Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
Loading...
HomeMy WebLinkAboutCO 044 ACONSERVATION ORDER 44A
Middle Ground Shoal
1. August 16, 2016 Hilcorp Alaska, LLC application to amend CO 44
2. August 19, 2016 Notice of Public Hearing, Affidavit of Publication, Email list, bulk
mail list
3. September 20, 2016 Transcript, Exhibit and sign in sheet
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION C(
333 West 7th Avenue
Anchorage Alaska 99501
Re: THE APPLICATION OF Hilcorp Alaska, LLC )
Docket Number: CO -16-016
to amend Conservation Order 44 Middle Ground )
Conservation Order No. 44A
Shoal Field )
Middle Ground Shoal Unit
Middle Ground Shoal Field
Middle Ground Shoal Oil Pool
Middle Ground Shoal Gas Pool
Kenai Borough, Alaska
January 12, 2017
IT APPEARING THAT:
1. By application received August 17, 2016, Hilcorp Alaska, LLC (Hilcorp), as owner and operator
of the Middle Ground Shoal (MGS) Field, requested an amendment to Conservation Order No. 44
(CO 44) to modify the Affected Area of the order, eliminate spacing requirements, combine the
existing oil pools into a single oil pool, and define a new gas pool. Hilcorp also requested several
other minor modifications to the existing order.
2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC)
scheduled a public hearing for September 20, 2016.
3. On August 18, 2016, the AOGCC published notice of that hearing on the State of Alaska's Online
Public Notice website and on the AOGCC's website, electronically transmitted the notice to all
persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all
persons on the AOGCC's mailing distribution list. On August 19, 2016, the notice was published
in the ALASKA DISPATCH NEWS.
4. No comments on the application were received.
5. The hearing commenced at 9:00 a.m. on September 20, 2016. Evidence was received from
representatives of Hilcorp.
6. The record was closed after the hearing.
FINDINGS:
1. CO 44 was issued on July 19, 1967.'
2. The MGS Field was originally operated by two separate companies. The southern portion of the
field around the Dillon platform was unitized as the South Middle Ground Shoal Unit (SMGSU).
The remainder of the field was not unitized.
3. In 2015, Hilcorp became sole owner and operator of the MGS Field.
4. On May 12, 2016, Hilcorp applied to the Department of Natural Resources (DNR) to expand the
SMGSU to cover the entire MGS Field and to rename the expanded unit as the Middle Ground
Shoal Unit (MGSU).
5. On September 21, 2016, DNR approved Hilcorp's request to expand and rename the unit.
'The Affected Area of CO 44 was modified by CO 53 on September 7, 1967, and further modified by CO
54 on October 12, 1967.
CO 44A
January 12, 2017
Page 2 of 6
6. Hilcorp has applied to modify the Affected Area of CO 44 so that it matches the current MGSU
boundaries. The primary change would be in the southern portion of the MGS Field where the
SMGSU has been contracted over the years.
7. Rule 1 of the current CO prohibits more than two wells being completed in a governmental quarter
section. Because of this requirement, 51 spacing exceptions have been issued for the MGS Field.
8. Rule 1 was written based on old drilling practices using vertical wells. Current drilling practices
make frequent use of highly deviated and horizontal wells that do not fit into the established well
spacing rule.
9. The MGS Field is mature. The size of infill drilling targets is now smaller than the 80 acres
envisioned in CO 44.
10. Hilcorp proposes that there be no well spacing restrictions within the modified Affected Area
except,
a. no gas well shall be drilled or completed less than 1,500 feet from the exterior boundary of
the Affected Area unless the owner and landowner are the same on both sides of the line;
b. no oil well shall be drilled or completed less than 500 feet from the exterior boundary of the
Affected Area unless the owner and landowner are the same on both sides of the line; and
C. on written request by the Operator, the AOGCC may administratively consider and approve
modifications to well spacing when justified.
IL Rule 2 defines seven oil pools (MGS Oil Pools A through F) within the MGS Field, but does not
define any gas pools.
12. Historically, the field has been operated—and production has been reported—as follows: MGS A;
MGS B, C, and D (commingled); and MGS E, F, and G (commingled).
13. Hilcorp proposes combining all seven oil pools into a single oil pool. Hilcorp also proposes to
establish a new gas pool that lies shallower than the oil pool and encompasses all potentially
productive gas sands.
14. There are three distinct gas bearing intervals identified in the MGS Field area, these are identified
by Hilcorp in the MGS-18746-1 well as the:
a. Upper Gas Interval, which extends from 1,459 feet measured depth (MD) to the coal 31
marker at 5,126 feet MD;
b. Middle Gas Interval, which extends from the coal 31 marker to the coal 41 marker at 6,437
feet MD; and
C. Lower Gas Interval, which extends from the coal 41 marker to the top of the proposed oil
pool at 7,016 feet MD.
15. Gas sands in the Cook Inlet basin tend to be laterally discontinuous and require more than one well
per governmental section in order to maximize ultimate recovery.
16. Only the Middle Gas Interval has produced gas, approximately 16 BSCF to date, and this interval
is estimated to be 60% depleted. The Upper Gas Interval has reported gas shows, but no production.
The Lower Gas Interval has no reported gas shows and no production.
CO 44A
January 12, 2017
Page 3 of 6
17. Rule 3 allows the downhole commingling of oil production referenced in Finding 12 above but
prohibits all other downhole commingling of production. Similar restrictions apply to downhole
commingling of injection for EOR purposes.
18. There have been in excess of 15 separate downhole commingling authorizations for individual
wells issued for the MGS Field. These authorizations have approved all possible variations of
downhole commingling.
19. The MGS has produced for nearly 50 years. Production peaked at about 45 thousand barrels of oil
per day (MBOPD) in June 1968, and has declined to less than 2 MBOPD today. Few wells are
currently producing more than 100 barrels of oil per day (BOPD), and the top producer is
approximately 225 BOPD. Cumulative production is approximately 200 million barrels of oil. All
production is currently assigned to the MGS E, F, and G Oil Pools.
20. Hilcorp proposes eliminating the rules regarding downhole commingling of production and
injection since downhole commingling would no longer be a concern if the seven oil pools are
combined into a single oil pool.
21. Rule 5 approves the drilling of a lease -line well between two separate leases in the MGS Field.
Hilcorp proposes eliminating this rule as it is no longer relevant since the entire field has been
unitized.
22. Rule 6 contains a clause that authorizes the AOGCC to approve administratively:
a. conversion of a well to or from injection service;
b. drilling of an injection well;
C. drilling of wells not otherwise authorized by CO 44; and
d. downhole commingling of production or injection in a wellbore.
23. Rule 6 predates AOGCC's adoption of an underground injection control program.
24. Rule 7 provides specific casing requirements for the MGS Field. Hilcorp proposes to repeal these
requirements and follow statewide casing and cementing requirements. It also proposes an
alternative method of using cement bond logs or water flow logs for demonstrating zonal isolation
on a case-by-case basis.
25. Rules 8 and 9 prescribe a bottom -hole pressure survey requirement and a gas -oil ratio test
requirement for all producing wells that have very specific testing procedures.
26. Hilcorp proposes to eliminate the bottom -hole pressure testing rule because the field is mature and
information for reservoir management purposes is available from other reports required by
regulations.
27. Hilcorp proposes to eliminate the gas -oil ratio testing rule because regulations already require every
producing well to be tested at least monthly and production be allocated to each individual well
accordingly.
CO 44A
January 12, 2017
Page 4 of 6
CONCLUSIONS:
1. Modifying the Affected Area to coincide with the current unit boundary is appropriate because that
unit boundary conforms to the known productive limits of the MGS Field development.
2. Eliminating interwell spacing requirements for the MGS Field will make further development of
the field more viable and lead to increased recovery.
3. Correlative rights will be protected by restricting oil and gas wells from being completed within
500 and 1,500 feet, respectively, of a property line unless the owner and landowner is the same on
both sides of the line.
4. Maintaining seven distinct oil pools in the mature MGS Field provides no benefit for reservoir
management and monitoring, may hinder further development of the field and may reduce ultimate
recovery.
5. Establishing a new gas pool with rules governing development of the shallow gas sands in the MGS
Field will allow more efficient development and improve ultimate recovery.
6. Because the Lower Gas Interval within the new gas pool has no reported gas shows and no
production it should not be included.
7. Combining the existing seven oil pools into a single oil pool will eliminate the need for a rule that
governs commingling.
8. Eliminating the lease -line well rule of Rule 5 is appropriate because the Affected Area will
correspond to a single unit managed by a single operator.
9. Replacing Rule 6 with AOGCC's standard administrative approval rule will simplify
administration of the MGS Field.
10. The AOGCC's existing regulations concerning casing and cementing of wells ensure proper well
construction and integrity, and prevent migration of fluids between zones. Hilcorp's proposed
revision to address zonal isolation in instances where a well cannot be cemented in accordance with
the regulations will ensure proper isolation of zones that are capable of flow.
11. Due to the maturity of the MGS field Rule 8 provides little, if any, reservoir management and
monitoring benefit over reporting already required by regulations.
12. Current regulations eliminate the need for a rule that governs gas -oil ratio tests
NOW THEREFORE IT IS ORDERED:
The development and operation of the Middle Ground Shoal Oil Pool and the Middle Ground Shoal Gas
Pool are subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not
superseded by these rules. Conservation Orders 44, 53, 54, 56, 62, 66, 89, 99, 163, and 236 are hereby
superseded by this order and their records incorporated by reference into this order. All Administrative
Approvals issued under CO 44, except CO 44.11, are hereby revoked.
CO 44A
January 12, 2017
Page 5 of 6
Affected Area: Seward Meridian
Township
7 North, Range
13 West
Section 10: NE 1/4 ofNE1/4
Section 11: NW l/4 of N W 1 /4
Section 2: WI/2 of NEI/4, N W l /4, and SWI /4
Section 3: SETA ofNEI/4 and El/2 of SEI/4
Township
8 North, Range
12 West
Sections 6-7: All
Township
8 North, Range
13 West
Sections 1-2: All
Sections 11-15: All
Sections 22-26: All
Section 35: Nel/4, NWI/4, SWIA, and WI/2 of
SE 1/4
Township
9 North, Range
12 West
Section 19: SEI/4 of SWIA and SWI/4 of SETA
Sections 30-31: All
Township
9 North, Range
13 West I
Sections 25 and 36: All
Rule 1 Well Spacine (Revised this order)
There shall be no well spacing restrictions within the Affected Area, except:
No gas well shall be drilled or completed less than 1,500 feet from the exterior boundary of the
Affected Area unless the owner and landowner are the same on both sides of the line.
No oil well shall be drilled or completed less than 500 feet from the exterior boundary of the
Affected Area unless the owner and the landowner are the same on both sides of the line.
Rule 2 Pool Designation (Revised this order)
The Middle Ground Shoal Oil Pool shall comprise the oil-bearing intervals common to and
correlating with the interval between the measured depth of 5,419 feet and 9,198 feet in well MGS
State 17595-4 (Permit to Drill Number 164-006).
The Middle Ground Shoal Gas Pool shall comprise the gas -bearing intervals common to and
correlating with the interval between the measured depth of 1,459 feet and 6,437 feet in well MGS
State 18746-1 (Permit to Drill Number 165-022).
Rule 3 Permissible Commingling (Repealed this order)
Rule 4 Fluid Infection (Repealed this order)
Rule 5 Lease Line Well (Repealed this order)
Rule 6 Administrative Approval (Renamed and revised this order)
Upon proper application, or its own motion, and unless notice and public hearing are otherwise required,
the Commission may administratively waive the requirements of any rule stated herein or administratively
amend this order as long as the change does not promote waste orjeopardize correlative rights, is based on
sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into
freshwater aquifers.
CO 44A
January 12, 2017
Page 6 of 6
Rule 7 Casine and Cementing Requirements (Revised this order)
Wells shall be completed in accordance with the provisions of 20 AAC 25.030.
Due to significant loss zones previously encountered in the intermediate casing of some wells,
alternative methods (cement bond log or water flow log) may be considered by the AOGCC on a
case-by-case basis as an alternative means to validate zonal isolation.
Rule S Bottom Hole Pressure Surveys (Repealed this order)
Rule 9 Gas -Oil Ratio Tests (Repealed this order)
DONE at Anchorage, Alaska and dated January 12, 2017.
Cathy rste Hisa h
m�
Chair, Commissioner omissir
TION AND APPEAL
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC
grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it.
If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or
decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within
10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration
are FINAL and may be appealed to superior court The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30
days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the
appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within
33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period;
the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day
that does not fall on a weekend or state holiday.
David W. Duffy
Landman
Hilcorp Alaska, LLC
P.O. Box 244027
Anchorage, AK 99524-4027
�G4
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7th Avenue
Anchorage Alaska 99501
Re: THE APPLICATION OF Hilcorp Alaska, LLC ) Docket Number: CO -16-016
to amend Conservation Order 44 Middle Ground ) Conservation Order No. 44A
Shoal Field ) Middle Ground Shoal Unit
Middle Ground Shoal Field
Middle Ground Shoal Oil Pool
Middle Ground Shoal Gas Pool
Kenai Borough, Alaska
January 12, 2017
IT APPEARING THAT:
1. By application received August 17, 2016, Hilcorp Alaska, LLC (Hilcorp), as owner and operator
of the Middle Ground Shoal (MGS) Field, requested an amendment to Conservation Order No. 44
(CO 44) to modify the Affected Area of the order, eliminate spacing requirements, combine the
existing oil pools into a single oil pool, and define a new gas pool. Hilcorp also requested several
other minor modifications to the existing order.
2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC)
scheduled a public hearing for September 20, 2016.
3. On August 18, 2016, the AOGCC published notice of that hearing on the State of Alaska's Online
Public Notice website and on the AOGCC's website, electronically transmitted the notice to all
persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all
persons on the AOGCC's mailing distribution list. On August 19, 2016, the notice was published
in the ALASKA DISPATCH NEWS.
4. No comments on the application were received.
5. The hearing commenced at 9:00 a.m. on September 20, 2016. Evidence was received fi-om
representatives of Hilcorp.
6. The record was closed after the hearing.
FINDINGS:
1. CO 44 was issued on July 19, 1967.'
2. The MGS Field was originally operated by two separate companies. The southern portion of the
field around the Dillon platform was unitized as the South Middle Ground Shoal Unit (SMGSU).
The remainder of the field was not unitized.
3. In 2015, Hilcorp became sole owner and operator of the MGS Field.
4. On May 12, 2016, Hilcorp applied to the Department of Natural Resources (DNR) to expand the
SMGSU to cover the entire MGS Field and to rename the expanded unit as the Middle Ground
Shoal Unit (MGSU).
5. On September 21, 2016, DNR approved Hilcorp's request to expand and rename the unit.
'The Affected Area of CO 44 was modified by CO 53 on September 7, 1967, and further modified by CO
54 on October 12, 1967.
CO 44A
January 12, 2017
Page 2 of 6
6. Hilcorp has applied to modify the Affected Area of CO 44 so that it matches the current MGSU
boundaries. The primary change would be in the southern portion of the MGS Field where the
SMGSU has been contracted over the years.
7. Rule I of the current CO prohibits more than two wells being completed in a governmental quarter
section. Because of this requirement, 51 spacing exceptions have been issued for the MGS Field.
8. Rule 1 was written based on old drilling practices using vertical wells. Current drilling practices
make frequent use of highly deviated and horizontal wells that do not fit into the established well
spacing rule.
9. The MGS Field is mature. The size of infill drilling targets is now smaller than the 80 acres
envisioned in CO 44.
10. Hilcorp proposes that there be no well spacing restrictions within the modified Affected Area
except,
a. no gas well shall be drilled or completed less than 1,500 feet from the exterior boundary of
the Affected Area unless the owner and landowner are the same on both sides of the line;
b. no oil well shall be drilled or completed less than 500 feet from the exterior boundary of the
Affected Area unless the owner and landowner are the same on both sides of the line; and
C. on written request by the Operator, the AOGCC may administratively consider and approve
modifications to well spacing when justified.
H. Rule 2 defines seven oil pools (MGS Oil Pools A through F) within the MGS Field, but does not
define any gas pools.
12. Historically, the field has been operated—and production has been reported—as follows: MGS A;
MGS B, C, and D (commingled); and MGS E, F, and G (commingled).
13. Hilcorp proposes combining all seven oil pools into a single oil pool. Hilcorp also proposes to
establish a new gas pool that lies shallower than the oil pool and encompasses all potentially
productive gas sands.
14. There are three distinct gas bearing intervals identified in the MGS Field area, these are identified
by Hilcorp in the MGS-18746-1 well as the:
a. Upper Gas Interval, which extends from 1,459 feet measured depth (MD) to the coal 31
marker at 5,126 feet MD;
b. Middle Gas Interval, which extends from the coal 31 marker to the coal 41 marker at 6,437
feet MD; and
C. Lower Gas Interval, which extends from the coal 41 marker to the top of the proposed oil
pool at 7,016 feet MD.
15. Gas sands in the Cook Inlet basin tend to be laterally discontinuous and require more than one well
per governmental section in order to maximize ultimate recovery.
16. Only the Middle Gas Interval has produced gas, approximately 16 BSCF to date, and this interval
is estimated to be 60% depleted. The Upper Gas Interval has reported gas shows, but no production.
The Lower Gas Interval has no reported gas shows and no production.
CO 44A
January 12, 2017
Page 3 of 6
17. Rule 3 allows the downhole commingling of oil production referenced in Finding 12 above but
prohibits all other downhole commingling of production. Similar restrictions apply to downhole
commingling of injection for EOR purposes.
18. There have been in excess of 15 separate downhole commingling authorizations for individual
wells issued for the MGS Field. These authorizations have approved all possible variations of
downhole commingling.
19. The MGS has produced for nearly 50 years. Production peaked at about 45 thousand barrels of oil
per day (MBOPD) in June 1968, and has declined to less than 2 MBOPD today. Few wells are
currently producing more than 100 barrels of oil per day (BOPD), and the top producer is
approximately 225 BOPD. Cumulative production is approximately 200 million barrels of oil. All
production is currently assigned to the MGS E, F, and G Oil Pools.
20. Hilcorp proposes eliminating the rules regarding downhole commingling of production and
injection since downhole commingling would no longer be a concern if the seven oil pools are
combined into a single oil pool.
21. Rule 5 approves the drilling of a lease -line well between two separate leases in the MGS Field.
Hilcorp proposes eliminating this rule as it is no longer relevant since the entire field has been
unitized.
22. Rule 6 contains a clause that authorizes the AOGCC to approve administratively:
a. conversion of a well to or from injection service;
b. drilling of an injection well;
C. drilling of wells not otherwise authorized by CO 44; and
d. downhole commingling of production or injection in a wellbore.
23. Rule 6 predates AOGCC's adoption of an underground injection control program.
24. Rule 7 provides specific casing requirements for the MGS Field. Hilcorp proposes to repeal these
requirements and follow statewide casing and cementing requirements. It also proposes an
alternative method of using cement bond logs or water flow logs for demonstrating zonal isolation
on a case-by-case basis.
25. Rules 8 and 9 prescribe a bottom -hole pressure survey requirement and a gas -oil ratio test
requirement for all producing wells that have very specific testing procedures.
26. Hilcorp proposes to eliminate the bottom -hole pressure testing rule because the field is mature and
information for reservoir management purposes is available from other reports required by
regulations.
27. Hilcorp proposes to eliminate the gas -oil ratio testing rule because regulations already require every
producing well to be tested at least monthly and production be allocated to each individual well
accordingly.
CO 44A
January 12, 2017
Page 4 of 6
CONCLUSIONS:
1. Modifying the Affected Area to coincide with the current unit boundary is appropriate because that
unit boundary conforms to the known productive limits of the MGS Field development.
2. Eliminating interwell spacing requirements for the MGS Field will make further development of
the field more viable and lead to increased recovery.
3. Correlative rights will be protected by restricting oil and gas wells from being completed within
500 and 1,500 feet, respectively, of a property line unless the owner and landowner is the same on
both sides of the line.
4. Maintaining seven distinct oil pools in the mature MGS Field provides no benefit for reservoir
management and monitoring, may hinder further development of the field and may reduce ultimate
recovery.
5. Establishing a new gas pool with rules governing development of the shallow gas sands in the MGS
Field will allow more efficient development and improve ultimate recovery.
6. Because the Lower Gas Interval within the new gas pool has no reported gas shows and no
production it should not be included.
7. Combining the existing seven oil pools into a single oil pool will eliminate the need for a rule that
governs commingling.
8. Eliminating the lease -line well rule of Rule 5 is appropriate because the Affected Area will
correspond to a single unit managed by a single operator.
9. Replacing Rule 6 with AOGCC's standard administrative approval rule will simplify
administration of the MGS Field.
10. The AOGCC's existing regulations concerning casing and cementing of wells ensure proper well
construction and integrity, and prevent migration of fluids between zones. Hilcorp's proposed
revision to address zonal isolation in instances where a well cannot be cemented in accordance with
the regulations will ensure proper isolation of zones that are capable of flow.
11. Due to the maturity of the MGS field Rule 8 provides little, if any, reservoir management and
monitoring benefit over reporting already required by regulations.
12. Current regulations eliminate the need for a rule that governs gas -oil ratio tests
NOW THEREFORE IT IS ORDERED:
The development and operation of the Middle Ground Shoal Oil Pool and the Middle Ground Shoal Gas
Pool are subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not
superseded by these rules. Conservation Orders 44, 53, 54, 56, 62, 66, 89, 99, 163, and 236 are hereby
superseded by this order and their records incorporated by reference into this order. All Administrative
Approvals issued under CO 44, except CO 44.11, are hereby revoked.
CO 44A
January 12, 2017
Page 5 of 6
Affected Area: Seward Meridian
Township
7 North, Range 13 West
Section 10: NE 1/4 ofNE1/4
Section 11: NW 1/4 of NW 1/4
Section 2: WI/2 of NEI/4, NW l /4, and SWI /4
Section 3: SEI/4 ofNEI/4 and E1/2 of SEIA
Township
8 North, Range 12 West
Sections 6-7: All
Township
8 North, Range 13 West
Sections 1-2: All
Sections 11-15: All
Sections 22-26: All
Section 35: Nel/4, NW1/4, SWI/4, and WI/2 of
SEI /4
Township
9 North, Range 12 West
Section 19: SEIA of SW 1/4 and SW 1/4 of SEIA
Sections 30-31: All
Township
9 North, Range 13 West
Sections 25 and 36: All
Rule 1 Well Spacing (Revised this order)
There shall be no well spacing restrictions within the Affected Area, except:
- No gas well shall be drilled or completed less than 1,500 feet from the exterior boundary of the
Affected Area unless the owner and landowner are the same on both sides of the line.
- No oil well shall be drilled or completed less than 500 feet from the exterior boundary of the
Affected Area unless the owner and the landowner are the same on both sides of the line.
Rule 2 Pool Designation (Revised this order)
The Middle Ground Shoal Oil Pool shall comprise the oil-bearing intervals common to and
correlating with the interval between the measured depth of 5,419 feet and 9,198 feet in well MGS
State 17595-4 (Permit to Drill Number 164-006).
The Middle Ground Shoal Gas Pool shall comprise the gas -bearing intervals common to and
correlating with the interval between the measured depth of 1,459 feet and 6,437 feet in well MGS
State 18746-1 (Permit to Drill Number 165-022).
Rule 3 Permissible Commingling (Revealed this order)
Rule 4 Fluid Infection (Repealed this order)
Rule 5 Lease Line Well (Revealed this order)
Rule 6 Administrative Approval (Renamed and revised this order)
Upon proper application, or its own motion, and unless notice and public hearing are otherwise required,
the Commission may administratively waive the requirements of any rule stated herein or administratively
amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on
sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into
freshwater aquifers.
CO 44A
January 12, 2017
Page 6 of 6
Rule 7 Casine and Cementine Requirements (Revised this order)
- Wells shall be completed in accordance with the provisions of 20 AAC 25.030.
- Due to significant loss zones previously encountered in the intermediate casing of some wells,
alternative methods (cement bond log or water flow log) may be considered by the AOGCC on a
case-by-case basis as an alternative means to validate zonal isolation.
Rule 8 Bottom Hole Pressure Surveys (Repealed this order)
Rule 9 Gas -Oil Ratio Tests (Repealed this order)
DONE at Anchorage, Alaska and dated January 12, 2017.
//signature on file//
Cathy P. Foerster
Chair, Commissioner
//signature on file//
Hollis French
Commissioner
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC
grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it.
If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or
decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within
10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration
are FINAL and may be appealed to superior court The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30
days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the
appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within
33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to mn is not included in the period;
the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day
Colombie, Jody J (DOA)
From: Colombie, Jody J (DOA)
Sent: Thursday, January 12, 2017 11:24 AM
To: aogcc.inspectors@alaska.gov;'Bender, Makana K (DOA) (makana.bender@alaska.gov)';'Bettis,
Patricia K (DOA) (patricia.bettis@alaska.gov)'; 'Brooks, Phoebe L (DOA)
(phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody 1 (DOA)
ody.colombie@alaska.gov)';'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton,
Loraine E (DOA);'Foerster, Catherine P (DOA)(cathy.foerster@alaska.gov)';'French, Hollis (DOA)';
'Frystacky, Michal (michal.frystacky@alaska.gov)'; 'Guhl, Meredith (DOA sponsored)
(meredith.guhl@alaska.gov)'; Kair, Michael N (DOA); 'Link, Liz M (DOA)'; Loepp, Victoria T (DOA);
'Mumm, Joseph (DOA sponsored) Qoseph.mumm@alaska.gov)'; 'Paladijczuk, Tracie L (DOA)
(tracie.pa lad ijczu k@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)';'Quick,
Michael (DOA sponsored)'; 'Regg, James B (DOA) Qim.regg@alaska.gov)'; 'Roby, David S (DOA)
(dave.roby@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T
(DOA) (dan.seamount@alaska.gov)'; Singh, Angela K (DOA); 'Wallace, Chris D (DOA)
(chris.wallace@alaska.gov)'; AK, GWO Projects Well Integrity; 'AKDCWellIntegrityCoordinator';
'Alan Bailey'; 'Alex Demarban';'Alexander Bridge'; 'Allen Huckabay';'Andrew VanderJack';'Ann
Danielson'; Anna Raff;'Barbara F Fullmer'; bbritch; Becky Bohrer;'Ben Boettger';'Bill Bredar';
Bob; Brandon Viator; 'Brian Havelock'; 'Bruce Webb'; 'Caleb Conrad'; 'Candi English'; Cocklan-
Vendl, Mary E; Colleen Miller, 'Connie Downing'; Crandall, Krissell;'D Lawrence';'Dale Hoffman';
'Dave Harbour'; David Boelens;'David Duffy'; David House;'David McCaleb';'David McCraine';
'David Tetta'; 'ddonkel@cfl.rr.com'; 'DNROG Units'; 'Donna Ambruz'; 'Ed Jones'; 'Elizabeth
Harball'; Elowe, Kristin; 'Evan Osborne'; Evans, John R (LDZX); 'Gary Oskolkosf'; 'George Pollock';
Gordon Pospisil; Greeley, Destin M (DOR); 'Gretchen Stoddard'; gspfoff; Hyun, James J (DNR);
'Jacki Rose'; Jdarlington Qarlington@gmail.com); 'Jeanne McPherren'; 'Jerry Hodgden'; 'Jim
Watt'; Jim White; 'Joe Lastufka'; Joe Nicks; 'John Burdick'; 'John Easton'; John Larsen; 'John
Stuart'; Jon Goltz; Josef Chmielowski; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Little'; Kari Moriarty;
'Kasper Kowalewski'; 'Kazeem Adegbola'; 'Keith Torrance'; Keith Wiles; Kelly Sperback; Kevin
Frank; Kruse, Rebecca D (DNR); Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Lori
Nelson; Louisiana Cutler, 'Luke Keller'; 'Marc Kovak'; Mark Dalton; Mark Hanley
(mark.hanley@anadarko.com); 'Mark Landt'; 'Mark Wedman'; 'Mealear Tauch'; 'Michael Bill';
Michael Calkins; 'Michael Moora'; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); nelson;
Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; 'Paul Craig'; Paul Decker
(paul.decker@alaska.gov);'Paul Mazzolini'; Pike, Kevin W (DNR); Randall Kanady;'Rena
Delbridge';'Renan Yanish';'Richard Cool'; 'Robert Brelsford';'Ryan Tunseth'; Sara Leverette;
'Scott Griffith'; Shannon Donnelly, Sharmaine Copeland; 'Sharon Yarawsky'; Shellenbaum, Diane
P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); 'Stephanie
Klemmer'; 'Stephen Hennigan'; Sternicki, Oliver R, Steve Moothart (steve.moothart@alaska.gov);
'Steve Quinn'; 'Suzanne Gibson'; Tamera Sheffield; 'Ted Kramer'; Temple Davidson; 'Teresa Imm';
'Thor Cutler'; 'Tim Jones'; 'Tim Mayers'; 'Todd Durkee'; 'trmjrl'; 'Tyler Sender'; Umekwe,
Maduabuchi P (DNR); 'Vinnie Catalano'; 'Weston Nash'; 'Whitney Pettus'; 'Aaron Gluzman';
'Aaron Sorrell'; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline 1; 'Bruce
Williams'; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn;'Don Shaw'; Eric Lidji; Garrett Haag;
'Graham Smith'; Hak Dickenson; Heusser, Heather A (DNR); Holly Fair; Holly Pearen; Jamie M.
Long; 'Jason Bergerson'; Jesse Chielowski; 'Jim Magill'; Joe Longo; John Martineck; Josh Kindred;
Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; 'Marie Steele';
Matt Armstrong; 'Mike Franger'; Morgan, Kirk A (DNR); Pascal Umekwe; Pat Galvin; 'Pete
Dickinson'; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel';
'Sandra Lemke'; 'Susan Pollard'; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck
C (LAW);'Wayne Wooster'; 'William Van Dyke'
Subject: CO 44A (Hilcorp) Middle Ground Shoal
Attachments:
co44A.,,jf
Re: THE APPLICATION OF Hilcorp Alaska, LLC to ) Docket Number: CO -16-016
amend Conservation Order 44 Middle Ground ) Conservation Order No. 44A
Shoal Field ) Middle Ground Shoal Unit
Middle Ground Shoal Field
Middle Ground Shoal Oil Pool
Middle Ground Shoal Gas Pool
Kenai Borough, Alaska
Jody J. Co(ombie
SFOyCC Specia( Assistant
_%Alaska Oi(andGas Conservation Commission
;3 )Nest 7"' Avenue
Anchorage, Alaska 99507
Office: (907) 793-1221
ax: (907) 276-7542
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 Jody Colombie at
907.793.1221 or iodv.colombie@alaska.aov.
F
Bernie Karl
M Recycling Inc. Gordon Severson Penny Vadla
P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave.
Fairbanks, AK 99711 Anchorage, AK 995084336 Soldotna, AK 99669-7714
George Vaught, Jr. Darwin Waldsmith Richard Wagner
P.O. Box 13557 P.O. Box 39309 P.O. Box 60868
Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706
'C�Q0 L
1 ALASKA OIL AND GAS CONSERVATION COMMISSION
E
3 Before Commissioners: Cathy Foerster, Chair
4 Daniel T. Seamount
5 Hollis French
0
7 In the Matter of Hilcorp Alaska, )
8 LLC's Application for Amendment of )
9 Conservation Order 44, Middle Ground )
10 Shoal Field. )
11 )
12 Docket No.: CO 16-016
13 ALASKA OIL and GAS CONSERVATION COMMISSION
14 Anchorage, Alaska
15 September 20, 2016
16 9:00 o'clock a.m.
17 PUBLIC HEARING
18 BEFORE: Cathy Foerster, Chair
19 Hollis French, commissioner
1 TABLE OF CONTENTS
2 Opening remarks by Chair Foerster 03
3 Remarks by Mr. Duffy
4 Remarks by Mr. Young
5 Remarks by Mr. Greenstein
2
O5
10
33
I P R O C E E D I N G S
2 (On record - 9:02 a.m.)
3 CHAIR FOERSTER: I'll call this hearing to
4 order. Today is September 20, 2016, it's 9:02 a.m. We
5 are at the offices of the Alaska Oil and Gas
6 Conservation Commission, 333 West Seventh Avenue,
7 Anchorage, Alaska. Commissioner Seamount is out
8 hunting something so today we have on my right
9 Commissioner French and I'm Commissioner Foerster.
10 We're here on docket order CO 16-016, the
11 application of Hilcorp Alaska, LLC, to amend
12 conservation order 44. Hilcorp Alaska, by letter dated
13 August 16th, 2016, requests the Alaska Oil and Gas
14 Conservation Commission issue an order amending CO 44,
15 Middle Ground Shoal Field.
16 Computer Matrix will be recording today's
17 proceedings and you can get a copy of the transcript
18 from Computer Matrix Reporting.
19 We have representatives from Hilcorp Alaska
20 intending to testify. And there any other parties
21 intending to testify?
22 (No comments)
23 CHAIR FORESTER: Okay. Since it doesn't look
24 like we have any new people to the -- in the audience
25 I'm going to forego the hectoring rules that I normally
3
I provide and I'll just go right to Commissioner French
2 and ask if you have anything to add for the good of the
3 order?
4 COMMISSIONER FRENCH: Not yet.
5 CHAIR FOERSTER: Okay. All right. Then you
6 guys know the drill on testifying so let's -- raise
7 your right hands.
8 (Oath administered)
9 MR. DUFFY: I do.
10 MR. YOUNG: I do.
11 CHAIR FOERSTER: Okay. And so does either one
12 of you want to be recognized as an expert?
13 MR. YOUNG: I do.
14 CHAIR FOERSTER: Okay. What area of expertise
15 would you like to be recognized for?
16 MR. YOUNG: My name is James Young, I'm -- I
17 have a bachelor of science in petroleum engineering and
18 I'd like to be recognized as an expert witness in the
19 area of reservoir engineering. I have 24 years of
20 stream oil and gas experience including about three
21 years as a reservoir engineer at Hilcorp working in the
22 Cook Inlet.
23 CHAIR FOERSTER: And where did you get your
24 degree?
25 MR. YOUNG: From Montana Tech.
4
I CHAIR FOERSTER: Okay. Commissioner French, do
2 you have any questions?
3 COMMISSIONER FRENCH: No.
4 CHAIR FOERSTER: Okay. Do you have any
5 concerns about recognizing his expertise?
6 COMMISSIONER FRENCH: No.
7 CHAIR FOERSTER: All right. So I have no
8 objections either. So you guys can -- and as you speak
9 introduce yourself, you know, if you change speakers
10 for the ease of the court reporter. And don't forget
11 to refer to your slides by number or name.
12 Okay. Thank you.
13 DAVID DUFFY
14 previously sworn, called as a witness on behalf of
15 Hilcorp Alaska, LLC, stated as follows on:
16 DIRECT EXAMINATION
17 MR. DUFFY: Good morning, Commissioners. My
18 name is David Duffy, I'm a landsman for Hilcorp Alaska.
19 On the introductory slide, slide 2, we have a
20 little bit of housekeeping. Normally we ask for -- if
21 there's any confidentiality issues related to the
22 presentation and there are none. And then I'm going to
23 start off the presentation with a quick review of just
24 the land and the ownership, where Middle Ground Shoal
25 is and how it fits into the overall inlet. And so
Wi
1 this is just an overall slide of Cook Inlet on the
2 left-hand side and.....
3 CHAIR FOERSTER: Slide number 3.
4 MR. DUFFY: Slide number 3. And then on the
5 right-hand side slide number 3 gives more detail. And
6 so the Middle Ground Shoal, these are the leases in the
7 field that we're going to talk about today, Middle
8 Ground Shoal as a whole. On the east side we have
9 Trading Bay and on the western side -- I'm sorry, the
10 eastern side, Kitchen Lights.
11 And on the next slide we put that together to
12 give an idea of how Hilcorp's leases and the four
13 platforms, Baker A, C and Dylan fit within the existing
14 conservation order 44 which is bounded by the pink
15 outline and then the various area injection orders, 7,
16 8 and 9, and they all tuck neatly together. Over time
17 -- currently the only portion of the leasehold that's
18 unitized is called the South Middle Ground Shoal and
19 that's wrapped around the two leases associated with
20 the Dylan platform. Hilcorp in -- just earlier this
21 spring has made an application to the Department of
22 Natural Resources to unitize the entire field which
23 would be the first time that's ever happened. So the
24 application is to take what's currently the Southern
25 Middle Ground Shoal unit and extend it to include all
C
1 the leases all the way up until the Baker. And then sc
2 the proposed lease boundary, I'm sorry, unit boundary,
3 is reflective of Hilcorp's lease ownership and you can
4 see that in the black outline. And so in our proposal
5 to amend conservation order 44 we requested that the
6 boundary or the affected area of conservation order 44
7 be amended to reflect Hilcorp's ownership which will
8 become the pending unit boundary for the overall field.
9 And the only place that really makes a difference is
10 over time the leases associated with the Dylan platform
11 have shrunk. So Hilcorp's ownership as you can see
12 down here, the current conservation order 44 extends
13 beyond Hilcorp's ownership. And where that really
14 matters is in terms of spacing, typically we have --
15 you know, if it's oil well or a gas well, 1,500 feet
16 for a gas well to where ownership changes. well, that
17 was one example where a boundary wouldn't matter for
18 spacing issues. If Hilcorp had both leases and that
19 was open it really wouldn't matter a bit. But at the
20 current time Hilcorp's leases are reflected in the unit
21 boundary. So it's one thing to consider. It's not a
22 critical issue either way.
23 CHAIR FOERSTER: So how would it change, I
24 mean, if the ownership is different then there's a --
25 there's a setback, right?
7
1 MR. DUFFY: Correct. Correct.
2 CHAIR FOERSTER: And how would changing the
3 unit bound -- the affected area boundary change that
4 because if you step outside the affected area you still
5 have a.....
6 MR. DUFFY: Right. SO.....
7 CHAIR FOERSTER: .....the requirement?
8 MR. DUFFY: .....part of -- and we'll get into
9 the details in a second when it comes.....
10 CHAIR FOERSTER: Okay.
11 MR. DUFFY: .....to the spacing portion.....
12 CHAIR FOERSTER: Okay.
13 MR. DUFFY: .....but we're asking for unlimited
14 spacing within the unit or within the affected area.
15 And at this point in time on the area in between the
16 pink line which is the current affected area and the
17 black line which is current -- Hilcorp's current
18 leasehold, that's not -- that's unleased state acreage.
19 CHAIR FOERSTER: Okay. So how would your
20 proposal affect wells drilled on the line between your
21 acreage and the unleased acreage?
22 MR. DUFFY: On new wells?
23 CHAIR FOERSTER: Yes.
24 MR. DUFFY: If they're within 1,500 feet and
25 it's a gas well we would probably have to come in and
9
1 either ask for administrative waiver or ask for a
2 spacing exception.
3 CHAIR FOERSTER: Okay. And on a current -- on
4 existing wells, how would -- are there existing wells
5 that are closer than 1,500 feet?
6 MR. DUFFY: I'm sure that there are.
7 CHAIR FOERSTER: And how would those wells be
8 affected?
9 MR. DUFFY: Those current wells -- in the back
10 of our proposal we outlined the last 40 years worth of
11 administrative orders and there's probably over 50
12 individual spacing exceptions that were granted over
13 time throughout the whole field. So on a -- for the
14 field is on a -- on a large part on a case by case
15 basis spacing exceptions have been granted particularly
16 for the oil wells which are the majority.
17 CHAIR FOERSTER: Okay. So I'm having a hard
18 time how -- seeing how changing it would make.....
19 MR. DUFFY: The.....
20 CHAIR FOERSTER: .....make a difference?
21 MR. DUFFY: Honestly it is sort of a -- it's
22 sort of a wash either way. I just wanted to make you
23 aware of what the ownership is and what the current
24 boundaries are.
25 CHAIR FOERSTER: Is it -- is the reservoir
E
1 outside of the lease, your current lease holdings?
2 MR. YOUNG: No. No, no hydrocarbons.
3 CHAIR FOERSTER: No hydrocarbons. Okay. All
4 right. Thank you.
5 JAMES YOUNG
6 previously sworn, called as a witness on behalf of
7 Hilcorp Alaska, LLC, stated as follows on:
8 DIRECT EXAMINATION
9 MR. YOUNG: Thank you, Commissioners. I'm
10 James Young again and I'd like to start with just a
11 brief field overview on slide 5 to give you some
12 history. The field was discovered in 1963 with state
13 lease 18754-01 well and shortly after that the pool was
14 extended to the south with another discovery well on
15 lease 18746-01. And at the time there were two
16 different major ownerships and two different operators,
17 basically the Baker and Dylan were Amoco operated and
18 the A and C platforms and leases were Shell operated
19 and owned. Production began in 1964 off the A and
20 Baker platform and followed shortly thereafter on the C
21 and Dylan platform in 167. Initially 50 wells were
22 used to develop the field off of these four platforms
23 which peaked out and 43 barrels a day in 1968. The
24 waterflood was started within a couple years after
25 production start and continued until the Dylan
10
1 waterflood was shut-in in 1987 and then Baker and Dylan
2 were completely shut-in on the oil in 2003, being
3 Unocal operated at the time. In 2012 Hilcorp acquired
4 the field and only the north and south ends of the
5 field, the Baker and Dylan platforms. The oil was not
6 activated at the time, there was some short term gas
7 production that was reactivated and basically what
8 shut-in in 2014. Just last year, 2015, Hilcorp
9 acquired the A and C platforms from XTO and at that
10 time was when Hilcorp finally had the entire field
11 under our ownership and operatorship and currently are
12 producing only the oil pools from the A and C platforms
13 at about -- a little less than 2,000 barrels a day with
14 about 39 active wells and nine shut-in wells.
15 So in summary the field is about 7 percent of
16 its peak production and very near its end of life and
17 Hilcorp is intending to consolidate, to simplify, so we
18 can highgrade where we may have opportunities.
19 On slide 6 just wanted to show you what the
20 stratigraphy looks like for the oil pools. And on the
21 left side is a geologic chart and you have basically
22 breaking down the oil pools are really contained within
23 the Miocene, Oligocene, the tertiary rocks of the
24 Tyonek formation and the Hemlock and they all -- they
25 both share a similar source rock being the Tekcedene
11
1 (ph), Jurassic, out here, the very similar oil
2 properties between all these reservoirs, they're
3 commonly sourced and they all follow a very similar
4 structure. What we found -- what has been determined
5 is that each one of these sands contains different
6 contacts, they haven't produced together. From the
7 life of the field we've made some estimates of
8 cumulative production and continued production and
9 various methods have been used, but this is a brief,
10 overall description of the oil pools. The majority of
11 the oil being in the Hemlock with about 20 percent in
12 the Tyonek A through F sands.
13 Slide 7, we just wanted to describe the way
14 we'd like -- we would propose to combine the pools is
15 combine these seven oil sands into a single oil pool
16 for administrative purposes and this will allow us to
17 manage the field as a single unit and simplify our
18 interactions. We still manage these reservoirs
19 separately in terms of looking for remaining oil. The
20 proposal is to combine those into a single pool and
21 then also there's a gas accumulation that has been
22 produced, has not been defined and our proposal is to
23 define that gas pool as a single gas pool. And we
24 really have three basic intervals where the gas is,
25 there's a -- which I'll describe shortly, but basically
12
1 there's a gas above where we produced which has gas
2 shows, but has not been produced, there's gas in the
3 area where we've produced and then there's gas below,
4 maybe gas, it's -- there hasn't been show, there hasn't
5 been any production so it's basically an interval that
6 we want to include in case there is something that
7 turns up.
8 CHAIR FOERSTER: Mr. Young, can I take you back
9 to slide 6 for just a second.....
10 MR. YOUNG: Sure.
11 CHAIR FOERSTER: .....and ask a question.
12 These estimated recoveries, they're current, right?
13 MR. YOUNG: Yes. Yes.
14 CHAIR FOERSTER: And is -- have you had any
15 waterflood here or is it -- this all just on primary
16 production?
17 MR. YOUNG: Yes, they've all been
18 waterflooded.....
19 CHAIR FOERSTER: They've all been waterflooded.
20 Okay.
21 MR. YOUNG: .....to various degree.
22 CHAIR FOERSTER: Okay. Thank you.
23 MR. YOUNG: Yep. Okay. So on slide 8 we
24 basically define -- this is the verbiage behind the
25 pool designations describing the wells used to describe
13
I these intervals and in the next slide, slide 9, I'll
2 show you a graphical representation of that.
3 This is the Baker 4 well and basically this is
4 the far ends of depths of the existing pools in this
5 well and that's the A, B, C, D, E, F and G. And then
6 on the left of this I'm showing historically how these
7 have been co -mingled through various modifications or
S administrative approvals to conservation 44. And
9 currently the production from the A and C is entirely
10 from this E, F and G pool which has been combined.
11 CHAIR FOERSTER: From the A and C platforms?
12 MR. YOUNG: From the A and C platforms.....
13 CHAIR FOERSTER: Okay.
14 MR. YOUNG: .....correct.
15 CHAIR FOERSTER: You get into the A, B, C, D's
16 and.....
17 MR. YOUNG: Yeah. Yeah.
18 CHAIR FOERSTER: Thanks.
19 MR. YOUNG: There's a lot of alphabet soup.
20 CHAIR FOERSTER: Yeah.
21 MR. YOUNG: And so again the proposal is to
22 combine all this into a single pool and same as the EOR
23 strata for waterflood as a -- to be the same pool as
24 the oil.
25 And this just shows the.....
14
1 CHAIR FOERSTER: Slide 10.
2 MR. YOUNG: Yeah, slide 10 shows just the
3 continuity and breadth of the various pools of oil
4 accumulations and the Hemlock being the deepest and the
5 largest is all -- this is all a single structure, what
6 you're seeing here is the different levels of a top of
7 a certain sand that -- containing hydrocarbons. So
8 this is the Hemlock which has the largest accumulation,
9 over 5,000 acres of oil and you can see the platforms
10 as they layout. And as you go shallower the contacts,
11 the edge of the hydrocarbon, there's less accumulation
12 in each of these sands as you go up hole so the Tyonek
13 E and F are limited to this area and you get up to the
14 B, C, D, they're an even smaller area and then the
15 Tyonek A is still yet a smaller area. So but the Baker
16 being inactive is why we really have no production from
17 these shallow sands.
18 And here's the -- on slide 11 is the
19 description of the gas pool described by Middle Ground
20 Shoal state 18746-1 and this is the entire interval of
21 gas, possible gas accumulations, it's from 1,459 to
22 7,016 feet. And in summary basically shows the yellow
23 is the accumulation where we see gas shows, but we have
24 not -- has not been any production at all other than a
25 unquantified volume of gas that was vented during the
15
1 1962 blowout of well 17595. And then in the middle
2 interval is basically where there has been production,
3 approximately 16 bcf has been produced out of the sands
4 from this interval, and it is over 60 percent depleted
5 and there may be some remaining recovery in that that
6 we will -- are evaluating going after with Baker.
7 CHAIR FOERSTER: So, Mr. Young, are those
8 associated gas production or separate sand.....
9 MR. YOUNG: It's separate sands.
10 CHAIR FOERSTER: .....you get separate gas
11 lenses?
12 MR. YOUNG: Yeah, so it's methane, it's not
13 solution gas.....
14 CHAIR FOERSTER: Okay.
15 MR. YOUNG: .....it's coal. And in the lower
16 interval basically between the lowest known gas
17 produced and the top of the oil pool so that we just
18 separate it from being solution gas. This is -- any
19 gas in this interval would be separate methane gas.
20 CHAIR FOERSTER: And you're proposing this all
21 be considered one gas pool?
22 MR. YOUNG: Yes.
23 CHAIR FOERSTER: Okay.
24 MR. YOUNG: Yes. And it's all known to not
25 have oil and it would be specifically just gas,
Vol
1 depletion drive mechanisms.
2 And then slide 12 just shows the mapped sands
3 where we've had known gas production and just shows --
4 you're zoomed in on a much smaller area here and really
5 limited to the Baker platform, these sands that have
6 been produced. And we show some possible extensions to
7 the south, however the sand thickness is very, very
8 small. In fact, the southern most production in any of
9 these is in this well, I guess Baker 14, which is about
10 a quarter mile north of the Baker platform.
11 So this -- slide 13 just gets into the rule
12 addressing well spacing and what is -- what you'll see
13 on here is basically a very simplified map zoomed in on
14 the A and C to show basically the wells that have
15 penetrated the Hemlock and each one of these dots is a
16 well penetration and what we've done is kind of broken
17 it down into performance areas to see has the increased
18 well density resulted in a crude recovery factor. And
19 what we found is in some of these areas, the lighter
20 colored areas here on this left side, this is actually
21 a different color than what's on the right side, is
22 down a 19 acre spacing where there's been improved
23 recovery approaching the technical limit of, you know,
24 exceeding 40 percent recovery whereas in any of these
25 other areas your significantly less recovery and this
17
1 is just an example why continued down spacing we feel
2 is going to be beneficial for this field. And as David
3 mentioned earlier there have been over 50 exceptions
4 addressing the spacing rule and almost all those have
5 been addressing not a lease line issue, but more of a
6 offset well. Currently the rules read 80 acre spacing
7 as a minimum. So we would like to change that to --
8 from 80 acres to allow unlimited spacing for oil wells
9 based on pattern performance and specific geology in a
10 -- in a given area.
11 CHAIR FOERSTER: Mr. Young, is there any -- is
12 there any known productive acreage outside of the
13 acreage operated by Hilcorp?
14 MR. YOUNG: No. No. I think outside of the --
15 as defined in CO 44, amended with 53 and 4, it's all
16 outside those.
17 CHAIR FOERSTER: So putting more straws into
18 the glass..
19 MR. YOUNG: Existing.
20 CHAIR FOERSTER: .....wouldn't affect
21 anyone.....
22 MR. YOUNG: Right.
23 CHAIR FOERSTER: .....else?
24 MR. YOUNG: Right.
25 CHAIR FOERSTER: Okay.
It.]
1 MR. YOUNG: That's correct.
2 CHAIR FOERSTER: Okay.
3 MR. DUFFY: And if I could interject? Within
4 the proposed unit boundary or existing leaseholds
5 Hilcorp's the 100 percent working interest owner,
6 there's no other partners and the state is the sole
7 owner and all the royalties are the same, there's not
8 even a difference on overrides between the different
9 leases. So production from the Baker for royalty
10 purposes or other ownership purposes would be the same
11 as if it were production from the Dylan per se.
12 CHAIR FOERSTER: We do have a representative
13 from the Division of Oil and Gas in the background and
14 I trust that if he disagrees with anything that you say
15 he'll start waving histrionically and ask to testify.
16 MR. YOUNG: Okay.
17 CHAIR FOERSTER: Okay. All right. Please
18 proceed
19 MR. YOUNG: Okay. So this is addressing the
20 well spacing for the oil and for the gas I just wanted
21 to show you another example. Currently the statewide
22 rules apply for gas which I believe is 160 acre
23 spacing, it's a very large spacing. And we were
24 evaluating perforating this well, this is slide 15
25 showing one of the sands with known gas accumulations
19
1 and had been produced in Baker 18. At this point we
2 were looking at perforating, trying to capture some
3 additional reserves and this specific case would
4 require an exception and administrative approval. And
5 the reason we end up having to drill wells close like
6 this is we're drilling from offshore where you don't
7 necessarily get to pick exactly where that location is.
8 We're trying to access marginal gas reserves that have
9 been stranded and we often have a -- to make them
10 economic we try to take a wellbore that penetrates it,
11 a well within the current well spacing limitations. So
12 this would just be an example of why we would like to
13 reduce the well spacing basically.....
14 CHAIR FOERSTER: Are these sands continuous?
15 MR. YOUNG: Yes, they are.
16 CHAIR FOERSTER: The individual lenses?
17 MR. YOUNG: Yeah, they're -- each one is
18 separate hydraulically, you know, vertically.
19 CHAIR FOERSTER: Uh-huh.
20 MR. YOUNG: Laterally we believe they are and
21 we can trace the coals across the field from the north
22 to the south end of the field.
23 In slide 16 is addressing the rules three and
24 four which apply to the co -mingling and consolidation
25 of fluid injection. And basically this rule was to
IM
1 address when you have separate pools which as current
2 these are all separate pools and required the A
3 platform to be injected, produced and reported
4 separately from the B, C, D and then from the E, F, G
5 and so on. And there was -- in the history there's
6 several examples of waivers or administrative approvals
7 to waive this to allow production at the Baker for
8 combined sands that would not otherwise be produced
9 just because of the access to the -- to those pools.
10 The other point on this is that the pools have
11 recovered we believe over 80 percent of their ultimate
12 recovery and to combine them in a single pool we do not
13 anticipate a major change or development of the
14 reserves in this area. What this -- the intent of this
15 is to allow us to access sands that would otherwise be
16 noncommercial in a similar well bore should we
17 determine they're viable to the co -mingle.
18 COMMISSIONER FRENCH: I have a couple questions
19 about that last point.....
20 MR. YOUNG: Sure.
21 COMMISSIONER FRENCH: .....and mainly it's just
22 helping me understand this. You say -- when you say
23 the stand alone sands are noncommercial, what does that
24 mean, that means they're just not being produced now?
25 MR. YOUNG: Yeah. Well, it's not just the not
21
1 being produced now, it's that the cost to drill a stand
2 alone well to that and the rate and reserves that you
3 could possibly get from that would not justify the cost
4 of that well by itself. However if you combine one
5 sand with another you could justify either drilling a
6 well or reactivating a well if it can produce from both
7 sands together.
8 COMMISSIONER FRENCH: I think I understand. I
9 mean, it sounds like it's a marginal -- it's a marginal
10 zone.....
11 MR. YOUNG: Yeah.
12 COMMISSIONER FRENCH: .....and yet if you got a
13 wellbore going through there and you're going to be
14 producing from below or above it you guys will open
15 that up and see what you get.....
16 MR. YOUNG: Exactly.
17 COMMISSIONER FRENCH: .....kind of thing?
18 MR. YOUNG: Yeah. Exactly.
19 COMMISSIONER FRENCH: Okay. Okay. Thanks.
20 MR. YOUNG: That -- that's what it allows.
21 It's strict.
22 Okay. Slide 17, again additional housekeeping.
23 It's addressing some of these older rules. The lease
24 line wells addressed basically an injection well that
25 separated the leases and that's no longer applicable.
22
1 These lease wells have been shut-in, I think one had
2 been shut-in for 13 years, the other one for about 30
3 years. They're not really conducive to the waterflood
4 operations and pattern management so we'd like to drop
5 that rule. And the other is no change to the
6 administrative approval process. And then rule seven
7 is just updating the casing and cementing requirements
8 to current provisions described in 20 AAC 25.240(b).
9 And the gas pools because of the challenging drilling
10 in some of these Baker wells, the intermediate casing
11 sometimes there's not a proven 500 foot column and
12 there may be administrative approvals or needs to have
13 another method to test integrity to ensure separation
14 from either the oil or a potential water zone.
15 And then slide 18 just describes the final rule
16 is the state recording. Currently there's an annual
17 pressure requirement to be submitted, I believe a
18 pressure for each platform. And this rule actually has
19 -- when we acquired the field we found that it hadn't
20 really been applied directly, the pressures that had
21 been obtained like on a producer is far, far low
22 compared to the average reservoir pressure in an
23 injector is far high. And we know that with the
24 history of this field that those actual pressure
25 surveys are not necessarily representative of the
23
1 actual reservoir pressure. And on this slide is a --
2 just an example of that. This is a plot of time and
3 this is pressure on this axis and then these lines are
4 basically your cumulative injection to withdrawal ratio
5 which is basically the amount that you've taken out,
6 the amount that you've replaced divided by how much
7 you've taken out and so when that reaches a one you
8 basically -- you filled it up, you replaced what you
9 put in. And we can see that these track very well,
10 these ratios track very well, with the simple models to
11 the average of the pressures that we've seen over the
12 history. And there's some high points and low points
13 and those are -- these would be injectors and these
14 would be producers, radical differences between these
15 wells just because of the nature of the reservoir. And
16 we feel that more representative methods to manage the
17 reservoir pressure is really the objectionable
18 withdrawal ratios and we may continue to take surveys,
19 but the request is to not have to require a survey
20 that's not representative to be submitted for that
21 report. And then the gas/oil ratio test is basically
22 just an update on how it's performed given today's
23 methods versus what they had in 1960. And these are
24 provided with our monthly well tests that are taken, no
25 changes in that, and provided via a 10-405.
24
1 CHAIR FOERSTER: So would you have a difficult
2 -- would you have heartburn with including in rule
3 eight that if you do take bottom hole pressure data
4 that you provide it to the Commission? You were saying
5 that you don't want to be required to take.....
6 MR. YOUNG: Yeah.
7 CHAIR FOERSTER: .....to be.....
8 MR. YOUNG: Yeah, that's -- yeah, that's not a
9 problem. I think.....
10 CHAIR FOERSTER: Okay.
11 MR. YOUNG: ..... we can -- when we take them
12 it's -- we generally will -- well, we will -- we will
13 describe basically the -- you know, a shut-in time and
14 whether it's representative, but, yeah, it's.....
15 CHAIR FOERSTER: Okay. Thank you.
16 MR. YOUNG: So this concludes the testimony I
17 have on the pool rules and the justification behind
18 some of these changes that are proposed. And I'd just
19 like to thank the Commissioners for your time and your
20 consideration and ask if there's any further questions.
21 CHAIR FOERSTER: So, Commissioner French, do
22 you have any questions before we take a recess?
23 COMMISSIONER FRENCH: I'll just ask -- this is
24 a little bit outside the scope of the hearing, but any
25 plans to start the Baker and the Dylan back up?
25
1 MR. YOUNG: In the short term, no, in the long
2 term we do feel there is some opportunity there. What
3 we're -- our focus is right now is actually to drill
4 wells that we see we can successfully do off of the
5 current operating platforms with the nine shut-in wells
6 we have there and what -- sort of the concepts that
7 we're testing if those are successful we feel that can
8 give us some upside to make the Baker and Dylan
9 economic and viable to reactivate. So without that
10 technology or success to reactivate those at the
11 current prices is probably not viable, but in the
12 future either price change or performance change based
13 on our proposed drilling at DNC we feel that's a
14 possibility.
15 COMMISSIONER FRENCH: So you got a perfect
16 little petri dish there in A and C to try out some
17 ideas?
18 MR. YOUNG: Yes. Yes, and it's a -- it's a
19 great opportunity because now we can look at the whole
20 field together as opposed to in the past it's always
21 been different owners, different interest, different
22 leases and not necessarily an understanding of the
23 reservoir.
24 COMMISSIONER FRENCH: It is interesting that
25 it's all under one owner, I think it's a good
26
1 opportunity for the Middle Ground Shoal.
2 MR. YOUNG: Yeah, we're excited.
3 COMMISSIONER FRENCH: Thanks.
4 CHAIR FOERSTER: All right. It's 9:35 and
5 we'll take a 20 -- well, let's just -- we'll take a 25
6 minute recess and we'll reconvene at 10:00 o'clock.
7 MR. YOUNG: Great.
8 CHAIR FOERSTER: So right now we're recessed.
9 (Off record)
10 (On record)
11 CHAIR FOERSTER: Okay. We had fewer questions
12 than we thought we would so we're going to start a
13 little early. We're going to go back on the record at
14 9:53.
15 All right. Commissioner French, do you have
16 any questions you'd like to ask?
17 COMMISSIONER FRENCH: No.
18 CHAIR FOERSTER: I have a few. Mr. Young, you
19 talked broadly about gas sands above, below and in the
20 middle, could you describe what formations you expect
21 to -- are you hoping to potentially find gas from
22 Tyonek, Hemlock, Sterling?
23 MR. YOUNG: Yeah. Yeah. Middle Ground Shoal,
24 really the -- it's all Tyonek where we've found the gas
25 and there's not really a Sterling or Beluga there. The
27
1 top -- what we're defining as the top of the gas pool
2 is actually a Tyonek and there's somewhat limited
3 thickness of these sands, they're basically
4 accumulations beneath coals. And there's really three,
5 the Tyonek 31, the Tyonek 35 and the Tyonek 40 that are
6 produced. And I think each of those have just about an
7 equal share of that 16 bcf and they're very strong
8 water drive so they tend to start out at a -- not a
9 very super high rate and then when the water comes in
10 they're done. And it's been fairly disappointing
11 results I think from the gas I've see here as compared
12 to some of the other offshore fields. And the -- some
13 of the testing or some of the -- really the open hole
14 logs kind of tell us if there are gas shows and like up
15 to the T-22 sand which is, you know, they're basically
16 numbered from the top down, and they look fairly
17 speculative. I think there was some attempts at
18 testing some of those in -- while Baker was operating
19 in 2013 to '14 and they were really not positive, I
20 don't think they condemned the wells, but they weren't
21 really like a huge -- anything to drive us to go after.
22 In the immediate term we feel like probably to make
23 those gas sands we'd have to have an oil project to go
24 with it to make them economic.
25 Does that.....
28
1 CHAIR FOERSTER: Okay. Your -- on slide six
2 you show some gas shows in the Beluga and the Sterling,
3 but you don't see those as something that you would be
4 targeting?
5 MR. YOUNG: Yeah. Basically I'm not a
6 geologist so I don't know if he's actually named that
7 interval.
8 COMMISSIONER FRENCH: Just for clarity, I think
9 the Commissioner was asking about slide six.
10 MR. YOUNG: Oh, six. Okay. Sorry.
11 COMMISSIONER FRENCH: That may help you.
12 MR. YOUNG: Oh, okay. Yeah. Yeah, I got it.
13 I got where you're coming from. So this is a general
14 section of the Cook Inlet, not necessarily do you see
15 the sands from surface and every location. And so at
16 Middle Ground Shoal really where we see the sand coming
17 in to the top of the (indiscernible) or potential
18 hydrocarbon zone is the Tyonek. And so.....
19 CHAIR FOERSTER: And so you don't have Beluga
20 and Sterling?
21 MR. YOUNG: No. Yeah, that's.....
22 CHAIR FOERSTER: Okay. Thank you. And how
23 much deep data do you have?
24 MR. YOUNG: We have a couple wells that have
25 penetrated the west (indiscernible) and they were
1 tested at the Baker and they were really nonproductive
2 of hydrocarbons. And then the -- there's a exploration
3 well at the very south end, south of the Dylan
4 accumulation that tapped into the Jurassic and didn't
5 -- it supposedly have some pressure to it, but there
6 really wasn't anything to go after in the Jurassic
7 there. It's always been the speculation, you know, is
8 the Jurassic a possible play here, but.....
9 CHAIR FOERSTER: I know if Commissioner
10 Seamount were here he'd be haranguing.
11 MR. YOUNG: He'd be all over it, yeah.
12 CHAIR FOERSTER: Yeah. Yeah, he is a
13 geologist. And I didn't mean that as a compliment to
14 him.
15 MR. YOUNG: This is for the record.
16 CHAIR FOERSTER: Beg pardon.
17 MR. YOUNG: This is on the record.
18 CHAIR FOERSTER: I -- and let the record
19 reflect that it wasn't a compliment.
20 COMMISSIONER FRENCH: If he goes back and
21 listens to this hearing he'll find a surprise. Oh,
22 well.
23 CHAIR FOERSTER: That's right. That's right.
24 So another question for you, Mr. Young, you -- going to
25 slide 11 for a minute.....
30
I MR. YOUNG: Uh-huh.
2 CHAIR FOERSTER: ..... if you don't mind.
3 MR. YOUNG: Yeah.
4 CHAIR FOERSTER: Well, that one -- that one
5 does show that you got some upper gas potential, some
6 lower gas potential.....
7 MR. YOUNG: Yeah.
8 CHAIR FOERSTER: .....and a middle interval
9 that's about 60 percent depleted, I thought you.....
10 MR. YOUNG: Yeah.
11 CHAIR FOERSTER: Okay. So if you are allowed
12 to consider that all one interval.....
13 MR. YOUNG: Uh-huh.
14 CHAIR FOERSTER: .....are you concerned about
15 crossflow?
16 MR. YOUNG: No, I think -- I mean, I'm always
17 concerned about how I would address it, what I would do
18 is -- you know, whenever we look at something that's
19 got potentially water pressure in it we isolate it, we
20 have to otherwise we're going to have problems. So I
21 think even though we may call it all one pool in terms
22 of how we'd manage it I think is on a case by case
23 basis.
24 CHAIR FOERSTER: Okay. Good answer. Mr.
25 Duffy, you mentioned that you aren't requesting any
31
1 changes to any of the AIOs, but have you reviewed all
2 of the AIOs to determine whether any modifications
3 would be appropriate in light of the changes you're
4 suggesting to this -- the conservation order because we
5 typically see when a CO changes the AIOs change too,
6 but have you all done that analysis?
7 MR. DUFFY: That's a great question. I really
8 would either defer to Mr. Young or.....
9 CHAIR FOERSTER: Okay. That's fine.
10 MR. DUFFY: Yeah.
11 MR. YOUNG: You know.....
12 CHAIR FOERSTER: Or Mr. Greenstein if he's.....
13 MR. YOUNG: Yeah, to be honest I.....
14 CHAIR FOERSTER: .....he's bouncing back there,
15 I think he wants to come up and answer.
16 MR. YOUNG: .....I didn't have anything
17 specifically that stood out to me. I'm not -- I'd
18 maybe ask Larry if there's anything that we want to
19 review, you know.....
20 CHAIR FOERSTER: Mr. Greenstein, you want to
21 come up and let me swear you in. Have a seat, turn on
22 the mic. All right. Raise your right hand.
23 (Oath administered)
24 MR. GREENSTEIN: Yes, I do.
25 LARRY GREENSTEIN
32
1 called as a witness on behalf of Hilcorp Alaska, LLC,
2 stated as follows on:
3 DIRECT EXAMINATION
4 MR. GREENSTEIN: I have reviewed the AIOs 7, 8
5 and 9. They're our old ones definitely, but they're
6 all written very similar to each other and we treat
7 them -- what would be the same even though we didn't
8 have A and C, they meld together very well. The area
9 affected is all the same, the reporting is all the
10 same. There is nothing that would contradict anything
11 in the conservation order, hiding in amongst the AIOs.
12 CHAIR FOERSTER: Thank you, Mr. Greenstein.
13 MR. GREENSTEIN: You bet.
14 CHAIR FOERSTER: The man in the back said you
15 didn't say your name for the record, but I'll just say
16 it for you, it's Larry Greenstein. We all know him.
17 (Off record comments)
18 CHAIR FOERSTER: One last question. I'm
19 surprised that you're not requesting modification of
20 rule number 6.
21 MR. YOUNG: The administrative?
22 CHAIR FOERSTER: Yeah. Have you given any
23 thought to that, would making a modification to that
24 make life easier in an old field where you're trying to
25 scrape the pot, lick the bowl, whatever?
33
1 MR. DUFFY: We did, but we've had I think
2 decent success in communications with the commission
3 and if issues come up on a case by case basis we feel
4 like the current rule is adequate to have that
5 conversation.
6 CHAIR FOERSTER: okay. All right. And if we
7 put something in it to ease that restriction you
8 wouldn't have heartburn?
9 MR. DUFFY: Not at all. The one place where we
10 did make a slight change was in the spacing rule. In
11 rule two where we said -- excuse me, I'm sorry, rule
12 number 1, on the third bullet of our application
13 besides talking about the, you know, unlimited spacing
14 on the gas well and unlimited spacing for the oil well,
15 there is a third bullet that says on request by the
16 operator the AOGCC may administratively consider and
17 approve modifications to a well spacing where
18 justified. so if something different -- so that is a
19 place where we didn't put it under the regular
20 administrative rule, but we've seen that same language
21 used in other places and instances and it's worked
22 beautifully for example on the North Slope.
23 CHAIR FOERSTER: Okay. Okay. Commissioner
24 French, do you have anything else?
25 COMMISSIONER FRENCH: No.
910
1 CHAIR FOERSTER: Is there anyone in the
2 audience who has a compelling need to get up and speak
3 into the microphone?
4 (No comments)
5 CHAIR FOERSTER: All right. Seeing no one, at
6 10:04 a.m. this hearing is adjourned.
7 (Adjourned - 10:04 a.m.)
g (END OF PROCEEDINGS)
35
1 TRANSCRIBER'S CERTIFICATE
2 I, Salena A. Hile, hereby certify that the
3 foregoing pages numbered 02 through 36 are a true,
4 accurate, and complete transcript of proceedings in re:
5 Docket No.: CO 16-016 public hearing, transcribed under
6 my direction from a copy of an electronic sound
7 recording to the best of our knowledge and ability.
8
9 Date
10
Salena A. Hile, Transcriber
kri
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
Docket Number: CO -16-016
September 20, 2016
NAME AFFILIATION Testify (yes or no)
T)n%lA J�CD5X-Moc-tC�— .��
'3
CO-16-16
Application to Amend Conservation Order 44,
Middle Ground Shoal Field
September 20, 2016
Introductions
• David Duffy, Landman, Hilcorp Alaska, LLC
• James Young, Reservoir Engineer, Hilcorp Alaska, LLC
Agenda
• Housekeeping:
• Confidentiality Issues: None
• Request to recognize Mr. Young as Expert Witness
• Land &Ownership Review
• Summary of Request &Technical Presentation
• Q&A
Slide 2
- •:rr
Westside
Kenai
.r�
Peninsula
J
L".d
�. c'co wnca,. Hw
� f�l-pte Lae
BAMYafI 3M6 LMY�
Mn MbIIY.Y
WIl.W V�
wes• Wnen.ne. �
d A G+u Urtl BlYM•n
Slide 3
Slide 4
® Field Discovery well: 18754-01(MGS-01) 1963
— Oil pool extension to south confirmed in 18746-01
— Baker & Dillon leases — Amoco operated
— A&C leases — Shell operated
® 1st production: A&B platform in 1964; C&D in 1967
— 50 initial wells, 4 platforms, 43 Mbopd peak in 1968
— Full -field water -flood start in 1969 (Dillon WF SI 1987)
— Baker and Dillon SI in 2003 (Unocal)
® Baker & Dillon acquired by Hilcorp 2012
— Short-term Baker gas production 2013-14
® Hilcorp acquired A & C Platforms from XTO in 2015
— A&C Currently producing oil only
— 1.9Mbopd, 39 active wells, 9 S/I
Slide 5
E =
Recent
Alluvium
Pleistocene
Glacial Gravels
Sands, Silts,
& Clays
PLIOCENE
Sterling
Fm.
MIOCENE
z
•
Beluga
Tyonek
Fm.
OLIGOCENE
Hemlock
WCENE
W. Foreland
«
PALEOCEVE
Chickaloon
Fm.
G
UPPER
Matanuska
Q
Fm.
i
x
LOR'ER
unnamed
Shale
OIL
SOURCE
n
UPPER
Naknek Fm.
Chinitna m
MIDDLE
Tuxedni Op.
LOWER
Talkeetna
-�
r
A- ZONE
B-ZONE SANDS
cl�f�r
C-ZONE SANDS
D-ZONE SANDS
AND
TDP HEMLOCK
Hemlock and Tyonek (A-F) Oil
- >2,500' section
- 5-15%PHI
- 5,289 Acres
OOIP HK: 800-1000 MMBBL
OOIP A-F: 150-180 MMBBL
Pool
Area
Avg. H
Cum Prod
Est
Rec.
Ac
ft
MMBBL
fract
A
672
36
2.8
0.15
B
978
55
3.9
0.12
C
688
83
5.9
0.15
D
667
30
2.1
0.19
E
2339
20
4.0
0.15
F
3362
20
7.0
0.16
G(HK)
6127
405
180.0
0.17
Slide 6
Rule 2: Pool Designation
• Fropose, to combined 7 oil sands (ABCDEFG)
into a single pool
• Propose to establish single gas pool comprised of
three intervals. --
I . Above known gas accumulation (possible)
2. Known gas accumulation (proven)
3e Below known gas accumulation (above top oil pool)
Slide 7
Rule 2: Pool Designation
Ifilcogi proposes to repeal Rule 2 ("Pool Designatic)n") in its cntircty and rUn1Uc:c it Widh
the following language:
+ The Middle Gcaund Shoal Oil fool shall comprise the oil-bcaring intervals
common to and correlating with the interval hetveen the measured depth of 5419
feet and 9198 feet in the MG-9 State 17595�4 (BA- ) wel1.
• The Middle Ground Shoal Gas Pool shall comprise the gas bearing inter%,als
common to and correlating with the interval between the measured depth of 1459
,feet and 7016 Meet in the 14 CTS ;Mate 18746-1 (common name) well -
This Vvs peal includes and is comprised of the following three intervals:
o Upper Gas Interval 1459' to 5126' MD (GOAL 31 marker).'
o Middle Gras Interval: 512ti' (COAL 31 marker) to 6437 AID (FOAL 41
marker).2
o I,ower Gas Interval: 6437' (CO -AL 41 rnarker) to 70161 MD (Trap A
marker, coincides with top of the Middlc Ground Oil Pool)!
Slide 8
(well A-42-11)
3134'-3480' (SAND 24)
Commingling 4680'-5283' (SAND 40-43)
under C044
2016 Prod,
BOED Existing Oil Pools
0 A: 5300'-5720'
B: 5720'-6100'
0 C: 6100'-6400'
D: 6400'-6750'
: 6750'-7050'
1900 F: 7050'-7375'
G: 7375'-9215'
Existing FOR Strata
5300'-9215'
2613'-2842 (SAND 24)
4279'-4956' (SAND 40-43)
Proposed Oil Pool
MGS Oil Pool: 5300'-9215'
Proposed FOR Strata
(same as the existing FOR Strata)
MGS FOR Strata: 5300'-9215'
Slide 9
Structure Maps with productive oil pools. Labels located at southern extent of oil column.
Tyonek
(A)
Tyonek(BCD)`'-
}- r
t 0
i
1
lvlv" kYL
18746-1
Proposed Gas Pool
MGS Gas Pool: 1459'-7016'
Upper Gas Interval 1459' to 5126' MD (COAL
31 marker). Known gas shows, but no
production other than an un-quantified volume
of gas vented during the MGS State 17595-1
blowout well in 1962.
Middle Gas Interval: 5126' (COAL 31 marker)
to 6437 MD (COAL 41 marker). This pool
contains known gas with a cumulative
production of approximately 16 BSCF and is
>60% depleted.
Lower Gas Interval : 6437' (COAL 41 marker)
to 7016' MD (top A marker, coincides with top
of the Middle Ground Oil Pool). No gas shows
or production from this interval in well
penetrations to date.
Slide 11
Structure Maps with productive gas sands — >60% depleted & zero current production
40 Sand
f
ry
Slide 12
Hemlock field performance
has Indicated additional oil
�
ecovery can be gained in
most areas to less than 20
Slide 13
19 acre
spacing
> 1000'
apparent pay
thickness
A-12-12LW ---.
A-34-11 LS1-
A-34.14LW
a-
C-32-23L
A-22.14LS---
C 21A-23
C-13A-23LN --
C-11-
C-24A
7 50 acre
7 spacing
c1,' 100'-600'
apparent pay
A-2
thickness
High RF
C-11
Medium RF
Low RF
Rule 1: Well Spacing
• Currently limited to 80 acres for oil and statewide
�o,,pacing regulations for the undefined gas.
Unlimited spacing is proposed to aiflow infill well Is
based on pattern performance & geology.
Rule l: Well Spacing
Hilcorp proposes to .repeal Rule 1 ("spacing pattern") in its entirety and replace it with
the following language;
There shall be no well spacing restrictions within the AlTected .Area, except:
► No gas well shall be drilled or completed less than 1,500 feet from the exterior
boundary of the Affected Area unless the owner and landowner is the same on
both sides of the line.
+ No nil well shall be drilled or completed less than 500 feet from the exterior
boundary of the Affected A.rca unless the owner and the landowner is the same
on both sides of the line,
• On written request by the Operator, the AOCTCC Wray administratively consider
and approve modifications to uvll spacing when justified, Slide 14
Access to remaining
gas reserves is
dictated by
availabilaty of
, 0
existing
0
reservoir geometry.
Slide 15
0 N4RI ,
Sedibri '19
/ BA-27
/ BA-18,
i
BA-14;'
'
10
t ,
T60N�R '
ft frl
/ / I
ts, 0000n,3-1
` 1
Rules 3 & 4: Elimination of Commingling and
Consolidation of Fluid Injection.
• Current rile require A, BCD & EFG oil pools to
be produced, injected and reported separately
except by admin approval.
• Pools have recovered over 80% of EUR and will
be combined into a single oil pool.
• Allows non-commercial standalone sands to be
A4
produced from via the same wellbore to improvi.p
viability.
Slide 16
Rule 5: Lease line wells — no longer applicable under
Hilcorp's consolidated ownership of entire field
Rule 6: No change to administrative approvals is
requested or required
Rule 7: Casing and Cementing
Wells shall be completed in accordance with 2
provisions •1 Ahowever
i due to
�
significant loss• •encountere
in a intermediate casingof s mwells, alternative
methods (cement bond log or water flow log) are
requested as a means •'validate zonal isolation.
Slide 17
Rule 8: Eliminate BHP Survey reporting & update gas -oil ratio tests.
• Due to field maturity, injection -withdrawal ratios (provided via 10-413) are
a more effective reservoir management tool than BHP surveys.
• Gas -oil ratio tests are measured during monthly well tests for production
allocations & provided via 10-405.
IVIGS EFG Historical Injection Withdrawl
6000
- -----
1.00
5000 -
0.90
4000
0.80
3000
0.70
2000
0.60
P—Datum TVD=8000
1000
--est. P, M BAL N= 800
0.50
--estP,Winf=5bw/day/psi
1W Cum
C)
0.40
?
Slide 18
Thank You.
Questions?
Slide 19
MIDDLE GROUND SHOAL UNIT
APPROVAL OF THE APPLICATION TO
EXPAND & RENAME THE SOUTH MIDDLE GROUND SHOAL UNIT
Findings and Decision of the Director
of the Division of Oil and Gas
Under a Delegation of Authority
from the Commissioner of the State of Alaska
Department of Natural Resources
September 21, 2016
TABLE OF CONTENTS
I. INTRODUCTION AND DECISION SUMMARY...............................................................
3
II. APPLICATION AND LEASE SUMMARY..........................................................................
4
III. DISCUSSION OF DECISION CRITERIA............................................................................
6
A. Decision Criteria considered under 11 AAC 83.303(b) ...................................................
6
1. Environmental Costs and Benefits...................................................................................
6
2. Prior Exploration and Geological and Engineering Characteristics .................................
7
3. Plans of Development......................................................................................................
8
4. The Economic Costs and Benefits to the State and Other Relevant Factors ...................
8
B. Decision Criteria considered under 11 AAC 83.303(a) .................................................
10
1. Promote the Conservation of All Natural Resources.....................................................
10
2. The Prevention of Economic and Physical Waste.........................................................
10
3. The Protection of All Parties of Interest, Including the State ........................................
10
IV. FINDINGS AND DECISION...............................................................................................
11
A. The Conservation of All Natural Resources..................................................................
11
B. The Prevention of Economic and Physical Waste.........................................................
11
C. The Protection of All Parties in Interest, Including the State .........................................
12
V. ATTACHMENTS.................................................................................................................14
1. Middle Ground Shoal Unit Proposed Exhibit A ............................................................
15
2. Middle Ground Shoal Unit Proposed Exhibit B.............................................................
17
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 2 of 19
I. INTRODUCTION AND DECISION SUMMARY
The State of Alaska, Department of Natural Resources, Division of Oil and Gas (Division),
received an application for the expansion of South Middle Ground Shoal Unit (Application), on
May 12, 2016 from the South Middle Ground Shoal Unit (SMGSU) operator, Hilcorp Alaska, LLC
(Hilcorp). The existing SMGSU contains 1,160 acres. The proposed unit expansion area, currently
known as the Middle Ground Shoal Field (MGSF) and North Middle Ground Shoal Field
(NMGSF), covers three leases containing approximately 11,502 acres. The Application also
proposes changing the name of the unit to the Middle Ground Shoal Unit (MGSU). Attachments 1
and 2 describe the proposed Exhibits A and B to the SMGSU agreement.
The SMGSU, MGSF and NMGSF are offshore Cook Inlet oil and gas developments comprised
of State of Alaska oil and gas leases. The SMGSU was formed effective April 7, 1967 and began
oil production later that year. Hilcorp purchased the working interest in the unit in late 2011 from
Union Oil Company of California (Unocal). The SMGSU produced from the Dillon platform
until 2003. The SMGSU has not produced oil or gas since 2003 and the Dillon Platform has
remained lighthoused. The current unit boundary dates back to 1972 when the unit was
contracted to the boundaries of the Tertiary System Participating Area (PA), established April 7,
1967, which includes ADL 18746 and ADL 18744. Although the Dillon Platform is not
operational, the unit term has been extended by the presence of a unit certified well and unit
operations have been conducted in accordance with approved plans of development as set forth
in 11 AAC 83.336(a)(1).
The MGSF is located between the SMGSU and NMGSF. The MGSF has been continuously
producing oil through lease operations since 1965 from the A Platform on ADL 18754 and C
Platform on ADL 18756. Hilcorp acquired the MGSF from XTO Energy Inc. on August 31,
2015. The NMGSF is a lease operation with initial production starting in April 1966. The
NMGSF produced hydrocarbons from the Baker Platform on ADL 17595. The Baker Platform
was built in 1965 and oil production began in April 1966 and continued until 2003. Hilcorp
acquired the NMGSF in January 2013. Gas production was reinitiated in April 2013 until a fire
on the platform shut-in production in October 2014. The Baker Platform is currently lighthoused
and ADL 17595 is held by production by wells drilled from the A Platform draining the lease.
"A unit must encompass the minimum area required to include all or part of one or more oil or
gas reservoirs, or all or part of one or more potential hydrocarbon accumulations." 1 I AAC
83.356(a). Hilcorp has submitted confidential geological, geophysical, and engineering data
demonstrating that the area approved for expansion includes all or part of an oil or gas reservoir
and potential hydrocarbon accumulations.
The Division finds that the expansion of the SMGSU promotes conservation of all natural
resources, promotes the prevention of economic and physical waste, and provides for the
protection of all parties of interest, including the State. AS 38.05.180(p); 11 AAC 83.303. 1
approve the Application under the terms and conditions of Section W. The effective date of the
SMGSU expansion is September 21, 2016. The SMGSU will be known as the Middle Ground
Shoal Unit upon the effective date of this decision.
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 3 of 19
II. APPLICATION AND LEASE SUMMARY
The five leases included in the MGSF, SMGSU, and NMGSF were issued by the State of Alaska
in 1962. The lease comprising the NMGSF (ADL 17595) was issued to Pan American Petroleum
Company (Pan American) on January 31, 1962. ADL 18754, ADL 18746, ADL 18744, and
ADL 18756 were issued on September 1, 1962. The leases comprising the SMGSU (ADL 18746
and 18744) were issued to Pan American Oil Company. The leases comprising the MGSF (ADL
18756 and 18754) were issued to Shell Oil Company (Shell), Richfield Oil Company, and
Standard Oil Company of California.
The discovery of the Middle Ground Shoal structure is attributed Pan American's drilling of the
Middle Ground Shoal No. 1 (MGS 1) well. The well encountered gas and experienced a blowout
on June 10, 1962. The well was certified by the DNR, and eventually affirmed by the Alaska
Supreme Court, as the discovery well for the Middle Ground Shoal structure. ADL 17595, where
the MGS 1 well was drilled, became what is known as the NMGSF. ADL 17595 was briefly
unitized along with lease ADL 369116, effective August 30, 1996. The North Middle Ground
Shoal Unit was terminated on December 31, 2005 after production ceased in 2003. Hilcorp
purchased the working interest in the NMGSF from Unocal on January 1, 2012. Only Segment 1
of ADL 17595 was proposed to be included in the expanded unit.
Amoco Production drilled the Middle Ground Shoal 18743 State No. 1 well to discover the
southern end of the Middle Ground Shoal structure. The well was certified capable of production
in paying quantities by the DNR on October 17, 1965. The South Middle Ground Shoal Unit
(SMGSU) and Tertiary System PA were formed effective April 7, 1967. The SMGSU originally
included three state oil and gas leases totaling 4,160 acres. The Tertiary System PA was
expanded three times prior to unit contraction. On July 7, 1972, the SMGSU was contracted to
its current configuration consistent with the Tertiary System PA boundary. The SMGSU
currently encompasses 1,160 acres of two State offshore leases. Amoco Production assigned its
interest in the SMGSU to Unocal in 1990. Unocal informed the DNR that the Dillon Platform
had reached its economic limit and production was shut-in on December 8, 2003. The platform
has remained in lighthouse mode since 2003 and Hilcorp now operates the SMGSU and
performs routine maintenance and inspections on the platform.
The Middle Ground Shoal Field continues to produce from platforms located on each of two
leases — ADL 18754 from the A Platform and ADL 18756 from the C Platform. The leases have
been held by production from the two platforms since the field came online in 1965. The lease
terms do not require the operator to provide a plan of development to the DNR. Shell operated
the MGSF until Cross Timbers Oil Company assumed operatorship in 1998. Cross Timbers
became XTO Energy, now a subsidiary of ExxonMobil, which operated the field until its sale to
Hilcorp in 2015. Hilcorp's recent purchases of the NMGSF, MGSF, and SMGSU constitutes the
first time the three fields' ownership has been aligned under a single company.
Hilcorp submitted the Application on May 12, 2016 and simultaneously paid the $500.00 unit
expansion application filing fee, in accordance with 11 AAC 83.306 and 11 AAC
05.010(a)(10)(D), respectively. The Application included: Exhibit A (Attachment A), a map of
the proposed expanded unit, the MGSU; Exhibit B (Attachment B), legally describing the
proposed expanded unit area, its leases, and ownership interests; Attachment 1, a map of the
existing Tertiary System PA; and Attachment 2, legally describing the existing Tertiary System
Middle Ground Shoal Unit: Approval of the Application Page 4 of 19
to Expand & Rename the South Middle Ground Shoal Unit g
PA. The Division notified Hilcorp by email, dated May 24, 2016, that the Application was
complete.
The Division published a public notice in the Alaska Dispatch News and Peninsula Clarion on
May 29, 2016 in accordance with 1 I AAC 83.311. On June 25, 2016, the Division issued a
revised public notice. Copies of the Application and the public notice were provided to interested
parties. The Division provided public notice to, among others, the Alaska Department of
Environmental Conservation, the Kenai Peninsula Borough, the City of Kenai, the Village of
Tyonek, the Salamatof Native Association, Cook Inlet Region, Incorporated, the Soldotna
Postmaster, and the radio station KDLL in Kenai. The notice was also published on the State of
Alaska Public Notice website and the Division's website. The public notices invited interested
parties and members of the public to submit comments by July 25, 2016. No comments were
received.
The leases proposed for inclusion within the proposed expanded SMGSU are summarized below.
Tract
Lease No.
Lease
Acres
Royalty
W1O
Description
No.
Date
3
18754
9/1/1962
3746.0
12.50%
Hilcorp - 100%
T. 8 N., R. 12W., SM, AK
Sec. 6, All;
Sec. 7, All.
T. 8 N., R. 13W., SM, AK
Sec. 1, All;
Sec. 2, All;
Sec. 11, All;
Sec. 12, All.
4
18756
9/1/1962
5,120.0
12.50%
Hilcorp - 100%
T. 8 N., R. 13W., SM, AK
Sec. 13, All;
Sec. 14, All;
Sec. 15, All;
Sec. 22, All;
Sec. 23, All;
Sec. 24, All;
Sec. 25, All;
Sec. 26, All.
5
17595-1
1/31/1962
2,636.0
12.50%
Hilcorp - 100%
Segment 1
T. 9 N., R. 12W., SM, AK
Sec 19, SEI/4SW1/4,
SWI/4SEI/4;
Sec. 30, All;
Sec. 31, All.
T. 9 N., R. 13W., SM, AK
Sec. 25, All;
Sec. 36, All.
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 5 of 19
IIl. DISCUSSION OF DECISION CRITERIA
The DNR Commissioner (Commissioner) reviews applications related to units under I 1 AAC
83.303 —11 AAC 83.395. By memorandum dated September 30, 1999, the Commissioner
approved a revision of Department Order 003 and delegated this authority to the Division
Director.
The Commissioner will approve an expanded unit upon a finding that it will (1) promote
conservation of all natural resources, including all or part of an oil or gas pool, field, or like area;
(2) promote the prevention of economic and physical waste; and (3) provide for the protection of
all parties of interest including the state. 11 AAC 83.303(a).
In evaluating these three criteria, the Commissioner will consider (1) the environmental costs and
benefits of unitized exploration or development; (2) the geological and engineering
characteristics of the potential hydrocarbon accumulation or reservoir proposed for unitization;
(3) prior exploration activities in the proposed unit area; (4) the applicant's plans for exploration
or development of the unit area; (5) the economic costs and benefits to the state; and (6) any
other relevant factors, including measures to mitigate impacts identified above, the commissioner
determines necessary or advisable to protect the public interest. 11 AAC 83.303(b).
A discussion of the subsection (b) criteria, as they apply to the Application, is set out directly
below, followed by a discussion of the subsection (a) criteria.
A. Decision Criteria considered under 11 AAC 83.303(b)
Environmental Costs and Benefits
The expansion area is habitat for various mammals, waterfowl, and fish. Area residents may use
this area for subsistence hunting and fishing. Oil and gas activity in the proposed unit area may
affect some wildlife habitat and some subsistence activity. The DNR develops lease stipulations
through the lease sale process to mitigate the potential environmental impacts from oil and gas
activity.
The DNR also considers environmental issues during the lease sale process, and the unit plan of
operations approval process. Alaska statutes require the DNR to give public notice and issue a
written finding before disposal of the state's oil and gas resources. AS 38.05.035(e);
AS 38.05.945; 11 AAC 82.415. In the written best interest finding, the Commissioner may
impose additional conditions or limitations beyond those imposed by law. AS 38.05.035(e).
Approval of the SMGSU expansion has no direct environmental impact. This decision is an
administrative action and does not authorize any on -the -ground activity. The unit expansion does
not entail any environmental costs in addition to those that may occur when permits to conduct
lease -by -lease exploration or development are issued. The Unit Operator must obtain approval of
a plan of operations from the State and permits from various agencies on State leases prior to
commencing any operations within the unit area, including drilling a well or wells. 1 I AAC
83.346. Potential effects on the environment are analyzed when permits to conduct exploration
or development in the unit area are reviewed. Hilcorp is operating under an approved plan of
operations and plan of development where required.
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 6 of 19
Unitization may provide an environmental benefit by enabling joint development of multiple
lessees thereby reducing redundant development. The proposed expansion of the unit will not
provide a significant joint development benefit of pulling different lessees together in a common
development. Hilcorp is the single working interest owner of the NMGSF, MGSF, and SMGSU.
Thus, Hilcorp does not need to unitize the leases in order to effect joint development. These
fields have been producing through lease operations with disparate leaseholder interest for 50
years. Expanding the SMGSU may provide opportunities to conserve natural resources but it is
not necessary to effect joint development on the reservoir.
2. Prior Exploration and Geological and Engineering Characteristics
South Middle Ground Shoal was discovered by Amoco et al in 1965 with the drilling of an
expendable well. The unit is located on the southern nose of the NE -SW trending Middle Ground
Shoal thrusted anticlinal structure. Production commenced in 1967 under primary recovery.
Estimated Original -Oil -in Place (OOIP) for the Hemlock reservoir within the unit area was
234 Million Stock Tank Barrels (MMSTB) with primary production coming from the higher
permeability intervals G-1 and G-2. The OOIP within the Hemlock G Sands was estimated to be
120 MMSTB. Peak rate during primary recovery was 9,000 Barrels of Oil Per Day (BOPD) from
10 producing oil wells.
A waterflood/pressure maintenance program commenced in 1969 after reservoir pressure had
depleted to approximately 2000 psi. At that time, three producing wells (Di -7, D-11 and Di -12)
were converted to injection at a total rate of 10,000 barrels of water per day. Additional injection
occurred at the C Platform line well between the Shell and Amoco et al leases.
Peak production in response to the waterflood was 7000 BOPD in 1970. The waterflood began to
break through in most producing wells in the early 1970's and oil production went into
precipitous decline in 1973 as the more permeable G-1 and G-2 layers of the Hemlock formation
began to water out. Three development wells were drilled in 1975-76 (Di -13, D-14, & Di -15)
and added initial oil rates of over 3000 BOPD and reserves of 5.8 MMSTB, which represents
two thirds of the oil recovered from SMGS since 1974. The waterflood was terminated by
Amoco in 1987 for economic reasons after oil production had declined to 700 BOPD. When
Unocal acquired the property from Amoco in September 1990, SMGSU production had declined
to 420 BOPD.
Dillon platform production was shut-in on December 8, 2003. Union stated in a letter to the
Division dated February 18, 2003 that the SMGSU had reached its economic limit from existing
producing horizons and was depleted. Cumulative SMGSU production is 28.1 MMSTB, which
represents a recovery of 23.2% of the Hemlock G OOIP and 43.8% of the moveable oil -in-place
in the developed area. Union was developing a well abandonment program for 16 shut-in
platform wells in 2010.
Hilcorp provided confidential geological, geophysical, and engineering data to support the
proposal to unitize the NMGSF, MGSF, and SMGSU. The data provided supports the
implication that a single oil reservoir underlays all five leases proposed for unit expansion. The
available technical data justifies the expansion of the SMGSU to include the leases in the MGSF
and NMGSF.
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 7 of 19
3. Plans of Development
On March 3, 2016, Hilcorp submitted annual plans of development for the SMGSU, MGSF, and
NMGSF. Hilcorp provided the Division with a technical presentation to outline their future plans
to increase drilling and oil production from the A and C Platforms. In 2015, Hilcorp acquired
3-D seismic data over the NMGSF and MGSF and began interpretation of the data. A
comprehensive field study was initiated at the MGSF while a reservoir study of the NMGSF was
completed during the 2015 POD period. No significant activities were conducted in the SMGSU.
The Division approved the 2017 NMGSF and SMGSU PODS on April 21, 2016.
Hilcorp plans to bring the Baker Platform in the NMGSF back online in 2017 if economic
circumstances and gas supply markets improve. In the meantime, Hilcorp is continuing work to
replace living quarters damaged by fire and to re -activate the gas dehydration system at the
Baker Platform. No projects are planned for the Dillon Platform and the SMGSU in 2016;
however, Hilcorp maintains its estimate for returning the SMGSU to production in 2018 through
extended reach wells from the C Platform. Hilcorp has indicated these wells may be drilled as
soon as the 2017 POD period.
Currently, the Division receives separate PODs for the SMGSU and NMGSF and no POD for
MGSF. By expanding the SMGSU to include the other two Middle Ground Shoal fields, the
Division would formalize its receipt of a single POD for the Middle Ground Shoal fields and
additional data on the MGSF the Division was not previously receiving. A single POD allows the
Division and Hilcorp to evaluate the Middle Ground Shoal reservoir in its entirety. Further,
expanding the SMGSU will reduce administrative overhead for the state by evaluating and
adjudicating a single POD for the area.
4. The Economic Costs and Benefits to the State and Other Relevant Factors
The State's primary economic interest in oil and gas leases is in the royalty and taxes received on
production. Expanding SMGSU creates a potential loss of royalty revenue, but the loss is
speculative, minimal, and offset by the potential of increased oil production. Currently, any gas
that Hilcorp produces from NMGSF, MSGSF, or SMGSU, and uses as fuel gas in one of the
other fields would be a royalty bearing event. Expanding the unit to include all three fields would
eliminate this potential royalty because gas produced within the unit for unit operations is not a
royalty bearing event. Gas production allocated from the NMGSF is used as fuel gas to aid in
production of oil at the MGSF, but serves as only a small amount of the total needed to
adequately supply the A and C Platforms. Similarly, if Hilcorp resumed operations of the Baker
Platform on the NMGSF, gas used as fuel gas in SMGSU or MGSF would no longer be royalty
bearing if the unit is expanded. The Baker Platform in the NMGSF began producing gas in
April 2013 until the BA -14 well watered out in July 2013. The average monthly royalty
production for the Baker Platform during that time was 3.134 Million Cubic Feet per month.
Prospects for future gas production from the NMGSF seem limited, so the risk of lost royalty is
low. Revenues lost in gas production royalties would also be regained through added oil
production and extending the lifetime of the platforms in the MGSF which helps maximize
recovery and eliminate waste.
Unitizing the three fields places additional unit regulatory hurdles, specific to default and
termination provisions, for the State to navigate in the case production ceases at MGSU or
another platform is lighthoused. The Application requests expansion of a unit which has not
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 8 of 19
produced oil or gas since December 2003. The Dillon Platform is in lighthouse mode with all
wells plugged and abandoned. According to Hilcorp, there are no facilities, living quarters, or
associated equipment left on the platform. The Baker Platform is also in lighthouse mode with
little remaining infrastructure on the platform after an October 2014 fire. The NMGSF lease
(ADL 17595) has not expired due to extension by production under provisions of the lease.
Wells from the A Platforms are draining the NMGSF and, therefore, the leases do not expire.
The SMGSU term has been extended by the presence of a unit certified well and unit operations
being conducted in accordance with approved plans of development. Hilcorp owns 14 oil and gas
platforms in the Cook Inlet with most of those platform built in the 1960s. While many of these
platforms continue to produce oil and gas, it is in the interest of all parties to understand the
dismantlement, removal, and restoration (DR&R) expectations for the future.
At this time, unitizing the three fields affords the best chance for reactivating the platforms and
identifying new oil and gas targets. Hileorp's recent PODS have stated the platforms will be
brought online by 2018. The public's interest is best served by restarting the Baker and Dillon
Platforms to bring production back online for added revenue and maximizing recovery. The
Baker and Dillon Platforms have both stood in lighthouse mode for more than a decade.
Perpetual lighthousing of platforms presents a potential risk to the State, but there are few
statutory and regulatory mechanisms in place to address platform DR&R. It is in the interest of
the public, state, and Hilcorp to begin to further address platform DR&R standards and
expectation for end -of -field life.
The Application did not include Segment 2 of ADL 17595 within the expanded unit. Segment 2
is not allocated any production, held by a certified well, or contributing to production. Hilcorp
has elected to relinquish Segment 2 of ADL 17595 would be relinquished after the SMGSU is
expanded. The lease will be returned to the State to be offered in a future State oil and gas
areawide lease sale. This protects the public interest in enhancing competition for state lands by
making the Segment 2 area available for future lease with revenue from a bonus bid.
The SMGSU, MGSF and NMGSF leases—ADLs 18744, 18746, 18756, 18754, and 17595—are
not written on current lease forms. Hilcorp has requested to continue using the SMGSU
agreement from 1967 rather than form a new unit with a new agreement. In order to protect the
public's interest, the Commissioner may invoke his authority under AS 38.05.180(p) and
paragraph 32 (Unitization) of the leases, with the lessee's consent, to change, establish, or revoke
requirements under the lease upon unitization. Hilcorp has agreed for the five leases to be
modified and amended to conform to the current lease language found in lease form DOG
201503W, as specified below:
a. Delete paragraphs 10 (Minimum royalty), 12 (Discovery royalty), 14 (RIK), 15 (RIV)
and 16 (Price).
b. Add subparagraphs (c) and (d) from paragraph 5 (Rentals).
c. Add paragraphs 7 (Apportionment of royalty), 9 (Plan of Operations), 10 (POD), 12
(Directional drilling), 34 (Definitions), 36 (Value), 37 (RIV), and 38 (RIK).
Recognizing the cost associated with the loss of royalties from fuel gas, risk of adding regulatory
impediments, and expanding a non -producing unit with a 50 -year old unit agreement, the
public's interest can be protected by mitigating potential impact through this decision.
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 9 of 19
B. Decision Criteria considered under I 1 AAC 83.303(a)
1. Promote the Conservation of All Natural Resources
A unit may be formed under AS 38.05.180(p) "[tlo conserve the natural resources of all or a part
of an oil or gas pool, field, or like area." Conservation of the natural resources of all or part of an
oil or gas pool, field or like area means "maximizing the efficient recovery of oil and gas and
minimizing the adverse impacts on the surface and other resources." 11 AAC 83.395(9). The
unitization of oil and gas reservoirs or accumulations and the formation and expansion of unit
areas to develop hydrocarbon -bearing reservoirs or accumulations are well -accepted means of
hydrocarbon conservation. Unitization, with development occurring under the terms of a unit
agreement, can promote efficient evaluation and development of the State's resources, and
minimize impacts to the area's cultural, biological, and environmental resources.
Expansion of an existing unit, with development occurring under the terms of a unit agreement,
promotes efficient evaluation and development of the State's resources, and minimizes impacts
to the area's cultural, biological, and environmental resources.
2. The Prevention of Economic and Physical Waste
Unitization, as opposed to activity on a lease -by -lease basis, may prevent economic and physical
waste. Economic waste is often referred to as the drilling of wells in excess of the number
necessary for the efficient recovery of the oil and gas in place. Physical waste, among other
things, includes the inefficient, excessive, or improper use of, or unnecessary dissipation of,
reservoir energy.
Unitization may also prevent economic and physical waste by eliminating redundant
expenditures for a given level of production, or by increasing ultimate recovery with the
adoption of a unified reservoir management plan. Annual approval of the SMGSU development
activities as described in future plans of development must also provide for the prevention of
economic and physical waste. Unitizing the three fields integrates the infrastructure and facilities
and helps maximize recovery with fewer expenditures on items such as wells and meters.
Unitizing the fields makes the proposed SMGSU more competitive for Hilcorp's internal funding
for wells and projects as opposed to submitting project funding on the three -field basis. Making
the unit a more attractive asset for internal funding could increase potential resources recovery
and feasibility of bringing lighthoused platforms back online.
3. The Protection of All Parties of Interest, Including the State
The people of Alaska have an interest in the development of the State's oil and gas resources to
maximize the economic and physical recovery of the resources. AS 38.05.180(a). Approval of
this expansion under annually -approved plans of development will provide for continued review
and approval of Hilcorp's plans to develop the SMGSU in a manner that will maximize
economic and physical recovery. Combining interests and operating under the terms of the
SMGSU Agreement and the new Operating Agreement ensures an equitable allocation of costs
and revenues commensurate with the resources.
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 10 of 19
The SMGSU expansion protects the economic interests of Hilcorp and the State. The expansion
promotes the State's economic interests because hydrocarbon recovery will be maximized and
additional production -based revenue will be derived from the increased production. Diligent
exploration and development under a single approved unit plan promotes the State's interest.
Operating under the SMGSU Agreement provides for accurate reporting and record keeping,
State approval of plans of exploration and development and operating procedures, royalty
settlement, and in-kind taking, all of which will further the State's interest.
The public interest is also advanced by updating lease terms to reflect current exploration and
development circumstances, returning state land to lease sales for future bonus bid revenue, and
combining leases to evaluate and administer the Middle Ground Shoal fields as a single
development unit.
IV. FINDINGS AND DECISION
A. The Conservation of All Natural Resources
Expansion of the SMGSU will provide for continued development of the expansion area
under the SMGSU Agreement and will maximize the efficient recovery of oil and gas and
minimize the adverse impacts on the surface and other resources.
2. The unitized development and operation of the expansion leases will reduce the amount
of land and fish and wildlife habitat that would otherwise be disrupted by individual lease
development. This reduction in environmental impacts and preservation of subsistence
access is in the public interest.
There is potential for environmental impacts associated with development. All unit
development must proceed according to an approved plan of development. Additionally,
before undertaking any specific operations, the Unit Operator must now submit a unit
Plan of Operations to the Division and other appropriate state and local agencies for
review and approval. The lessees may not commence any drilling or development
operations until all agencies have granted the required permits. The leases may also be
subject to mitigation measures, compliance with which is reviewed when the operator
submits a Plan of Operations. DNR may also amend a proposed unit Plan of Operations
as necessary to protect the State's interest. Compliance with mitigation measures will
minimize, reduce, or completely avoid adverse environmental impacts.
B. The Prevention of Economic and Physical Waste
Hilcorp submitted geological, geophysical and engineering data to the Division in support
of the Application. Division technical staff determined that the expanded SMGSU
acreage encompasses all or part of one or more oil and gas reservoirs.
2. The available geological, geophysical, and engineering data justify including the
proposed land in the MGSU, as described in Section III A, 2. in this decision.
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page I 1 of 19
3. The production of hydrocarbons through the existing production and processing facilities
reduces the environmental impact of the additional production. Using existing facilities will
avoid unnecessary duplication of development efforts on and beneath the surface.
C. The Protection of All Parties in Interest, Including the State
1. The unit expansion as approved protects all parties' interests including the people of
Alaska who have an interest in the development of the State's oil and gas resources to
maximize the economic and physical recovery of the resources.
2. The economic, geological, geophysical, and engineering data that Hilcorp provided
reasonably justify the inclusion of the SMGSU expansion acreage under the terms of the
applicable regulations governing formation, expansion, and operation of oil and gas units
and participating areas (11 AAC 83.301 —11 AAC 83.395) and the terms and conditions
under which these lands were leased from the State.
3. Hilcorp holds sufficient interest in the unit area to give reasonably effective control of
operations.
4. The unit expansion meets the requirements of 11 AAC 83.303.
5. The Division complied with the public notice requirements of 11 AAC 83.311.
6. The unit expansion will not diminish access to public and navigable waters beyond those
limitations (if any) imposed by law or already contained in the oil and gas leases covered
by this decision.
7. The SMGSU Agreement provides for additional expansions and contractions of the unit
area in the future, as warranted by data obtained by exploration or otherwise. The
SMGSU Agreement thereby protects the public interest, the rights of the parties, and the
correlative rights of adjacent landowners.
8. The SMGSU Agreement, as amended, will remain in effect for the SMGSU and become
effective for the expansion area leases as of the effective date of the expansion decision.
The SMGSU and expansion leases—ADLs 18744, 18746, 18756, 18754, and 17595—are
not written on the current lease form. These leases will be modified and amended to
conform to the current lease language found in lease form DOG 201503W as follows.
a. Delete paragraphs 10 (Minimum royalty), 12 (Discovery royalty), 14 (RIK), 15
(RIV) and 16 (Price).
b. Add subparagraphs (c) and (d) from paragraph 5 (Rentals).
C. Add paragraphs 7 (Apportionment of royalty), 9 (Plan of Operations), 10 (POD),
12 (Directional drilling), 34 (Definitions), 36 (Value), 37 (RIV), and 38 (RIK).
9. The approved expanded unit is effective September 21, 2016.
10. The leases approved for inclusion in the expanded South Middle Ground Shoal Unit are
Middle Ground Shoal Unit: Approval of the Application
to Expand & Rename the South Middle Ground Shoal Unit Page 12 of 19
as follows:
Tract
Lease
Lease
Acres
Royalty
WIO
tion
;Y�8�N.,R.12W.,SKAKc.
No.
3
No.
18754
Date
7/18/1962
3746.0
12.50%
Hilcorp - 100%
�1
sec. 7, All,
T. 8 N., R. 13W., SM, AK
sec. 1, All;
sec. 2, All;
sec. 11, All;
sec. 12, All.
4
18756
7/18/1962
5,120.0
12.50%
Hilcorp - 100%
T. eN-, R. 1131W., SM, AK
sec. 14, All;
sec. 15, All;
sec. 22, All;
sec. 23, All;
sec. 24, All;
sec. 25, All;
sec. 26, All.
5
17595-1
1/31/1962
2,636.0
12.50%
Hilcorp -100%
Segment 1
T. 9 N., R. 12W., SM, AK
sec. 19: SEI/4SW1/4,
SW 1 /4SE 1 /4;
sec. 30, All;
sec. 31, All.
T. 9 N., R. 13W., SM, AK
sec. 25, All;
sec. 36, All.
11. The Application included Exhibits A and B. Hilcorp shall submit new Exhibits A and B
within 60 days of the issuance of this decision.
12. Hilcorp has agreed to relinquish Segment 2 of ADL 17595 upon the issuance of the unit
expansion decision. The legal description of Segment 2 of ADL 17595 is as noted below.
ADL 17595, Segment 2
Seward Meridian, Alaska
T. 9 N., R. 12 W.,
sec. 17, All, 640.00 acres;
sec. 18, All, 634.00 acres;
sec. 19, NI/2, SWI/4SW1/4, N1/2SW1/4, SEI/4SE1/4, Nl/2SEl/4, 556.00 acres;
sec. 20, All, 640.00 acres.
The area described contains 2,470.00 acres, more or less.
Middle Ground Shoal Unit: Approval of the Application Page 13 of 19
to Expand & Rename the South Middle Ground Shoal Unit g
13. Future MGSU PODS submitted to the Division should address the operations to restart
production at the Baker and Dillon Platform with timelines and detailed information on
efforts to bring the platforms online. The timeline for each platform should include
measurable and verifiable milestones. In order to protect the public's interest, Hilcorp and
the State are also commencing discussions on DR&R expectations for platforms and
offshore location clearance in Cook Inlet.
For the reasons discussed in this Findings and Decision, I hereby approve the SMGSU expansion
and name change to the Middle Ground Shoal Unit.
An eligible person affected by this decision may appeal it in accordance with 11 AAC 02. Any
appeal must be received within 20 calendar days after the date of "issuance" of this decision, as
defined in 11 AAC 02.040(c) and (d), and may be mailed or delivered to Andrew T. Mack,
Commissioner, Department of Natural Resources, 550 W 7th Avenue, Suite 1400, Anchorage,
AK 99501; faxed to 1-907-269-8918; or sent by electronic mail to dnr.appeals@alaska.gov. This
decision takes effect immediately. An eligible person must first appeal this decision in
accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC
02 may be obtained from any regional information office of the Department of Natural
Resources.
If you have any questions regarding this decision, contact Kyle Smith with the Division at 907-
269-8807, or by email at. Kyle.Smith@alaska.gov
Com A. Feige
Director
Division of Oil and Gas
cc: Department of Law
V. ATTACHMENTS
1. Middle Ground Shoal Unit Proposed Exhibit A
Description of Lands within the Expanded Unit
2. Middle Ground Shoal Unit Proposed Exhibit B
Map of Expanded Unit Area
�21/�
Date
Middle Ground Shoal Unit: Approval of the Application Pae 14 of 19
to Expand & Rename the South Middle Ground Shoal Unit g
Middle Ground Shoal Unit Proposed Exhibit A
Map of the Proposed Expanded Unit
Middle Ground Shoal Unit: Approval of the Application Page I S of 19
to Expand & Renamae the South Middle Ground Shoal Unit S
6
3
2
1
6 5
21
22
ADLO18772
Y4
19
20
20
21
23
ADLO18754
7 8.. 9
10
11
w�
S009NO13W
18 17 16
15
14
S009NO12W
18 17
26
S008NO12W
25
30
29
28
2
20
19 20 21
22
":` z1 X11
24
19 ADL389919
om
23
30
Aree of Davi n1-�
28
27
26
25
30
ADL391597 29
29
oaa.om
'n
Lw..P
34
}senee
d )?°"°�°
35
36
31
32
33
1 .w
6
3
2
1
6 5
I
Cgpy,pMOT01a EaM1 HERE. ,N"
Euwcr:EM. pataae, UE09,Ni8
....
ADLO18754
7 8.. 9
10
11
12
7 8
18 17 16
15
14
13
18 17
S008NO12W
SOO8N013W
3
20
19 20 21
22
":` z1 X11
24
19 ADL389919
23
30
28
27
26
25
30
ADL391597 29
29
36 32
ADL3914323 33 34 35 ADL 3926- 31
31
2 Q Unit Tracts --
Stale Leases
ADL018746 5
6 5 4 3 1
ADL378114 ADL391838
7 8 S007NO13W 9 1� ADL`744 11 12 7 S007NO12W8
Middle Ground Shoal Unit
Exhibit A 05 '
� Miles
Mapoale: 411412015
Middle Ground Shoal Unit: Approval of the Application page 16 of 19
to Expand & Rename the South Middle Ground Shoal Unit
2, Middle Ground Shoal Unit Proposed Exhibit B
Description of Lands within the Proposed Expansion of Unit Area
Middle Ground Shoal Unit: Approval of the Application Page 17 of 19
to Expand & Rename the South Middle Ground Shoal Unit
o 3:
to a
x a.
a0
�6
�a
`3 to
Cs'
C
Cn
a C
a °=
tD
O N
C4
O N
O
C O
O
K
ro
to
OO
N
O
M
Exhibit B
Middle Ground Shoal Unit
Effective May 1, 2013
TM, RI3W.SM, AR 1,0800000 HAK%605838 Satef Al
o
Section 02; WV2NE1/4,NWI/4, SWI/4: ADLM 18746 Depaasd
Re ourcd
400 a s
Kfi�o3: sP2/4NEv4, EvzsEv4; I20
TBN, RI3W. SM, AK
Seedon35: NEP4,NWI/4,SWU4,
WInSEI/4, 560 teres;
T8N. R12W, SM, AK
.' ADLN 18754 Depemnent ofNm.l
Sec 06: Mi. 593..1:
Resound
Working
working
TSN, RUW, SM, AK
Mineral
Mineral Royalty ORRI
ORRI Interest
Interest
Owner °h
Secdon 11: All, 640 acro
Tract
Owner
Interest Percent Owner
Percent Ownership
5,1200000 HAK4589104 Stateof Alaska,
ADL6 15756 Department of Nawre
Tract Tract Legal Description
Acreage Lease M
S
Section 14: Mi, 640 acres:
Semon 15'. All, 640 ecsd;
.W IOO
Secl10022: All, 640 acrta:
Smfim 23: All, 640 arts:
Hilcory Alaska, LLC
Secdon25: All, 640aercs;
800000
Saaof AMd
100.00°5 12.500°5
1 T'M,R13W, SM, Alk
AnL#605839
ADLIt 15744
Depatbnent ofNed°al
Section l0: NEI/4NE1/4;400aerts:
Rdourtes
Section ll: NW/4NWV4; 40.0 acrd.
TM, RI3W.SM, AR 1,0800000 HAK%605838 Satef Al
o
Section 02; WV2NE1/4,NWI/4, SWI/4: ADLM 18746 Depaasd
Re ourcd
400 a s
Kfi�o3: sP2/4NEv4, EvzsEv4; I20
TBN, RI3W. SM, AK
Seedon35: NEP4,NWI/4,SWU4,
WInSEI/4, 560 teres;
T8N. R12W, SM, AK
.' ADLN 18754 Depemnent ofNm.l
Sec 06: Mi. 593..1:
Resound
Secdon 07'. All, 593 acres:
TSN, RUW, SM, AK
Semon 01: AIL 640 saes:
Secsian 02. All, 640 add:
Secdon 11: All, 640 acro
Semon 12: AIL b40 scro;
TSN,RI3W,SM,AK
5,1200000 HAK4589104 Stateof Alaska,
ADL6 15756 Department of Nawre
Sation 13'. All, 640 acrd:
Resources
Section 14: Mi, 640 acres:
Semon 15'. All, 640 ecsd;
Secl10022: All, 640 acrta:
Smfim 23: All, 640 arts:
Secfim 24: All, 640 acres:
Secdon25: All, 640aercs;
Secdon 26'. All, 640 acres;
Middy Cvoond Shoal Unit Exhibit 8
Lot Update: 4/11/2016
P'S 1 of t
e28OOL'J
ens «pun moo !" qlnosoql a £ _pulu
uo!A/dv A fjUA: nluo a punolDi
i
�|
!m
Dr
°Q w � o CD - C G P* C) a. 3 C7
n W w O•C
O N Com'• N J �... 'O y i•i p 0 N f1
CD CD 0 S
CD 0
0 CD 0 N o, tlQ .v E" ry I t"' a C"
o
co w �• 9 w < o o
n ° o C CD Z. w
icy O\O � o UaQ �G aN ..
W NW �' ° O° C N ACD 0 m CD O N O r
O O
C, �' f1cl O CD N r'
�o
N� w a. a� ao a y Giy�
-j 00 cr x''J 0r PD < a' vi W ii f3
w„ wqQ w 9 yA
�a.a `DoaQ r nCi7M
W NM
y Off' 'J "a� n QQA
rA
CD
CD CD ft
° 0 O 4: cyo Oti E' N i=
UQ qq
CD
c °Q � N a � �
0
C6 Cl.
cCDCD
o o ti c P, O y n o
m G. 0q .-. ° p w Inaq o ti O
O- q coo C CD co
o
> CA
o n a O
Y °
., .Ox z
CN ;3 o° N p m cn r m
CD ot CD
CD CD
C�
CD< n W owe a'
N 0 0 h 0 NP CD y
STATE OF ALASKA
ADVERTISING
ORDER
NOTICE TO PUBLISHER
SUBMIT INVOICE SHOWING ADVERTISING ORDER NO.CERTO'IED
OF PUBLICATION WITH ATTACHED COPY OF ADRTISMENT.
AFFmAvT VE
ADVERTISING ORDER NUMBER
AO -17-004
FROM:
Alaska Oil and Gas Conservation Commission
AGENCY CONTACT:
Jody Colombie/Samantha Carlisle
DATE OF A.O.AGENCY
08/18/16
PHONE:
(907 279-1433
333 West 7th Avenue
Anchorage, Alaska 99501
DATES ADVERTISEMENT REQUIRED:
COMPANY CONTACT NAME:
PHONE NUMBER:
ASAP
FAX NUMBER:
(907) 276-7542
TO PUBLISHER:
Alaska Dispatch News
SPECIAL INSTRUCTIONS:
PO Box 149001
Anchors e, Alaska 99514
TYPE OF ADVERTISEMENT:
FV LEGAL I DISPLAY CLASSIFIED r OTHER (Specify below)
DESCRIPTION PRICE
CO -16-016
Initials of who pre ared AO:
Alaska Non -Taxable 92-600185
:sysiii[:mVOICeSuvwuiFruv[idtiS0.4G.
N+1£U gFP1Pi1kiT:Q?:':
p:Mit inw.Tf WiTA.A, 'r¢G— .6... PY:QF::
'.AUVERTIBMENT:T6
Department of Administration
Division of AOGCC
333 West 7th Avenue
Anchorage, Alaska 99501
PaI of 1
e
Total Of
All
REF Type Number
I PVN ADN84501
Amount out. Comments
2 AID AO -17-004
3
4
FIN AMOUNT SY Appr Unit PGM LGR Object FY DIST LIQ
1 17 021147717 3046 17
2
3
4
5
P ha n thority igna re Telephone Number
Purchasing Authonty Sone: TNR.: 79'3 —/Z.3
'jz il-vy-p�JC 1�ulC
I. A.O. A and receiving agency name must appear on all Invoices and documents ming to this ase.
2. The state is registered for tat free transactions under Chapter 32, IRS code. Registration number 92-73-0OOfi K. Items are far the ezUusive use of the slate and not la
resale.
:77M
D� TWBUTIQN
Dtvlslon FicaVOriginalAO
..... ..
:: Cepies: Pptiltsf�tP tfyxeilj, Division Fistalr $eceivirrg.
Form: 02-901
Revised: 8/18/2016
270227 RECEIVED
0001391370 AUG 25 2016
$19424 AOGCC
AFFIDAVIT OF PUBLICATION
STATE OF ALASKA
THIRD JUDICIAL DISTRICT
Emma Dunlap
being first duly sworn on oath deposes and
says that he/she is a representative of the
Alaska Dispatch News, a daily newspaper.
That said newspaper has been approved
by the Third Judicial Court, Anchorage,
Alaska, and it now and has been published
in the English language continually as a
daily newspaper in Anchorage, Alaska, and
it is now and during all said time was
printed in an office maintained at the
aforesaid place of publication of said
newspaper. That the annexed is a copy of
an advertisement as it was published in
regular issues (and not in supplemental
form) of said newspaper on
August 19, 2016
and that such newspaper was regularly
distributed to its subscribers during all of
said period. That the full amount of the fee
charged for the foregoing publication is not
in excess of the rate charged private
individuals. C�
Signed
Subscribed and sworn to before me
this 19th day of Au list, 2�011�6
H"a
Notary Public in and for
The State of Alaska.
Third Division
Anchorage, Alaska
MY COMMISSION EXPIRES
aIa3L(2�i9
Notice of Public Hearing
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Re: Docket Number: C0-16-016
The application of Hilcorp Alaska, LLC to amend Conservation
Order 44
Hilcorp Alaska, LLC by letter dated August 16, 2016, requests the Alaska
Oil and Gas Conservation Commission (AOGCC) issue an order
amending Conservation Order 44, Middle Ground Shoal Field.
The AOGCC has tentatively scheduled a public hearing on this
application for September 20, 2016, at 9:00 a.m. at 333 West 7th
Avenue, Anchorage, Alaska 99501. To request that the tentatively
AOGCC no lateritha4:30 p.m. onheld, a s Sepan tember 8, 016.uest must E tiled with the
If a request for a hearing is not timely filed, the AOGCC may consider
the
the hearing, an
(907without
2791433 ater hearing. ptember 9, 2To learn if 01AOGCC will
In addition, written comments regarding this application may be
99501IttCto the ommem50Gmustat 3be 3receivetl7 noAlatevenuethanc430 Pmlasok1l1
September 16, 2016, except that, if a hearing Is held, comments must
the
be received no later than conclusion of the September 20, 2016
hearing. be N Y
comment or atte d the hearincg,,acorlte.L hedAtOGCC at (907) 2 9�1�433
no later than September 15, 2016.
//signature on file//
Daniel T. Seamount, Jr.
AO -17-004
Published: August 19, 2016
Notary Public
/ BRITNEY L. THOMPSON
State of Alaska
^�y Commission Expires Feb 23, 20'
Carlisle, Samantha J (DOA)
From: Carlisle, Samantha J (DOA)
Sent: Thursday, August 18, 2016 2:17 PM
To: Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov); Bender, Makana K (DOA)
(makana.bender@alaska.gov); Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov); Bixby,
Brian D (DOA); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha
1 (DOA); Colombie, Jody 1 (DOA) Qody.colombie@alaska.gov); Cook, Guy D (DOA);
Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine E (DOA); Foerster,
Catherine P (DOA) (cathy.foerster@alaska.gov); French, Hollis (DOA); Frystacky, Michal
(michal.frystacky@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Guhl,
Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Herrera, Matthew F (DOA); Hill,
Johnnie W (DOA); Jones, Jeffery B (DOA) Qeff Jones@alaska.gov); Kair, Michael N (DOA);
Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored)
Qoseph.mumm@alaska.gov); Noble, Robert C (DOA) (bob.noble@alaska.gov);
Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov); Pasqual, Maria (DOA)
(maria.pasqual@alaska.gov); Quick, Michael (DOA sponsored); Regg, James B (DOA)
oim.regg@alaska.gov); Roby, David S (DOA) (dave.roby@alaska.gov); Scheve, Charles M
(DOA) (chuck.scheve@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov);
Seamount, Dan T (DOA) (dan.seamount@alaska.gov); Singh, Angela K (DOA)
(angela.singh@alaska.gov); Wallace, Chris D (DOA) (chris.wallace@alaska.gov); AK, GWO
Projects Well Integrity, AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban;
Alexander Bridge; Allen Huckabay; Andrew Vandedack, Ann Danielson; Anna Raff;
Barbara F Fullmer, bbritch; Becky Bohrer; Bill Bredar; Bob; Brian Havelock; Bruce Webb;
Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Crandall, Krissell; D
Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy; David House; David
McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; DNROG Units; Donna
Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX);
Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR);
Gregg Nady; Gretchen Stoddard; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington
Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim
Watt; Jim White; Joe Lastufka; Joe Nicks; John Burdick; John Easton; Jon Goltz; Juanita
Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Torrance; Keith
Wiles; Kelly Sperback; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith;
Louisiana Cutler; Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley
(mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer
(meg.kremer@alaska.gov); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora;
MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nikki
Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Paul Decker
(paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L.
Skillern; Rena Delbridge; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth;
Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky;
Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith,
Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Steve Moothart
(steve.moothart@alaska.gov); Steve Quinn; Suzanne Gibson; Tamera Sheffield; Ted
Kramer, Temple Davidson; Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd
Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vicki Irwin; Vinnie
Catalano; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis;
Assmann, Aaron A, Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J
(DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Graham Smith; Hak Dickenson;
Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill;
Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W
I I
To: (Dl�r(); Marc Kuck; Marcia Hobson; Marie Steele; matt Armstrong; Mike Franger;
Morgan, Kirk A (DNR); Pascal Umekwe; Pat Galvin; Pete Dickinson; Peter Contreras;
Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke;
Susan Pollard; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW);
Wayne Wooster, William Van Dyke
Subject: Notice of Public Hearing, CO -16-016, Hilcorp
Attachments: CO -16-016 Public Hearing Notice.pdf
The application of Hilcorp Alaska, LLC to amend Conservation Order 44.
Samantha Carlisle
Ix""(1tiVe Secletar} Ill
Alaska Oil and Gas Conservation C ,nntnissiun
3a'� Wast ja, Avenue
; l n di o rap C, AK 99561
(90-1)79-1-1223
CONFIDENTIALITY NOTICE., This e -Mail message, including any atachments, contains information from the Alaska Oil and Gas Conservation
Commission (AC CCC), 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 dixlosurc of such information may violate state or federal laic. If you are an unintended recipient of this e-mail, please
delete it, without first saving or forwarding it, anis, so that the AOGCC is aware of tin: mistake in sending it to you, contact Samantha Carlisle at (9)7)
793-12.3 or Samantha Carlislex<altis!sAov.
Bernie Karl
Jack Hakkila K&K Recycling Inc.
P.O. Box 190083 P.O. Box 58055
Anchorage, AK 99519 Fairbanks, AK 99711
Penny Vadla George Vaught, Jr.
399 W. Riverview Ave. P.O. Box 13557
Soldotna, AK 99669-7714 Denver, CO 80201-3557
David W. Duffy
Richard Wagner Landman
P.O. Box 60868 Hilcorp Alaska, LLC
Fairbanks, AK 99706 P.O. Box 244027
Anchorage, AK 995244027
Gordon Severson
3201 Westmar Cir.
Anchorage, AK 995084336
Darwin Waldsmtth
P.O. Box 39309
Ninilchik, AK 99639
tJ�•\ � � I 2U�
M
Hilcorp Alaska, LLC
August 16, 2016
Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: 907/777-8414
Fax: 907/777-8301
Email: dduffv@hilcorp.Com
Cathy Foerster, Chair R E CLE! V E D
Alaska Oil and Gas Conservation Commission AU6 17 2016
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501 AOGCC
RE: Application to Amend Conservation Order 44 (Middle Ground Shoal Field)
Dear Commissioner Foerster:
Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Middle Ground Shoal Field, hereby
requests the Alaska Oil and Gas Conservation Commission ("AOGCC") take action to
amend Conservation Order 44 ("CO 44").
The Middle Ground Shoal field has the unique distinction of being the first offshore
development in both Cook Inlet and Alaska. Following discovery in 1963, production
peaked in 1968 at 43 mbopd. To date, a cumulative 215 mmstbo has been produced
field -wide.
Hilcorp acquired the Baker and Dillon Platforms in 2012, but both platforms are
currently shut-in. In 2015, Hilcorp acquired two active platforms (A and C) from XTO.
Current production from the field is approximately 1900 bopd.
As the sole operator and working interest owner of the Dillon, A, C, and Baker
Platforms, Hilcorp is pursuing unitization of the entire Middle Ground Shoal field with
the State of Alaska, Department of Natural Resources and is actively evaluating various
opportunities to return currently shut-in leases to production.
The proposed amendments to CO 44 are necessary to extend field life, increase
ultimately recovery and minimize waste.
1.0 Regulatory History of Conservation Order 44
Conservation Order 44 was issued on July 19, 1967. On September 7, 1967, AOGCC
issued Conservation Order 53 to expand the affected area of the field. On October 12,
1967, AOGCC issued Conservation Order 54 to correct and finalize the affected area
governed by CO 44.
Subsequently, AOGCC issued numerous administrative orders under CO 44, the
majority of which approved conversion of producing wells to injectors (or vice versa),
authorized well -specific downhole commingling (or injection), or approved drilling,
testing and production from wells at tighter intervals than otherwise required by
applicable well spacing restrictions. A summary of such administrative order is detailed
in Exhibit C.
Proposed Amendment, CO 44
Page 2 of 13
2.0 Proposed Order
Modification of the Affected Area
A map of the Affected Area of CO 44 (as amended by Conservation Orders 53 and 54) is
provided as Exhibit A. This map also illustrates the boundary of Area Injection Orders
Nos. 7, 8 and 9.
Hilcorp has filed an application with the Department of Natural Resources to unitize the
entire field. As such, Hilcorp respectfully requests the AOGCC to adopt the (pending)
boundary of the Middle Ground Shoal Unit as the affected area of CO 44. See Exhibit
B.
Hilcorp is the sole operator and owner of the entire Middle Ground Shoal Unit, including
operations associated with each of the four platforms (Baker, A, C, and Dillon). The
State of Alaska is the sole landowner. Utilizing the proposed Middle Ground Shoal Unit
boundary is an appropriate method of protecting the associated correlative rights of all
affected parties while promoting efficient development of this legacy field.
Rule 1: Well Spacing
Hilcorp proposes to repeal Rule 1 ("spacing pattern") in its entirety and replace it with
the following language:
There shall be no well spacing restrictions within the Affected Area, except:
• No gas well shall be drilled or completed less than 1,500 feet from the exterior
boundary of the Affected Area unless the owner and landowner is the same on
both sides of the line.
• No oil well shall be drilled or completed less than 500 feet from the exterior
boundary of the Affected Area unless the owner and the landowner is the same
on both sides of the line.
• On written request by the Operator, the AOGCC may administratively consider
and approve modifications to well spacing when justified.
Rule 2: Pool Designation
Hilcorp proposes to repeal Rule 2 ("Pool Designation") in its entirety and replace it with
the following language:
• The Middle Ground Shoal Oil Pool shall comprise the oil-bearing intervals
common to and correlating with the interval between the measured depth of 5419
feet and 9198 feet in the MGS State 17595-4 (BA -04) well.
r
Proposed Amendment, CO 44
Page 3 of 13
• The Middle Ground Shoal Gas Pool shall comprise the gas bearing intervals
common to and correlating with the interval between the measured depth of 1459
feet and 7016 feet in the MGS State 18746-1 (common name) well.
This gas pool includes and is comprised of the following three intervals:
o Upper Gas Interval 1459' to 5126' MD (COAL 31 marker).'
o Middle Gas Interval: 5126' (COAL 31 marker) to 6437 MD (COAL 41
marker) 2
o Lower Gas Interval: 6437' (COAL 41 marker) to 7016' MD (Top A
marker, coincides with top of the Middle Ground Oil pool).3
Rule 3: Permissible Commingling
Hilcorp proposes to repeal Rule 3 ("Permissible Commingling") in its entirety.
At this late stage of the field's development, consolidation of the field's original seven
oil pools (A through G) and three subsequent commingling groups (A, BCD, EFG) into a
single oil pool is necessary to maximize ultimate recovery and therefore prevent waste.
Over the last 50 years, approximately 80% of the field's recoverable oil reserves have
been produced. The field's regulatory history demonstrates a clear trend towards
consolidation of multiple oil pools to promote and enhance ultimate recovery. Full
consolidation of field's oil-bearing formations into a single oil pool will maximize field
life, reduce administrative burdens and efficiently promote ultimate recovery.
For similar reasons, Hilcorp requests the AOGCC recognize a single gas pool for the
entire Middle Ground Shoal Field. Doing so will promote and enhance ultimate
recovery from previously produced intervals (5126' to 7016'MD in the MGS State
18746-1 well) while promoting efficient exploration and development of the field's
potential gas -bearing zones above and below established production intervals.
Rule 4: Fluid Injection
Hilcorp proposes to revise Rule 4 to be consistent with the proposed single oil. Doing so
will allow injection to be commingled within a single well bore. For reservoir
management purposes, and in accordance with good engineering practices, Hilcorp will
continue to track and manage injection volumes into historic oil pool designations.
' To date, no production of this interval has occurred, other than unquantified volumes of gas vented
during the MGS State 17595-1 blowout well in 1962.
' This interval contains known gas with a cumulative production of approximately 16 BSCF and is >60%
depleted.
' To date, no gas production from this interval has occurred.
I
Proposed Amendment, CO 44
Page 4 of 13
Rule 5: Lease line well
Hilcorp proposes to repeal Rule 5 in its entirety. This rule is a relic of the field's
segmented development history and ownership. Today, Hilcorp owns and operates all
leases and associated facilities throughout the entire field. Operating the field as an
integrated unit will extend field life and increase ultimate recovery.
Rule 6: Administrative Approvals
No proposed changes to Rule 6 are requested at this time.
Rule 7: Casing and Cementing Requirements
Hilcorp proposes to repeal Rule 7 in its entirety and replace it with the following
language:
• Oil wells shall be completed in accordance with the provisions of 20 AAC
25.240(b).
• Due to significant loss zones previously encountered in the intermediate casing of
some gas wells, alternative methods (cement bond log or water flow log) will be
considered by the AOGCC on a case-by-case basis as an alternative means to
validate zonal isolation.
Rule 8 (Bottom -hole Pressure Surveys) and Rule 9 (Gas -Oil Ratio Tests)
Due to field maturity and availability of both current and historic data (e.g., 10-413 and
10-405 submissions) Hilcorp proposes to repeal both Rule 8 (Bottom Hole Pressure
Surveys) and Rule 9 (Gas -Oil Ratio Tests) in their entirety.
Should you have any technical questions, please contact Mr. Radu Girbacea at 777-8324
(roirbace @hilcorp.com) or James Young, Reservoir Engineer, at 777-8404
(jyounena hilcorp.com). At AOGCC's request, we would please to provide a technical
briefing.
Sincerely,
David W. Duffy, Landman
Hilcorp Alaska, LLC
Enclosures:
• Exhibit A: Map of Current CO 44, 53 and 54 (with AIOs 7,8 and 9)
• Exhibit B: Proposed Affected Area (to match MGS Unit Boundary)
• Exhibit C: Regulatory' History of CO 44
CC: DNR
Proposed Amendment, CO 44
Page 5 of 13
Exhibit A:
Current Affected Areas
CO 44, 53 and 54
with AIOs 7, 8 and 9
Jury 2016
MCorp Alaska. LLC
Proposed Amendment, CO 44
Page 6 of 13
Exhibit B: Proposed Affected Area of Middle Ground Shoal Field / Unit
i
Proposed Amendment, CO 44
Page 7 of 13
Exhibit C
Annotated History of CO 44
Conservation Order 44 was issued on July 19, 1967, and thereby expanded and
modified the Middle Ground Shoal Field's original pool rules established under
Conservation Order 31.
• September 7, 1967: AOGCC issued Conservation Order 53, expanding and the
affected area of Conservation Order 44.
• October 12, 1967: AOGCC issued Conservation Order 54, modifying the affected
area of Conservation Order 53 and establishing the total affected area governed by
CO 44.
• October 19, 1967: OGCC issued AA 44. 1, authorizing the conversion of well A -AA -
11 from producer to injection status.
• January 3, 1968: AOGCC issued Conservation Order 56, authorizing the
commingling of fluids from A with those from the combined BCD with those from
either the BCD pools or the EFG pools.
• March 27, 1968: AOGCC issued Conservation Order 62, granting a spacing
exception to the commingling provisions of CO 44 and No. 53 for the MGS 17595
No. 4 well to permit the commingling of fluids from the A pool with fluids from EFG
pools, subject to certain conditions.
• September 3, 1968: AOGCC issued Conservation Order 66, granting a spacing
exception otherwise required by Rule 1(b) of Conservation Order No. 53 and
therefore allowing South MGS Unit well No. 11 to be drilled.
• October 22, 1968: AOGCC issued AA 44.2 authorizing comingling of fluids for
injection into the A and BCD pools.
• December 31, 1968: AOGCC issued AA 44.3 authorizing conversion of wells A-12-
12, A-33-14 and A-11-13 from producing to injection status.
• March 24, 1969: AOGCC issued AA 44.4 authorizing conversion MGS 17595 well
Nos. 9, 10, 12, 13 and 14 to injection status.
• April 23, 1969: AOGCC issued AA 44.5 authorizing conversion of MGS Well Nos.
11 and 12 to injection status.
• May 1, 1969: AOGCC issued AA 44.6 approving the granting of an exception to the
comingling provision of CO 44 and CO 53 to permit comingling of production from
the BCD pools with production from EFG pools.
Proposed Amendment, Co 44
Page 8 of 13
• May 16, 1969: AOGCC issued AA 44.7 authorizing conversion of A-13-12 from
producing to injection status.
• October 15, 1969: AOGCC issued AA 44.8 authorizing the conversion of producing
well A-11-1 from producing to injection status.
• December 2, 1969:AOGCC issued AA 44.9 authorizing commingling of production
from both the BCD and EFG pools in the MGS 17595 No. 7.
• April 6, 1970: AOGCC issued Conservation Order No. 89, cancelling Conservation
Order 62 (permitting commingling of production from the A pool with the EFG pools
in the MGS Well No. 4) and allowing commingling of production from the same
pools under different requirements.
• July 8, 1970:AOGCC issued AA 44.10 authorizing conversion of MGS Well No. 2
from producer to injection status in the F and G pools.
• January 29, 1971: AOGCC issued AA 44.11 authorizing re-injection of produced
water into field water injection wells.
• July 14, 1971: AOGCC issued AA 44.12 authorizing conversion of well A-32-11
from producer to water injection status.
• March 15, 1971: AOGCC issued Conservation Order No. 99, allowing semiannual
production tests for the MGS 17595 Nos. 4 and 7 by measuring the proportionate
amount of fluid being produced from the commingled A and EFG pools by means of
spinner survey.
• March 21, 1973: AOGCC issued AA 44.13 authorizing conversion of MGS 17595
No. 4 from producer to water injection status.
• March 21, 1973: AOGCC issued AA 44.14 authorizing commingling of production
from the A pool with the BCD pools in the wellbore of MGS 17595 Well No. 6.
• March 21, 1973: AOGCC issued AA 44.15 authorizing use of spinner surveys for
semi-annual production tests in the MGS 17595 Well No. 6.
• May 3, 1973: AOGCC issued a spacing exception under AA 44.16 to authorize
drilling of well C-24-14 (injector).
• May 3, 1973: AOGCC issued a spacing exception under AA 44.17 to authorize
drilling of well C-44-14 (injector).
I
Proposed Amendment, CO 44
Page 9 of 13
• December 21, 1973: AOGCC issued a spacing exception under AA 44.18 to
authorize the drilling of well A-24-01 (injector).
• October 25: 1974, AOGCC issued AA 44.19 authorizing the commingling of
production from the BCD and EFG oil pools within the wellbore of MGS 17595 well
No. 7.
• April 9, 1975: AOGCC issued AA 44.20 authorizing the commingling of production
from the BCD and EFG oil pools within the wellbore of MGS 17595 No. 5.
• July 15, 1975: AOGCC issued AA 44.21 authorizing the re -drilling of well C -24 -14 -
RD to improve the drainage efficiency of the water flood project and increase total
oil recovery from the field.
• August 20, 1975: AOGCC issued a spacing exception under AA 44.22 to authorize
the drilling of the South MGS Unit No. 13.
• October 22, 1976: AOGCC issued a spacing exception under AA 44.23 to authorize
the re -drilling of MGS 17959 No. 9.
• November 10, 1976: AOGCC issued a spacing exception under AA 44.24 to
authorize the re -drilling of well A -34 -14 -RD.
• March 24, 1977: AOGCC issued a spacing exception under AA 44.25 to authorize
drilling of MGS 17595 No. 16.
• June 2, 1977: AOGCC issued a spacing exception under AA 44.26 to authorize re-
entry into the surface casing of a water source well for recompletion as an oil
producer.
• July 8, 1977: AOGCC issued a spacing exception under AA 44.27 to authorize the
drilling MGS 17595 No. 15.
• October 7, 1977: AOGCC issued a spacing exception under AA 44.28 to authorize
the drilling of well A-12-1.
• November 8, 1977: AOGCC issued a spacing exception under AA. 44.29 to
authorize the re -drilling of 17595 No. 8.
• December 13, 1977: AOGCC issued a spacing exception under AA 44.30 to
authorize the drilling of well C -44 -14 -RD.
• March 6, 1978: AOGCC issued a spacing exception under AA 44.31 to authorize the
re -drilling of we11C-42-23 RD.
Proposed Amendment, CO ,+4
Page 10 of 13
• June 19, 1978: AOGCC issued a spacing exception under AA 44.32 to authorize the
re -drilling of MGS 17595 No. 8.
• September 10, 1979: AOGCC issued a spacing exception under AA 44.33 to
authorize the re -drilling of well C-24-26.
• February 28, 1980: AOGC issued Conservation Order 163, thereby exempting the
well A-14-01 well from the requirements of Title 11, AAC 22W40 for the for the productive
life of the well, and allowing this well to serve as a gas supply
• September 1, 1981: AOGCC issued Conservation Order No. 176, thereby exempting
drilling rigs from specific requirements of 20 AAC 25.035(b)(1) which require the
equivalent of a six-inch line with at least two lines venting in different directions. A
system with a minimum four -inch diverter flowline to a degasser and vented by a
minimum four -inch line at the derrickman's position or the crown was approved.
• January 10, 1983: AOGCC issued a spacing exception under AA 44.34 to
authorizing the drilling of MGS 17595 No. 25.
• July 11, 1983: AOGCC issued a spacing exception under AA 44.35 authorizing the
drilling of well A -12A-1.
• July 20, 1983: AOGCC issued a spacing exception under AA 44.36 authorizing the
drilling of MGS 17595 No. 27.
• January 17, 1984: AOGCC issued a spacing exception under AA 44.37 authorizing
drilling of MGS 17595 No. 23.
• July 31, 1984: AOGCC issued a spacing exception under AA 44.38 authorizing the
re -drilling well 7595 No. 27 well.
October 19, 1984: AOGCC issued a spacing exception under AA 44.39 authorizing
the drilling of well A-34-11.
• October 30, 1987: AOGCC issued AA 44.40 authorizing commingling of production
from the BCD and oil pools in the wellbore of MGS 17595 No. 27.
• August 23, 1988: AOGCC issued a spacing exception under AA 44.41 authorizing
the re -drilling of well C-13-23.
• January 29, 1990: AOGCC issued a spacing exception under AA 44.42 authorizing
the drilling of well C-12-23.
• May 22, 1990: AOGCC issued a spacing exception under AA 44.43 authorizing
drilling of MGS 18756 No. C -22A-26.
Proposed Amendment, CO v4
Page 11 of 13
• August 1, 1990: AOGCC issued a spacing exception under AA 44.44 authorizing the
drilling of well C -13A-23.
• January 8, 1991: AOGCC issued a spacing exception under AA 44.45, authorizing
the drilling of MGS 18756 No. C-11-23.
• On March 29, 1991: AOGCC issued a spacing exception under AA 44.46 authorizing
the drilling of MGS 18756 No. C -21A-23.
• November 30, 1982: AOGCC issued AA 44.7 authorizing commingling of
production from the A and BCD Oil Pools in the MGS 17595 Well No. 27.
• June 15, 1993: AOGCC AA 44.8 Q spacing exception authorizing the drilling,
completion and production of the MGS No. A32 -11R.
• August 16, 1993, AOGCC issued a spacing exception under AA 44.9 authorizing the
drilling of MGS No. A -13A-01.
• August 18, 1993: AOGCC issued a spacing exception under AA 44.50 authorizing
the drilling of the MGS No. 29.
• November 22, 1993: AOGCC issued a spacing exception under AA 44.51
authorizing the drilling of MGS No. A33-1 ILS.
• February 23, 1994: AOGCC issued AA 44.52 authorizing the commingling of
production from the A and BCD pools in the MGS 17595 No. 28.
• March 14, 1994: AOGCC issued AA 44.53 authorizing the commingling of
production from the A, BCD and EFG pools in the MGS 17595 No. 28.
• March 17, 1994: AOGCC issued a spacing exception under AA 44.54 authorizing the
drilling of MGS No. A31-14LW.
• April 7, 1994: AOGCC issued a spacing exception under AA 44.55 authorizing the
drilling of the MGS Dillion No. 17.
• April 29, 1994: AOGCC issued Conservation Order No. 335 to waive the
requirements of 20 AAC 25.265(a)(2) for a period of six month to produce the MGS
19595 No. 28.
May 4, 1994: AOGCC issued a spacing exception under AA 44.56 authorizing the
drilling of MGS A-22-14LS.
Proposed Amendment, CO 44
Page 12 of 13
• On June 22, 1994: AOGCC issued a spacing exception under AA 44.57 authorizing
the drilling of the MGS A-41-11LN.
• August 4, 1994: AOGC issued a spacing exception under AA 44.58 authorizing the
drilling of well MGS A-13-01LN.
• September 14, 1994: AOGCC issued a spacing exception under AA 44.59
authorizing the drilling of well A-12-01 LN.
• September 14, 1994: AOGCC issued a spacing exception under AA 44.60 spacing
authorizing the drilling of well A14-01LN.
• April 27, 1995: AOGCC issued a spacing exception under AA 44.61 authorizing the
drilling of well A-43-1-1LW.
• June 19, 1995: AOGCC issued a spacing exception under AA 44.62 authorizing the
drilling of well A-34-11 LS.
• March 6, 1996: AOGCC issued Conservation Order No. 378, and associated
Erratum dated March 26, 1996, granted a spacing exception to 20 AAC
25.25.055(a)(4) to allow the drilling of the Baker No. 32 well.
• August 15, 1996: AOGCC issued AA 44.63 authorizing the commingling of
production from the A, BCD and EFG pools in well 17595 No.15RD.
• June 2, 1998: AOGCC issued Conservation Order No. 236 to repeal Rule 7 of CO
44, and replace it with the following language regarding surface casing construction:
Surface casing must be set and cemented to a depth of at least
1600 feet TVD if no intermediate casing string will be set. If
an intermediate casing string is set between 4000 feet TVD and
the shallowest abnormally pressed waterflood zone, surface
casing must be set and cemented to a depth of at least 1000 feet
TVD. In either case, sufficient cement must be used to
circulate to the surface.
• June 29, 2000: AOGCC issued a spacing exception under AA 44.64 authorizing the
drilling of well A34-11LS2.
• January 3, 2001: AOGCC issued a spacing exception under AA 44.65 authorizing
the side track drilling of well A2413 -0I LN.
• February 6, 2001: AOGCC issued a spacing exception under AA 44.66 authorizing
the side track drilling of well Al2-12LW.
Proposed Amendment, CO 44
Page 13 of 13
• June 21, 2001: AOGCC issued a spacing exemption under AA 44.67 (June 21, 2001)
spacing exception authorizing the side track drilling of well A34-14LW.
• September 5, 2001: AOGCC issued AA 44.68 authorizing the commingling of
production from the BCD and EFG pools in well Al 1-01.
• November 19, 2001: AOGCC issued a spacing exception under AA 44.69
authorizing the side track drilling of well A-34-14LW.
• March 5, 2002: AOGCC issued a spacing exception under AA 44.70 authorizing the
side track drilling of well C-32-23LW.
• April 12, 2002: AOGCC issued a spacing exception under AA 44.71 authorizing the
side track drilling of well C-24A-23LN.
• January 10, 2003: AOGCC issued a spacing exception under AA 44.72 authorizing
the side track drilling of well C-24A-23LN2.
• October 14, 2004: AOGCC issued AA 44.73 issued a spacing exception under AA
44.73 authorizing the drilling of well C -22A -26N.
