notice of intention to abandon / re-abandon well · of 300 psig overbalance for well control...

FOR DIVISION USE ONLY

Forms

Bond OGD114 OGD121

NATURAL RESOURCES AGENCY OF CALIFORNIA

DEPARTMENT OF CONSERVATION

DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES

NOTICE OF INTENTION TO ABANDON / RE-ABANDON WELL Detailed instructions can be found at: www.conservation.ca.gov/dog

In compliance with Section 3229, Division 3, Public Resources Code, notice is hereby given that it is our intention to abandon / re-abandon well Standard Sesnon 25 , API No. 037-00776 , (Check one)

Sec. 28 , T. 3N , R. 16W , S.B. B.&M., Aliso Canyon Field, Los Angeles County.

The complete casing record of the well (present hole), including plugs and perforations, is as follows: (Attach wellbore schematics diagram also.) See attached wellbore schematic

The total depth is: 8749 feet. The effective depth is: 7580 feet.

Present completion zone(s): N/A plugged back . Present zone pressure: N/A psi. (Name)

Oil or gas shows: See attached program feet. Depth to base of fresh water: 800 feet.

(Name and depth)

Top of uppermost hydrocarbon zone (which may be behind unperforated casing): Pliocene Gas Sand: 2,703' feet.

(Depth of interval)

Is this a critical well as defined in the California Code of Regulations, Title 14, Section 1720(a) (see next page)? Yes No

The proposed work is as follows: (A complete program is preferred and may be attached.)

See attached program

The Division must be notified immediately of changes to the proposed operations. Failure to provide a true and accurate representation of the well and proposed operations may cause rescission of the permit. Name of Operator

Southern California Gas Company Address

P. O. Box 2300 City/State

Chatsworth Zip Code

91313-2300 Name of Person Filing Notice

Thomas McMahon Telephone Number:

562.806.4429 Signature

Thomas McMahon Date

3/30/2018

Individual to contact for technical questions: Telephone Number: E-Mail Address:

Ella Lein 818. 700. 3890 [email protected]

This notice must be filed, and approval given, before plugging and abandonment operations begin. If operations have not commenced within one year of the Division’s receipt of the notice, this notice will be considered cancelled.

OG108 (1/09)

CRITICAL WELL DEFINITION

As defined in the California Code of Regulations, Title 14, Section 1720 (a), “Critical well” means a well within:

(1) 300 feet of the following: (A) Any building intended for human occupancy that is not necessary to the operation of the well; or (B) Any airport runway.

(2) 100 feet of the following: (A) Any dedicated public street, highway or the nearest rail of an operating railway that is in general use; (B) Any navigable body of water or watercourse perennially covered by water; (C) Any public recreational facility such as a golf course, amusement park, picnic ground, campground or any

other area of periodic high-density population; or (D) Any officially recognized wildlife preserve.

This form may be printed from the DOGGR website at www.conservation.ca.gov/dog/

SS-25 Phase 3A Contingency Part 2 Summary Steps Rev 5 March 30 2018 el v01 1 of 15

Southern California Gas Company Standard Sesnon 25

Blade’s Phase 3A Contingency Part 2 and Well Abandonment Operations Procedure

Aliso Canyon

March 30, 2018 Well Data: API #: 037-00776 KB to GL: 6’ above GL at 2927’ MD: 8,749’ TVD: 8,733’ PBMD: 7,555’ Nature of Plug Back: CIBP and Cement Surface Location: Sec. 28, T 3N, R 16W Estimated Bottom-hole Static Temp: 150 F Estimated Formation Fracture Gradient: 0.556 psi/ft

Casing and Tubing Data:

Surface Casing: 11-3/4” 42 ppf H-40 Cemented at 990’

Production Casing: 7” 0’ – 939’ 29 ppf N-80 (tieback casing) 939’ – 2,398’ 23 ppf J-55 2,398’ – 6,308’ 23 ppf N-80 6,308’ – 8,282’ 26 ppf N-80 8,282’ – 8,585’ 29 ppf N-80

Cemented with 600 sacks, ETOC at 7,000’, WSO perforations at 8,474’ and 8,583’, TOC in 7” casing at 7,590’

Production Liner: 5-1/2” 20 ppf J-55; 8,559’ – 8,749’ – Plugged Back (Intercepted the well at 8,612’ via the Porter 39A relief well)

Production Tubing: 2-7/8” 6.5 ppf J-55; 7,555’ – 8,496’, Tubing CIBP at 7,572’, Cement from 7,580’ – 8,496’

Kill String:

Kill string 3-1/2” 9.3 ppf N-80 at approximately 7,524’

Wellhead:

13-5/8” 5M Casing Head, 11” 5M Tubing Head (Diverter with 6” diverter line and 13-5/8” 5M BOP on the tubing head)

Geologic Markers:

a. BFW: 800’ (+/-) MD b. Pliocene Gas Sand: 2,703’ MD c. A1 (Aliso Sand): 4,650’ MD d. A36 (Aliso Sand): 5,527’ MD e. Upper Porter: 5,820’ MD f. Lower Porter: 6,245’ MD g. Upper Del Aliso 1: 6,566’ MD h. Upper Del Aliso 2: 6,871’ MD


i. Middle Del Aliso: 7,350’ MD j. Lower Del Aliso: 7,588’ MD k. MP: 8,182’ MD l. S1: 8,395’ MD m. S2: 8,434’ MD n. S4: 8,492’ MD o. S6: 8,509’ MD p. S8: 8,600’ MD q. S10: 8,628’ MD r. S12: 8,702’ MD s. S14: 8,748’ MD Perforations:

Plugged back with cement Slotted liner, 8,592’ – 8,748’ (120 Mesh x 2” slots 6” centers) Perforated with 4 jspf at 8,510 – 8,538’, 8,542’ – 8,559’

Current Status: Idle, rig on standby. The work is suspended pending Supplemental NOI approval.

Permit Status: Pending

Work performed to date: As per the Supplementary Permit issued October 2, 2017, including recovery of the parted 7” production casing to 939’, running a suite of logs to evaluate the 11-3/4” casing, running 7” tieback casing from 939’ to surface and running a suite of logs to evaluate the 7” casing.

Table of Critical Zones

Critical Zones Depth (ft) Annulus Est. Bot. of Annulus

Squeeze (ft) Est. Top of Annulus

Squeeze (ft)

Casing Plug Tag Depth or

Higher (ft)

Base Fresh Water * (See SCG attachment for BFW depth justification)

800 Squeeze 800 650 700

Pliocene Gas Sand 2,703 Squeeze 2,703 2,203 2,603

A1 (Top Aliso Sand) 4,650 Squeeze 4,654 4,504 4,554

A36 (Deepest Aliso Sand) 5,527 Squeeze 5,527 5,377 5,427

Upper Porter 5,820 Squeeze 5,820 5,670 5,720

Lower Porter 6,245 Squeeze 6,245 6,095 6,145

Upper Del Aliso 1 6,566 Squeeze 6,566 6,416 6,466

Middle Del Aliso 7,350 Cemented

Lower Del Aliso 7,588 Cemented

Miocene/Pliocene Unconf. 8,182 Cemented

S1 Sesnon 8,395 Cemented

Project Notes:

1. BOPE requirements in Gas Company Standard 224.05 shall be fully implemented at all

times.


2. The storage reservoir pressures shall be monitored during the workover with a minimum

of 300 psig overbalance for well control fluids.

3. Prepare the location by removing all relevant landscaping/lighting fixtures as well as

surface piping and electrical components as required.

4. DOGGR permit must be posted on site. Notify DOGGR as required for BOPE testing

prior to commencing downhole operations as stated on permit. DOGGR Ventura District

office (805)-654-4761. If a permit has not been issued, contact DOGGR prior to rigging

up on the well for verbal approval to rig up.

SS-25 Phase 3A Contingency Part 2 Summary Steps

1. Ensign Rig 540 is rigged up over the well.

2. A diverter with a 6” diverter line and Class III 5M BOPE is currently nippled up on the 11”

5M tubing head. Pressure test the BOPE and function test the diverter. Function test the

diverter weekly and record the function test on the daily report.

a. All tests are to be charted and witnessed by a DOGGR representative.

b. Perform a 300 psig low pressure test on the annular preventer, blind rams and pipe

rams for 20 minutes. Pressure test all lines and connections to 300 psig.

c. Pressure test the Class III 5M annular preventer to 3,500 psig for 20 minutes. Test

the blind and pipe rams to 5,000 psig for 20 minutes. Pressure test all lines and

connections to 5,000 psig.

d. Remove test plug from the tubing hanger.

3. POH with the tubing workstring.

4. RIH with noise and temperature logs to 1500’.

5. Pump fluid down the 11-3/4” x 7” annulus and monitor noise and temperature logs to

determine a fluid flow path near the 11-3/4” casing shoe if one exists.

6. Run a gyro survey to 1,500’ in the 7” casing at 10’ intervals.

7. RIH with a 5” OD x 4” ID wash shoe and 5” washpipe to clean out between the tubing

and casing from 7555’ and 7590’. Make a diligent effort to clean out to the TOC in the

annulus at approximately 7590’.

a. Contact DOGGR to witness tagging the 7” x 2-7/8” annulus plug.

b. If unable to make progress, stop and contact DOGGR for authorization to proceed

with the work.

8. RIH with a joint of 5” washpipe on the workstring to get over the tubing stub and balance

a 200’ cement plug (7.7 bbl) in the 7” x 2-7/8” tubing annulus and 7” casing.

a. Plug #1, 7590’ to 7390’


b. Type III Cement Intermediate Blend

Intermediate Blend Composition Properties

Type III Cement Yield 1.75 cu ft/sack35% SSA‐1 Silica Flour Water 7.92 gal/sack0.5% Halad 322 Fluid Loss Control Additive Density 14.8 ppg0.3% CFR‐3 Friction Reducer Compressive Strength 2045 psi in 8 hours Permeability 0.0018 mD

9. Tag top of plug. Tag must be witnessed by DOGGR.

10. RU eline. RIH and take 7” casing annulus fluid samples and annulus pressures using the

Schlumberger Cased Hole Dynamics Tester (CHDT) at the proposed depths shown in

the table below. Correlate to the Schlumberger Isolation Scanner Cement Evaluation log

run on December 4, 2017. RD eline.

a. The CHDT holes will be plugged and pressure tested to 1000 psi using the CHDT

tool after the samples are taken.

b. If the plug fails to pressure test, the situation will be evaluated. If the leak is deemed

a safety or operational risk, the hole will be squeeze cemented and pressure tested

to 1000 psi. Notify DOGGR if a pressure test fails.

c. Compile the pressure charts, including the pressure tests for submission to DOGGR.

Count CHDT Depths

(ft)

Count CHDT Depths

(ft)

Count CHDT Depths

(ft)

1 975 10 1,218 19 3,659

2 994 11 1,552 20 4,121

3 1,006 12 1,664 21 4,186

4 1,046 13 1,680 22 4,285

5 1,054 14 1,918 23 4,810

6 1,084 15 2,031 24 5,980

7 1,100 16 2,295 25 6,240

8 1,116 17 2,560 26 6,716

9 1,168 18 2,706 ‐ ‐

11. RU eline. RIH and take 7” casing samples using the Schlumberger Mechanical Sidewall

Coring Tool (MSCT) in the following order at the following depths. Correlate to the

Schlumberger Isolation Scanner Cement Evaluation log run on December 4, 2017. RD

eline.

a. MSCT 7337’

b. MSCT 7126’

12. RIH with the workstring to the TOC (approximately 7390’) and balance a 500’ cement

plug (19.1 bbl Intermediate Blend) in the 7” casing.


a. Plug #2, 7390’ to 6890’




eline.

a. MSCT 6721’

14. RIH with the workstring to the TOC, approximately 6890’ and balance a 274’ cement


a. Plug #3, 6890’ to 6616’

15. Tag the TOC at 6621’ or above. Contact DOGGR to witness the tag.

16. Confirm the casing integrity.

a. Pressure test the casing to 500 psi for 30 minutes. Record the test. Notify DOGGR to

witness the pressure test.

17. RU eline. RIH and perforate to squeeze the UDA-1 6566’ – 6576’ using a 10’ 4 spf 90°

phase gun. RD eline.

18. Criteria for Injection Rate.

a. Establish an injection rate based on a surface pressure not to exceed a 0.556 psi/ft

gradient at the perforations.

b. If an injection rate of >3 bpm is established, pump a mud push spacer ahead of the

cement and squeeze the zone. Contact DOGGR to witness squeeze jobs.

c. If the injection rate is <3 bpm, contact DOGGR and discuss the options prior to

proceeding. Options include re-perforate, balance a cement plug and apply squeeze

pressure, etc.

19. Establish the injection rate and maximum surface pressure according to the Criteria for

Injection Rate. Lay a 19.1 bbl (499 linear feet in the casing Intermediate Blend) cement

plug from the TOC, approximately 6616’ to 6117’. PU above the cement. Attempt to

squeeze 150 linear feet of cement into the annulus.

a. Contact DOGGR to witness the squeeze job.

b. Squeeze UDA-1, 6566’ to 6416’, 150’ length. Volume 9.3 bbl (100’ in the annulus +

50% excess)

c. Estimated cement plug inside casing 6616’ – 6360’.



Coring Tool (MSCT) in the following order at the following depths. RD eline.


a. MSCT 6260’

22. RU eline. RIH and perforate to squeeze the LP 6245’ – 6255’ using a 10’ 4 spf 90°






a. Contact DOGGR to witness the squeeze job.

b. Squeeze LP, 6245’ to 6095’, 150’ length. Volume 9.3 bbl (100’ in the annulus + 50%

excess)






eline.

a. MSCT 6020’



a. Plug #4, 6095’ to 5870’


28. RU eline. RIH and perforate to squeeze the UP 5820’ – 5830’ using a 10’ 4 spf 90°






a. Contact DOGGR to witness squeeze jobs.

b. Squeeze UP, 5820’ to 5670’, 150’ length. Volume 9.3 bbl (100’ in the annulus + 50%

excess)



31. RU eline. RIH and perforate to squeeze the A-36 5527’ – 5537’ using a 10’ 4 spf 90°








b. Squeeze A-36, 5527’ to 5377’, 150’ length. Volume 9.3 bbl (100’ in the annulus +

50% excess)





a. Plug #5, 5377’ to 5077’



a. MSCT 4791’



a. Plug #6, 5077’ to 4704’


38. RU eline. RIH and perforate to squeeze the A-1 4654’ – 4664’ using a 10’ 4 spf 90°







b. Squeeze A-1, 4654’ to 4504’, 150’ length. Volume 9.3 bbl (100’ in the annulus + 50%

excess)



41. Confirm wellbore integrity.

a. Pressure test the casing to 500 psi for 30 minutes. Record the test and notify

DOGGR to witness the test.

b. Check for gas using a gas monitor after the well has been shut in overnight.


42. RIH and set a cement retainer or CIBP above the TOC.



a. MSCT 4110’

b. MSCT 3666’



a. Plug #7, 4500’ to 4000’



a. Plug #8, 4000’ to 3500’


47. RU eline. RIH and perforate to squeeze the 10-5/8” x 7” annulus 3450’ – 3460’ using a

10’ 4 spf 90° phase gun. RD eline.





a. Squeeze Annulus, 3450’ to 3250’, 200’ length. Volume 12.4 bbl (133’ in the annulus

+ 50% excess)

b. Estimated cement plug inside casing 3500’ – 3300’.



a. Plug #9, 3300’ to 2800’



a. MSCT 2713’

51. RU eline. RIH and perforate to squeeze the PGS 2703’ – 2713’ using a 10’ 4 spf 90°





squeeze 500 linear feet of cement into the annulus. Leave the TOC in the casing at

approximately 2690’.



b. Squeeze PGS, 2703’ to 2203’, 500’ length. Volume 31.0 bbl (333’ in the annulus +

50% excess)

c. Estimated cement plug in the casing 2800’ – 2690’.

d. If the PGS was squeezed, drill out to 2690’ in preparation for the CBL.

53. If the PGS was squeezed, WOC for at least 48 hours. Run a CBL while holding 500 psi

on the casing, from 2690’ to 2000’ to confirm cement integrity behind the casing. Consult

and review the CBL with DOGGR prior to proceeding with the next step.



a. MSCT 2553’

b. MSCT 2372’

c. MSCT 2289’

d. MSCT 2037’

e. MSCT 1925’



a. Contact DOGGR to witness the cement plug placement.

b. Plug #10, 2690’ to 2190’



a. Plug #11, 2190’ to 1690’




a. MSCT 1625’

b. MSCT 1564’

c. MSCT 1140’

d. MSCT 1092’

e. MSCT 1035’


plug (16.5 bbl Shallow Blend) in the 7” casing.

a. Plug #12, 1690’ to 1270’

b. Type III Cement Shallow Blend


Shallow Blend Composition Properties

Type III Cement Yield 1.36 cu ft/sack0.5% Halad 322 Fluid Loss Control Additive Water 6.46 gal/sack0.4% Halad 344 Dispersant Density 14.8 ppg2.0% CaCl2 Compressive Strength 1062 psi in 8 hours Permeability 0.00025 mD


plug (9.1 bbl Shallow Blend) in the 7” casing. Contact DOGGR to witness the cement

plug placement.

a. Plug #13, 1270’ to 1040’

61. Tag the TOC at approximately 1040’. Contact DOGGR to witness the tag.

62. Dress the TOC to 1040’ if required.

63. RIH and cut the 7” casing at a target depth of 1024’ and no deeper than 1027’. POH and

LD cutter. Nipple down the BOPE and diverter. ND the tubing head. Pick up the casing

with a spear. Remove the casing slips. Set the casing down and release the spear.

64. NU BOPE and the diverter on the 13-5/8” 5M casing head. Pressure test the BOPE

breaks and function test the diverter. Notify DOGGR to inspect the BOPE.

65. Pick up the casing with a spear. POH and lay down the 7” casing. The 7” casing includes

the temporary tieback casing and approximately 85’ of original 7” casing. Handle and lay

down the original casing according to the Blade Tubular Handling Protocol document.

66. RU eline. RIH with open hole caliper and log from the 11-3/4” shoe to the 7” casing stub.

Circulate and condition the fluid if required. RIH with a FMI tool and log from the 11-3/4”

shoe to the 7” casing stub.

67. RIH with a 11-3/4” casing scraper. Prepare the 11-3/4” casing for logs. POH with casing

scraper.

68. Run 11-3/4” casing logs. Refer to the Proposed 11-3/4” Logs.

Proposed 11-3/4” Logs

Log Description Purpose Provider Tool Name Abbreviation

Noise – Temperature Evaluate possible flow paths near the 11‐3/4” casing shoe

TBD Noise

Temperature

Open hole logs Evaluate open hole ID and borehole image

SLB Caliper

Formation Micro‐Imager

Caliper FMI

Junk Basket, Gauge Ring, Gamma Ray, Casing Collar Locator

Determine if there are any ID restrictions in the 11‐3/4” casing

Baker ‐‐ JB‐

GR/GR/CCL

Mechanical Caliper 11‐3/4" ID measurements, deformation, corrosion indications

Baker ICAL Multi‐

Finger Caliper ICAL


Log Description Purpose Provider Tool Name Abbreviation

Annulus Evaluation Evaluate Cement Quality Baker Integrity

Explorer Cement Evaluation

IntEX CBL

Annulus evaluation 11‐3/4" Casing condition

Solid‐liquid‐gas map of annulus material, hydraulic communication map, acoustic impedance, flexural attenuation, rugosity image, casing thickness image, internal radius image

SLB

Isolation Scanner

Ultrasonic

Casing Imager

IBC

UCI

Formation evaluation Lithology type, water, hydrocarbon identification

SLB Pulsed Neutron

Extreme LithoScanner

PULSAR NEXT

Active corrosion detection

Identify anodic/cathodic cells indicating active corrosion

SLB Corrosion and Protection

Evaluation Tool CPET

Downhole camera Visual inspection of the 11‐3/4" casing ID for defects and anomalies

EV EV Downhole Video Camera

MK2

69. Evaluate the log data to determine if additional squeeze cement jobs are necessary to

isolate the fresh water. Contact DOGGR to review and approve any proposed changes

based on log evaluation.

70. RIH and take 11-3/4” casing annulus fluid samples using the Schlumberger Cased Hole

Dynamics Tester (CHDT) at various depths (depths to be determined by log evaluation).

71. RIH and take 11-3/4” casing samples using the Schlumberger Mechanical Sidewall

Coring Tool (MSCT) at various depths (depths to be determined by log evaluation).

72. Run a gyro survey in the 11-3/4” casing at 10’ intervals.

73. Displace the fluid to clear fluid for a video camera run.

74. Run a video camera in the 11-3/4” casing.

75. RIH and displace the clear fluid with 9 ppg fluid.

76. Run 7” casing tieback and connect to the casing stub at approximately 1024’.

77. Cut the casing between 985’ and 940’. The target cut depth is 980’. Plugs assume a cut

depth at 980’.

78. POH and lay down the casing.

79. RIH with the workstring to the TOC in the 7” casing (approximately 1040’) and balance a

34.6 bbl (290 linear feet of Shallow Blend) cement plug inside the 11-3/4” casing to

isolate the 11-3/4” shoe.

a. Estimated cement plug inside the 7” casing 1040’ to 980’ (2.4 bbl)


b. Estimated cement in the 16” x 11-3/4” annulus 990’ to 840’ (17.2 bbl, 100’ in the

annulus + 50% excess)

c. Estimated cement in the 11-3/4” x 7” annulus 990’ to 980’ (0.7 bbl)

d. Estimated cement in the 11-3/4” casing 980’ to 860’ (14.3 bbl)

80. Tag top of plug 100’ above the casing stub or higher at approximately 880’. Tag must be

witnessed by DOGGR.

81. RIH and set an 11-3/4” cement retainer at the top of cement, approximately 860’.

82. RIH with the workstring to the cement retainer (approximately 860’) and balance a 6.0

bbl (50 linear feet of Shallow Blend) cement plug in the 11-3/4” casing.

a. Plug #14, 860’ to 810’

83. Evaluate the 11-3/4” cement at the BFW at approximately 800’. If no cement, RIH and

perforate to squeeze the BFW 800’ – 810’ using a 10’ 4 spf 90° phase gun. RD eline.

84. RIH and set a packer at approximately 760’ and establish the injection rate and

maximum surface pressure according to the Criteria for Injection Rate. Mix and pump

20.8 bbl of Shallow Blend cement. Squeeze 17.2 bbl from 800’ to 650’. Attempt to


a. Squeeze BFW, 800’ to 650’, 150’ length in the 16” x 11-3/4” annulus. Volume 17.2

bbl (100’ in the annulus + 50% excess)

b. Estimated cement plug inside the casing 810’ to 780’ (3.6 bbl).

85. RIH with the workstring to the TOC (approximately 780’) and balance a 23.9 bbl (200

linear feet of Shallow Blend) cement plug in the 11-3/4” casing.

a. Plug #15, 780’ to 580’


87. Run and set a cement retainer at the TOC at approximately 580’.

88. RIH with the workstring to the TOC (approximately 580’) and balance a 200’ cement plug

(23.9 bbl Shallow Blend) in the 11-3/4” casing.

a. Plug #16, 580’ to 380’



a. Plug #17, 360’ to 180’



a. Plug #18, 180’ to 15’

91. ND BOPE.


92. Cut the 11-3/4” casing below the casing head and release the casing head to Blade for

RCA evaluation. Weld on a riser to extend the casing if necessary to meet the

requirement of the top of casing cut off 5’ to 10’ below ground level.

93. Cut the casing 5’ to 10’ below ground level. Contact DOGGR to witness.

94. Perform bubble test. Contact DOGGR to witness.

95. Weld on well identification plate.

96. Release rig and move off.


Spud Date:Conversion Date:TD ‐ MD:TD ‐ TVD:API Number:

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

MD Age Hole

990 ft 11‐3/4" 42ppf H40 STC

7.0" Speed Tite8585 ft_

GLE = 2,927 ftRKB = 6.35 ft

Packer = 8486 ft

TOC = ±7000'

1‐Oct‐19536‐June‐19738,749 ft8,733 ft03700776

Southern California Gas Co.Standard Sesnon #25

Current Status

8748 ft_

Aliso Canyon RCA Project Rev: 18 Feb 2018

7.0" Casing29 ppf N80 Surf ‐ 939’23 ppf J55 939 ‐ 2398'23 ppf N80 2398 – 6308 ft26 ppf N80 6308 – 8282 ft

29 ppf N80 8282 – 8585 ft

TD = 8,749 ft MD8,733 ft TVD

5‐1/2" TOL = 8559'

Form. Zone.

16”

10‐5/8”

6.0"5‐1/2" 20.0 ppf J55 FJ (slotted ‐ 120 mesh)

TOC A Annulus 7590'TOC Tubing 7580'

Upper Plio

cene

Lower Plio

cene

Middle M

iocene

Old Santa Susana Fault _1635

Modelo

Topanga

_4200Yng Santa Susana Fault

Pico

_8182Mio‐Plio Unconformity

Pico

Modelo

Middle M

iocene

_1912

_2703

_3412

Pico‐1

Pico‐2

Pico‐3

Pico‐4_3992

_4650Pico

Aliso

_5820

_6566

Porter

_7350

Upper Del Aliso

Mid DA _7588

Lower DA

_8395Cap Rock

Sesnon

20" Conductor

CIBP 7572’Tubing Cut 7555’

7” Casing Patch7” Tieback Casing939’ to Surface

9 ppg Flowzan Fluid to Surface

Tubing Hanger Installed

3‐1/2” Workstring9.3 ppf EUE

EOT approx. 7524’ (1 joint above the tubing stub at 7555’)

Holes in 11‐3/4” Casing144 – 300’

Perforations8510 – 8538’8542 – 8559’


Spud Date:Conversion Date:TD ‐ MD:TD ‐ TVD:API Number:

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

MD Age Hole

990 ft

11‐3/4" 42ppf H40 STC

7.0" Speed Tite8585 ft_

GLE = 2,927 ftRKB = 6.35 ft

Packer = 8486 ft

1‐Oct‐19536‐June‐19738,749 ft8,733 ft03700776

Southern California Gas Co.Standard Sesnon #25

Proposed Abandonment

8748 ft_

Aliso Canyon RCA Project Rev: 21 Mar 2018

7.0" Casing29 ppf N80 Surf – 1040 ft23 ppf J55 1040 – 2398 ft23 ppf N80 2398 – 6308 ft26 ppf N80 6308 – 8282 ft

29 ppf N80 8282 – 8585 ft

TD = 8,749 ft MD8,733 ft TVD

5‐1/2" TOL = 8559'

Form. Zone.

16”

10‐5/8”

6.0"5‐1/2" 20.0 ppf J55 FJ (slotted ‐ 120 mesh)

TOC A Annulus 7590'TOC Tubing 7580'

Upper Plio

cene

Lower Plio

cene

Middle M

iocene

Old Santa Susana Fault _1635

Modelo

Topanga

_4200Yng Santa Susana Fault

Pico

_8182Mio‐Plio Unconformity

Pico

Modelo

Middle M

iocene

_1912

_2703

_3450

Pico‐1

Pico‐2

Pico‐3

Pico‐4_3992

_4650Pico

Aliso

_5820

_6566

Porter

_7350

Upper Del Aliso

Mid DA _7588

Lower DA

_8395Cap Rock

Sesnon

20" Conductor

CIBP 7572’Tubing Cut 7555’

580’ Cement Retainer800’ BFW860’ Cement Retainer7” Tieback Casing ±1024’ to ±980’

2703' PGS

3450’ Annulus Sqz

4650’ A1

5527’ A36

5820’ UP

6245’ LP

6566’ UDA 1

Perforations8510 – 8538’8542 – 8559’

ETOC 650’Sqz Holes 800’

ETOC 2203‘Sqz Holes 2703’







TOC ±7000’

Aliso Canyon Base of Fresh Water, 800’MD

Base of Fresh Water (BFW) for Aliso Canyon is noted in California Oil and Gas Fields Vol 2, a publication

by the California Division of Oil and Gas, as 100‐800’ (Attachment 1). BFW is identified as 3,000ppm

Total Dissolved Solids (TDS). It is important to note the Summary of Operations California Oil Fields 29th

Annual Report of the State Oil and Gas Supervisor states there are no subsurface waters suitable for

domestic or irrigation purposes to protect at Aliso Canyon. This established the original 500’ surface

casing depth (Attachment 2).

800’+/‐ was selected as a conservative BFW for the majority of the field1 instead of using 100’ or even no

BFW. This depth was also confirmed by DOGGR agents at the field. Petrophysical analysis of BFW at the

Aliso Canyon field is complicated by many factors. The west field where SS‐25 is located contains a

basalt layer within the Topanga formation (Figure 1) that has a strong electric log signature (Figure 2),

highlighting the abrupt transition in lithology. At SS‐25 this basalt layer is present from 845’MD to

969’MD (Figure 3). Another complicating factor for petrophysical analysis is the preference to drill with

oil‐based mud due to difficult shallow drilling conditions. The oil emulsion mud used to drill the shallow

section of SS‐25 had an Rm of about 2.0 OHMM at reservoir temperature which interferes with

petrophysical determination of BFW. SS‐25 also has only SP and Resistivity logs for petrophysical

analysis. SP method of Rw (and salinity) requires a known 100% wet, clean sand. The shallow geology

of Aliso Canyon is known to have tar staining and interbedded shales (Figure 3) from mudlogs; these

conditions will also underestimate calculated salinities.

Blade Energy Partners calculated formation water salinity of neighboring wells drilled in the early 1970s:

SS‐25A (surface casing set at 806’MD) and SS‐25B (surface casing set at 900’MD). The resulting

calculations (Figure 4) show formation salinity of 6,000ppm at approximately 900’MD (no logs were

acquired in the surface casing section) thereby indicating 800’MD BFW to be a conservative depth for

the three wells at the SS‐25 well site.

1 Note the western part of the field has Modelo/Topanga faulted out and a petrophysically established BFW at the PEupth marker.

F

Figure 1: Full field cross section showing basalt isolated to the west field.

Figure 2: SS‐25 shallow e‐log from 1953 showing strong resistivity response of Topanga basalt

Figure 3: Partial SS‐25 Stratigraphic Column

Figure 4: SS‐25A and SS‐25B Salinity calculation from SP

notice of intention to abandon / re-abandon well · of 300 psig overbalance for well control...

Documents