 gal/sk 5.58 gal/sk
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pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be
enough to overcome hydrostatic differential at liner top).
17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
Backup release from liner hanger:
17.21. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will
have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure
and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear
screws.
17.22. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down
to the setting tool.
17.23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then
proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop
1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up
with workstring to release collet from the profile.
17.24. WOC minimum of 12 hours, test liner to 2500 psi and chart for 30 minutes.
test liner to 2500 psi
Circumferential Cement bond log of the 4-1/2" liner is required. It may be done as part of completion Sundry - bjm
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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 liner 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” liner tally & liner and cement report to cdinger@hilcorp.com and
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
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18.0 4-1/2” Liner Tieback Polish Run and Cleanout Run
18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker
procedure.
18.3. POOH, and LD polish mill.
18.4. M/U casing clean out assy complete with casing scraper assys for each size casing in the hole.
x 3-1/2” bit or mill
x Casing scraper & brush for 4-1/2” 12.6# tubulars
x +/- 5100’ 2-7/8” PH-6 workstring.
x Casing scraper & brush for 7-5/8” 29.7# casing
x 4-1/2” DP to surface.
18.5. TIH & clean out well to landing collar (+/- 6,250’ MD).
x Circulate as needed on trip in if string begins to take weight.
x Circulate hi-vis sweeps as necessary to carry debris out of wellbore.
x Ensure 3-1/2” bit is worked down to the landing collar.
x Space out the cleanout BHA so that the 3-1/2” bit reaches the 4-1/2” landing collar when
crossover/7-5/8” casing scraper is +/- 30’ above the 4-1/2” liner top.
18.6. After wellbore has been cleaned out satisfactorily using mud, test casing to 3000 psi / 30 min.
Ensure to chart record casing test.
18.7. Displace drilling fluid in wellbore with a hi-vis pill followed by 6% KCl completion fluid.
18.8. POOH, LDDP and workstring. Clean and clear rig floor in preparation for running tieback.
19.0 4-1/2” Tieback Run
19.1 PU 4-1/2” tieback assembly and RIH with 4-1/2” 17# L-80 CDC HTQ casing.
19.2 Install SSSV at ~500’ in tieback string. RU control line spooler and install single control line.
19.3 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space
out tieback seals in PBR.
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19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance
of seals from no-go.
19.5 Install packoff and test hanger void.
19.6 Test 4-1/2” liner and tieback to 2,500 psi / 30 min and chart for 30 minutes.
19.7 Test 7-5/8” x 4-1/2” annulus to 2,500 psi / 30 min and chart for 30 minutes.
20.0 RDMO
20.1 Install BPV in wellhead
20.2 N/D BOPE
20.3 N/U tree and test
20.4 RDMO Hilcorp Rig #169
Provide AOGCC 24 hrs notice to witness pressure test
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21.0 Diverter Schematic
16'’
Hydril V
4.30'
Hydril
MSP 21-¼ 2M
.50'
4.00'
2.67'
1.33'
4.37'
Grade Level
3.09'
DSA 16 ¾ 3M X 21 ¼ 2M
21 ¼ 2M
Spool
21 ¼ 2M
Diverter Tee
16'’ 150 outlet
4.08'
16'’ casing cut @ 64'’
below ground level
.42'
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22.0 BOP Schematic
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23.0 Wellhead Schematic
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24.0 Days Vs Depth
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25.0 Geo-Prog
5/7/2021 16:44
Well Name:Seaview 9 Survey Type KB
Field Name:Anchor Point Surface Hole:229.6
Pool Name:undefined Bottom Hole:HEC 169
State:Alaska BH Depth:18
Field Location:Onshore Coord Ref Sys:NAD27 AK4 True North 211.6
County/Parish:Kenai Peninsula Borough
Objective:
Reference Plan:
Base Glacial Drift freshwater 156 151.6 78 68.22 0.45
Sterling Middle Sand gas 357 352.6 -123 158.67 0.45
Beluga gas 500 499.6 -270 224.82 0.45
Tyonek gas 1,900 1,708.8 -1479 768.9735 0.45
T-19 Gas Pay SV 8 gas 4,500 3,165.3 -2936 1424.3895 0.45
T-90 gas 7,300 5,773.9 -5544 2598.2415 0.45
TD TD 7,763 6,229.5 -6000 2803.284 0.45
= Reservoir Objectives
= Possible Geo Hazards
TARGET RADIUS
Mud Logging:
LWD Data:
Other Log Data:
Coreing:
DATA COLLECTION REQUIREMENTS:
LWD Triple Combo;
Openhole dipole sonic for all holes sections. Dip Meter Data in both hole sections.
None
Drill a 7763' MD follow-up gas test well to the Seaview 8 well, targeting Lower Sterling, Beluga, and Tyonek gas zones.
200 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.
Seaview-9 wp05ANTICIPATED FORMATION TOPS & GEOHAZARDS
Geo Summary/
Justification:
Proposed Seaview 9 will test the anticlinal trap discovered at the Seaview 8 well. Note: directional geometries will change bu t the
well course will remain the same.
TOP NAME LITHOLOGY EXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING EASTING Est.
Pressure Gradient
Ground Elevation:
GEOLOGICAL PROGNOSIS
As-Built
x = 163,025.69 y = 2,108,532.94
TVD Ref Datum:
TVD Ref Elevation:
Planned Rig:
Rig Height:
x = 160,209.61 y = 2,106,124.10
7,763' MD 6,229' TVD
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26.0 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.
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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.
Given the volume of losses experienced in KU 42-12 when drilling through Pool 6, ensure all LCM
inventory is fully stocked before drilling out surface casing.
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.
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27.0 Hilcorp Rig 169 Layout
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28.0 FIT/LOT 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.
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29.0 Choke Manifold Schematic
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30.0 Casing Design Information
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31.0 6-3/4” Hole Section MASP
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32.0 Spider Plot (Governmental Sections)
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33.0 Surface Plat (As-Built NAD27)
!
-1500-7500750150022503000375045005250600067507500True Vertical Depth (1500 usft/in)-3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250Vertical Section at 229.45° (1500 usft/in)Seaview 9 wp05 Tgt116"7 5/8" x 9 7/8"4 1/2" x 6 3/4"500100015002000250030003500400045005000550060006500700075007763Seaview 9 wp05Start Dir 4º/100' : 550' MD, 550'TVDEnd Dir : 1972.22' MD, 1749.79' TVDStart Dir 4º/100' : 4144.68' MD, 2936.53'TVDStart Dir 2º/100' : 4566.9' MD, 3215.6'TVDEnd Dir : 6066.9' MD, 4559.59' TVDTotal Depth : 7762.68' MD, 6229.6' TVDBase Glacial DriftSterling MiddleBelugaTyonekT-19T-90Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Seaview 9211.60+N/-S+E/-WNorthingEasting LatittudeLongitude0.000.002108532.940 163025.69059° 45' 32.8703 N 151° 49' 39.6394 WSURVEY PROGRAMDate: 2021-02-17T00:00:00 Validated: Yes Version: Depth FromDepth ToSurvey/PlanTool18.00 1500.00 Seaview 9 wp05 (Seaview 9) 3_MWD+AX+Sag1500.00 7762.68 Seaview 9 wp05 (Seaview 9) 3_MWD+AX+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation151.60 -78.00 151.60 Base Glacial Drift352.60 123.00 352.60 Sterling Middle495.60 266.00 495.60 Beluga1703.60 1474.00 1891.14 Tyonek3216.60 2987.00 4568.21 T-195778.60 5549.00 7304.72 T-90REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Seaview 9, True NorthVertical (TVD) Reference:WELL @ 229.60usft (HEC 169)Measured Depth Reference:WELL @ 229.60usft (HEC 169)Calculation Method: Minimum CurvatureProject:Seaview ProspectSite:SeaviewWell:Seaview 9Wellbore:Seaview 9Design:Seaview 9 wp05Seaview ProspectSeaviewSeaview 9Seaview 9Seaview 9 wp055.765CASING DETAILSTVD TVDSS MD Size Name120.00 -109.60 120.00 16 16"1431.87 1202.27 1500.00 7-5/8 7 5/8" x 9 7/8"6229.60 6000.00 7762.68 4-1/2 4 1/2" x 6 3/4"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.002 550.00 0.00 0.00 550.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 550' MD, 550'TVD3 1972.22 56.89 229.48 1749.79 -422.31 -494.03 4.00 229.48 649.93 End Dir : 1972.22' MD, 1749.79' TVD4 4144.68 56.89 229.48 2936.53 -1604.69 -1877.21 0.00 0.00 2469.60 Start Dir 4º/100' : 4144.68' MD, 2936.53'TVD5 4566.90 40.00 229.40 3215.60 -1809.38 -2116.39 4.00 -179.83 2784.42 Seaview 9 wp05 Tgt1 Start Dir 2º/100' : 4566.9' MD, 3215.6'TVD6 6066.90 10.00 229.40 4559.59 -2217.23 -2592.23 2.00 180.00 3411.13 End Dir : 6066.9' MD, 4559.59' TVD7 7762.68 10.00 229.40 6229.60 -2408.86 -2815.82 0.00 0.00 3705.59 Total Depth : 7762.68' MD, 6229.6' TVD
-3000-2667-2333-2000-1667-1333-1000-667-3330333South(-)/North(+) (500 usft/in)-3333 -3000 -2667 -2333 -2000 -1667 -1333 -1000 -667 -333 0 333 667 1000West(-)/East(+) (500 usft/in)Seaview 9 wp05 Tgt116"7 5/8" x 9 7/8"4 1/2" x 6 3/4"25050075010001250
15001750200022502500275030003250350037504000425045004750500052505500575060006230Seaview 9 wp05Start Dir 4º/100' : 550' MD, 550'TVDEnd Dir : 1972.22' MD, 1749.79' TVDStart Dir 4º/100' : 4144.68' MD, 2936.53'TVDStart Dir 2º/100' : 4566.9' MD, 3215.6'TVDEnd Dir : 6066.9' MD, 4559.59' TVDTotal Depth : 7762.68' MD, 6229.6' TVDProject: Seaview ProspectSite: SeaviewWell: Seaview 9Wellbore: Seaview 9Plan: Seaview 9 wp05WELL DETAILS: Seaview 9211.60+N/-S +E/-W Northing EastingLatittudeLongitude0.00 0.00 2108532.940 163025.690 59° 45' 32.8703 N 151° 49' 39.6394 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Seaview 9, True NorthVertical (TVD) Reference: WELL @ 229.60usft (HEC 169)Measured Depth Reference:WELL @ 229.60usft (HEC 169)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name120.00 -109.60 120.00 16 16"1431.87 1202.27 1500.00 7-5/8 7 5/8" x 9 7/8"6229.60 6000.00 7762.68 4-1/2 4 1/2" x 6 3/4"
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0.001.503.004.50Separation Factor0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100Measured DepthSeaview 10 wp03No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Seaview 9 NAD 1927 (NADCON CONUS)Alaska Zone 04211.60+N/-S+E/-W NorthingEastingLatittudeLongitude0.000.002108532.940 163025.690 59° 45' 32.8703 N 151° 49' 39.6394 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Seaview 9, True NorthVertical (TVD) Reference:WELL @ 229.60usft (HEC 169)Measured Depth Reference:WELL @ 229.60usft (HEC 169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-02-17T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 1500.00 Seaview 9 wp05 (Seaview 9) 3_MWD+AX+Sag1500.00 7762.68 Seaview 9 wp05 (Seaview 9) 3_MWD+AX+Sag0.0030.0060.0090.00120.00Centre to Centre Separation (50.00 usft/in)0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100Measured DepthSeaview 10 wp03Seaview 8GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 7762.68Project: Seaview ProspectSite: SeaviewWell: Seaview 9Wellbore: Seaview 9Plan: Seaview 9 wp05Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name120.00 -109.60 120.00 16 16"1431.87 1202.27 1500.00 7-5/8 7 5/8" x 9 7/8"6229.60 6000.00 7762.68 4-1/2 4 1/2" x 6 3/4"
English Kick Tolerance
KICK TOLERANCE CALCULATIONS
WELL NAME Seaview 9 wp05
Well Depth 6230 ft Hole Size 6.75 inches
Casing Depth 1432 Casing Size 7.625 inches ID = 6.878 in
Fracture grad.15.3 ppg Casing Weight 29.7 lb/ft
Current LOP 432 psi HWDP Size 4.5 inches
Current mud weight 9.5 ppg DP Size 4.5 inches
Estimated Formation Grad.9.15 ppg DC Size 4.75 inches
Estimated formation pressure 2964 psi
Mud Hydrostatic pressure at TD 3078 psi Ann.Cap. Length Ann.Cap.
Est Friction Pressure 0 psi bbl/ft ft bbls
Choke Operator error 0 psi DC/Open Hole 0.0223 185 4.1
Influx Gradient 0.1 psi/ft HWDP/Open Hole 0.0246 560 13.8
Collar Length 185 ft DP/ Open Hole 0.0246 4053 99.7
HWDP Length 560 ft DP/ Casing 0.0263 1432 37.6
BOP/Wellhead rating 5000 psi Totals 6230 155.2
Casing Burst Rating 5880 psi
Max Influx length 1096 ft Max Allow. Ann. Surf.Press 432 psi
Max Influx Volume @Shoe 27.0 bbls Max. BHP 3078 psi
Max Influx volume @ TD 26.5 bbls
Max Influx Shoe Vol @ BHP 10.0 bbls KICK TOLERANCE 10.0 BBL
KT Factor 1.33
NOTES :
- Assumes the well is vertical
- Assumes influx is a gas obeying gas law regardless of the influx gradient used.
- Influx gradient used to calculate maximum influx length only.
- Volume adjustment from shoe to TD uses P1*V1 = P2*V2 and ignores T & Z.
- Assumes all BHA is outside the casing shoe
- In certain specific development areas known to have essentially gas free crude, the lesser of
TD or shoe influxes may be used.
LOT vs. Allowable TVD
Seaview 9 LOT test result vs. allowable TVD to maintain minimum 10 bbl kick, assuming 9.5 ppg mud
weight and zero kick intensity (swab kick). This table assumes a vertical wellbore, so is conservative.
Hole angle at the shoe would increase the allowable kick volume.
This table, prepared by Hilcorp and verified by AOGCC, shows the max allowable depth of the well if 15.3
ppg EMW LOT pressure is not achieved.
Planned depth is 6230’ TVD.
LOT Value TD (TVD) TD (MD wp05)
PLAN 15.3 6230 7763
15.2 6099 7630
15.1 5953 7482
15.0 5808 7335
14.9 5664 7188
14.8 5522 7044
14.7 5381 6901
14.6 5242 6760
14.5 5104 6620
14.4 4967 6481
14.3 4832 6344
14.2 4698 6207
14.1 4566 6073
14.0 4435 5940
13.9 4305 5806
13.8 4177 5672
13.7 4050 5538
13.6 3925 5403
13.5 3801 5267
1
Carlisle, Samantha J (CED)
From:Frank Roach <Frank.Roach@hilcorp.com>
Sent:Wednesday, June 23, 2021 4:38 PM
To:McLellan, Bryan J (CED)
Cc:Monty Myers
Subject:RE: [EXTERNAL] Seaview 9 FIT
Bryan,
Correct.ThetablesentintheJune10emailisbasedonthebottomͲholehydrostaticofa9.5ppgmudasencounteredin
aswabkickscenario.
Thecommentsintheemailweretoclarifythedifferenceinthetwosubmittedkicktolerancecalculationsheets.Inthe
firstsheetIsent(June2email),formationpressurewasshownasthepredictedporepressure(0.45psi/ftgradient,
8.65ppgEMW).IntheupdatedkicktolerancecalcsheetthatwassentonJune9,theformationpressureisenteredas
9.15ppgEMWtoreflect0.5ppgoverporepressureandhighlightingtheinitialplanofdrillingwithamudweightthat’s
greaterthan0.5ppgoverpredictedporepressure.Thecommentsintheemailbodyweretohighlightthatchange.
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Sent:Wednesday,June23,202116:09
To:FrankRoach<Frank.Roach@hilcorp.com>
Cc:MontyMyers<mmyers@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
Frank,
Iwantedtoclarifythatyourtableisbasedonabottomholepressureequaltomudhydrostaticof9.5ppgEMW,as
wouldbeencounteredinaswabͲkickscenario.Itisnotbasedonanticipatedreservoirpressureof0.5ppgover
prognosis,asyoumentionedbelowonyourJune9email.
Also,asdiscussed,theKicktolerancefactorcalculatedinyourspreadsheetisnotrelevantbecauseitdoesnottakeinto
accountHolesizeordrillpipesize,whicharecriticalfactorswhendeterminingkicktolerance.TheAOGCCdoesnot
recognizeKTFactorinourdeterminationofkicktolerancelimits.
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
From:FrankRoach<Frank.Roach@hilcorp.com>
Sent:Thursday,June10,20213:12PM
To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
2
Cc:MontyMyers<mmyers@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
Bryan,
Hereyougosir.SubsequentTVD/TDbasedontheLOTachieved.
Seaview9LOTResultsvs.TD(Maintain10bblKT)
LOTValueTD(TVD)TD(MDwp05)
PLAN15.362307763
15.260997630
15.159537482
15.058087335
14.956647188
14.855227044
14.753816901
14.652426760
14.551046620
14.449676481
14.348326344
14.246986207
14.145666073
14.044355940
13.943055806
13.841775672
13.740505538
13.639255403
13.538015267
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Sent:Thursday,June10,202110:54
To:FrankRoach<Frank.Roach@hilcorp.com>
Cc:MontyMyers<mmyers@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
ThanksFrank.Thislooksgreat.
I’dlikeyoutosubmitatableorchartshowingtheallowableTVDofthewellvs.achievedLOTpressure.Thatway
everyoneisonboardwiththe10bblkicktoleranceexpectationbeforeyouspud,andwewon’thavetodebatethedepth
overtheweekendwiththerigwaitingforananswer.TheanswerwillalreadybeapprovedinthePTD.
Thankyou
BryanMcLellan
SeniorPetroleumEngineer
3
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
From:FrankRoach<Frank.Roach@hilcorp.com>
Sent:Wednesday,June9,20212:06PM
To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Cc:MontyMyers<mmyers@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
Bryan,
AppreciatethetextandphonediscussiononSeaview9today.Aswediscussed,pleaseseetheattachedupdatedkick
tolerancecalculationforthe7Ͳ5/8”surfacecasingshoe.Thechangesareasfollows:
Ͳ Estimatedformationpressureincalculationis9.15ppgEMW.
o Thistakesa0.5ppgintensityovertheexpectedporepressureof8.65ppgEMW.
Ͳ Mudweightusedinthecalculationis9.5ppg.
o Thiswillallowustodustupthemudweight,ifneeded,forholestability.
TheplanremainstoperformaLOTbelowthe7Ͳ5/8”shoesowewillknowtheformationstrengthforfuturewells.
Letmeknowifyouneedanythingadditional.
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Sent:Thursday,June3,202111:55
To:FrankRoach<Frank.Roach@hilcorp.com>
Cc:MontyMyers<mmyers@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
Frank,
Kicktolerance,amongotherfactors,determinesthelengthofholethatcanbesafelydrilledbetweeneachcasing
shoe.SinceHilcorpdoesnotconsideritasafactorindeterminingcasingsetpointsintheirwelldesign,theAOGCCwill
requireaminimumvalueforkicktoleranceforthiswellat10bbls,assuminga0.5ppgkickintensityaboveplannedmud
weight.Duringdrilling,thekicktoleranceshouldberecalculatedanytimethereisachangeinmudweightandafter
performingaLOTorFIT.TotaldepthofthewellmaybelimitedafterperformingtheLOT/FITiftheabovecriteriaare
notmet.
PleasesubmitawelldesignforSeaview9thatmeetstheaboveminimumkicktolerancecriteria.
Thankyou
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
4
From:FrankRoach<Frank.Roach@hilcorp.com>
Sent:Wednesday,June2,202111:08PM
To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Cc:MontyMyers<mmyers@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
Bryan,
ThereisnotaminimumsetkicktolerancethatHilcorpmandates.ForthemajorityofthegaswellsontheKenai
Peninsula,weusea2ͲstringwelldesignwherethetwocriticaldepthsaresurfacecasingandTD.
Inrelationtothesurfacecasingdepth,thecriteriathatbracketthisdepthisensuringwe’redeepenoughtohave
sourcesofdrinkingwatercoveredandthatwe’reshallowenoughtohavesomestandoffabovethetargetedreservoir
sandsoutlinedbythegeologist/reservoirengineer.Fromthoseboundaries,Icalculatekicktolerancefactorandfollow
upwiththekicktolerancevolumeusingthatspreadsheetattachedinthepreviousreply.
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Sent:Wednesday,June2,202115:42
To:FrankRoach<Frank.Roach@hilcorp.com>
Cc:MontyMyers<mmyers@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
ThanksFrank.
DoesHilcorpusesomeminimumKickTolerancevalueasoneofyourcriteriaforpickingcasingsettingdepth?
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
From:FrankRoach<Frank.Roach@hilcorp.com>
Sent:Wednesday,June2,20213:33PM
To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Cc:MontyMyers<mmyers@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
Bryan,
Thanksforthephonediscussionearlier.SinceMontywaspartofthecall,I’veincludedhimontheemailchainsohe’sin
theloop.
5
Aswediscussed,pleaseseetheattachedExcelsheetIuseforkicktolerancecalcs.It’snotlockedsoyoucangothrough
andseewheretheformulasgettheirvalues.
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Sent:Wednesday,June2,202111:32
To:FrankRoach<Frank.Roach@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9FIT
Frank,
Thiswelldesigndoesnotappeartoprovideadequatekicktolerance.Theformulayoupresenteddoesnottakeinto
accounttheholesizeorDPOD,sonotsurethatwecanuseitinameaningfulway.
I’mhappytodiscusscalculationassumptionsandoptionsforincreasingkicktolerance.
Regards
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
From:FrankRoach<Frank.Roach@hilcorp.com>
Sent:Wednesday,May26,20218:40AM
To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Subject:RE:[EXTERNAL]Seaview9FIT
Bryan,
ALOTistheplanafterdrillingoutthe7Ͳ5/8”surfacecasingshoetrack,9Ͳ7/8”ratholeand20’(minimum)ofnew
formation.Onpage23oftheprogram,steps15.12and15.13shouldstatetoperformaLOT.
The14.0ppgEMWreferencedasatargetminimumandusedinthe“Note”forthekicktolerancecalculations.Thisisthe
intheprogramtogivetherigteamavaluethatifwedon’treachwiththeLOT,tostopandcallforfurtherdiscussion.
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Sent:Tuesday,May25,202113:31
To:FrankRoach<Frank.Roach@hilcorp.com>
Subject:[EXTERNAL]Seaview9FIT
6
Frank,
We’vebeenlookingattherecentapplicationforSeaviewpoolrules.TherequesttocominglefromTDallthewayto
343’TVDisgoingtohavesomeconditionsrelatedtoporepressureofthedeepersandsvs.fracgradientoftheshallower
sands.Idon’tthinkyouhaveanyfracgradientdataintheSeaviewareasinceSeaview8onlyperformedanFITto12.5
ppgandyouareplanningtoFITto14ppginSeaview9.Ahigherknownfracgradientmayresultinallowingmore
comingling.Isthereanyreasonyoudon’twanttoperformaLOTonSeaview9togetagooddatapointwithinthe
field?
Regards
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
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
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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,
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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
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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,
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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
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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,
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the recipient should carry out such virus and other checks as it considers appropriate.
1
Carlisle, Samantha J (CED)
From:McLellan, Bryan J (CED)
Sent:Wednesday, June 23, 2021 4:55 PM
To:Frank Roach
Cc:Regg, James B (CED)
Subject:RE: [EXTERNAL] Seaview 9 - exploration well
Frank,
WewillapprovethisvariancerequestforSeaview9forthereasonsyoustatebelowandsinceitisadelineationwell,
withSeaview8havingbeendrilledinthevicinity.
WewillnotapprovethesamevarianceforWhiskeyGulch1,whichisaWildcatexplorationwell.
Regards
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
From:FrankRoach<Frank.Roach@hilcorp.com>
Sent:Tuesday,June22,20219:06AM
To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Subject:RE:[EXTERNAL]Seaview9Ͳexplorationwell
Bryan,
Understoodabout20AAC25.033(g)applyingtothewholewellpathonanexplorationwell.Onyoursuggestion,I’malso
thinkingit’sobvioustotherigcrewstocontinuecirculatingifweightͲindoesn’tequalweightͲout,butIwillquizthem
whenIheaddownforthepreͲspudmeeting.
For20AAC25.033(f)(4),rig169(andthesister,rig147)isequippedwiththefollowingforconstantmonitoringand
communicationtotherigfloorper20AAC25.033(f)(5):
(A) GasEntrainedinDrillingFluidthroughrig’sgaswatchsystemandmudlogger’sgassampling
(B) FluidDensitythroughPWDinbothholesections.
(D) RateOfPenetrationthroughrig’sPasonsystem
(E) Fromoffsetfieldsandourtargetformations,hydrogensulfidedoesnotexist.TherigmaintainsH2Sdetection
per20AAC25.066andistestedduringeveryBOPEtesttoconfirmfunctionality.Therigalsohasstandardand
emergencyoperatingproceduresshouldH2Sbeencountered.
Hilcorprequestsavarianceto20AAC25.033(f)(4)(C)forconstantdrillingfluidsalinitymonitoring.Theriskofwater
flowsinthegasfieldsofsouthernKenaiPeninsulaarenegligibletozeroasshownintheoffsetproducingfieldsandin
Seaview8.Porepressure(kick)detectionusing(A),(B),and(D)isthestandardwiththerig.Frequentmud
density/viscositychecksbythepitwatcherensureourconstantdataisinlinewithphysicalmeasurements.Also,full
mudchecksareperformedbythemudengineertoconfirmallmudproperties,includingsalinity.Thesemudchecksare
performedatamorefrequentratethantherequired“onceeachtour”asspecifiedin20AAC25.033(d).
2
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Sent:Monday,June21,202115:54
To:FrankRoach<Frank.Roach@hilcorp.com>
Subject:RE:[EXTERNAL]Seaview9Ͳexplorationwell
Frank,
Idon’tseeanyproblemwithusingacombinationofcomponentsformonitoringtheitemsin20AAC25.033(f)(4),solong
astheyaremonitoredandrecordedandyouaresetuptocommunicateperpart(5).
Asfor20AAC25.033(g),Ifiguredthiswasprobablypartofyourstandardprocedure,butwantedtomakesureyouknew
itwasarequirementssincethewellstatuswaschanged.Therequirementinpart(g)isactuallynotexclusiveto
explorationwells.Itappliestoanywellwhenhydrocarbonzonesareexposedinopenhole,butitappliesfortheentire
wellwhendrillingexplorationwells.
Onesuggestionforthestandardrigprocedurebelow,andI’mnotsayingthisisarequirement:The“AssignedCorrective
Action”inthethirdcolumnisprettymuchreiteratingwhatwassaidinthe“JobProcedure”inthefirstcolumn.Iwould
havethoughtthecorrectiveactionwouldsaysomethinglike:“Continuecirculatingandconditioningmuduntilmud
weightisthesamegoinginandcomingout.”Orsomethinglikethat.Butmaybeit’sobvioustotherigcrewthatthey
needtodothat.Youdon’tneedtorespondtomeonthis,justsomethingtoconsider.
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
From:FrankRoach<Frank.Roach@hilcorp.com>
Sent:Monday,June21,20211:26PM
To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Subject:RE:[EXTERNAL]Seaview9Ͳexplorationwell
Bryan,
Sorryforthelatereply.Ihaveacouplequestionsabouttheitem1below.For20AAC25.033(f)(4),doesithavetobean
exclusiveunitforthesemeasurementsorcanitbeacombinationofcomponentsthatcanbeusedaslongasitalso
satisfies20AAC25.033(f)(5)?
Forthesecondnote,therequirementofperformingamudcheckfordensityandensuringthemudweightinandout
arewithintoleranceispartoftherig’sstandardprocedurefortripping.BelowisthelinepulleddirectlyfromtherigͲsite
procedure:
3
Iproposethathavingtheabovestepintherigproceduresatisfies20AAC25.033(g)anditem2below.
Thanksinadvancefortheadditionalinfoonthefluidmonitoringrequirement.
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov>
Sent:Thursday,June17,202116:13
To:FrankRoach<Frank.Roach@hilcorp.com>
Subject:[EXTERNAL]Seaview9Ͳexplorationwell
Frank,
Seaview9meetsthedefinitionofanexplorationwellin20AAC25.990(25)andisbeingclassifiedassuch.Thereare
someadditionalregulationsfordrillingexplorationwells.
1. Pleaseconfirmthatrig169meetstherequirementsof20AAC25.033(f)(4)&(5)?
2. Also,pleaseincludetherequirementsofsection20AAC25.033(g)inyourprocedure.
Thanks
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
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Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both
well name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
Seaview Field
X
Seaview Undefined Gas Pool
221-025
X
Seaview 9
Hilcorp Alaska, LLC
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