Solutions for Today | Options for Tomorrow
Key Points from the 2016 Workshop of Well Integrity for Natural Gas Storage –Lessons from Aliso Canyon
GHGT-13, November 15, 2016
Grant S. Bromhala, Barry Freifeldb
aNational Energy Technology LaboratorybLawrence Berkeley National Laboratory
R 324.805 Operational testing requirements.
Rule 805. (1) A permittee of an injection well, except for an injection well utilized for gas storage, shall provide for a pressure test that meets the requirement of subrule (2) of this rule, by a qualified person, to determine the mechanical integrity of the tubing, casing, and packer. (2) The annulus between the innermost casing and the tubing above the packer shall be tested at least once each 5 years at a pressure of not less than 300 psig.
R 324.801 Construction and operation of injection wells.
Rule 801. (1) A permittee of a well shall ensure that the injection of fluid into a well is through adequate tubing and packer. During injection operations, the tubing to casing annulus shall be filled with a noncorrosive liquid. Injection wells utilized for gas storage are exempt from this subrule.
R 324.803 Testing before operation of injection wells.
Rule 803. (1) Before injecting fluid into a newly drilled injection well, or into a previously existing well that has been newly converted to an injection well, a permittee of a well shall provide for a test of the annulus between the innermost casing and the tubing above the packer. The test shall be conducted by a qualified person and the test shall be at a pressure of not less than 300 psig. The difference in pressure between the testing pressure and the tubing pressure shall be not less than 100 psig at the time of the test. A satisfactory test shall have a bleed off of not more than 5% over a period of 30 minutes.
(2) Before the test, a permittee of a well shall notify the supervisor or authorized representative of the supervisor of the date and time of the test. A certified copy of the test procedure and results shall be filed with the supervisor by the qualified person making the test. The supervisor or authorized representative of the supervisor, after evaluating the test results and determining the mechanical integrity of the packer and casing string immediately outside the tubing, may approve injection operations to begin.
(3) Injection wells utilized for gas storage are exempt from this rule.
Michigan DEQ – Oil & Gas Regulation
• Background on Aliso Canyon incident
• Task Force and related gas storage issues
• Gas storage monitoring
• Comparison of CCS and UGS
Presentation Outline
• Leak began at Aliso Canyon October 23, 2015• Eight top kill attempts were made between Oct. 24 and Dec. 22
• Increasingly aggressive attempts• Successive top kills caused erosion and expansion of the vent
• Ground prep for relief well began Nov. 13 and drilling started on Dec. 4• ~90,000 tonnes of gas leaked in four months
• On February 17, 2016, leak was permanently plugged using relief well
• DOGGR (State of CA) consulted LBNL, LLNL, SNL in December 2015
• DOE-led Task Force initiated in April 2016 (PIPES Act)• Well Integrity (FE), Reliability (OE), Health and Environment (EPA & HHS)
• Well Integrity lab team formed in April 2016 with addition of NETL• Initiate Well Integrity Workshop• Analyze Aliso incident• Evaluate potential for broader well integrity risks• Provide recommendations
Background on Aliso and Task Force
4
SS-25 well schematic
5
2-7/8 in production tubing
shoe @ 8585 ft
7 in casing
11-3/4 in casing
Camco 2-1/2 in SSSV 8451 ft**Otis “XN” 8472 ft
8510 ft
8486 ft
8391 ft8381 ft
990 ft
440 ft 134 m
302 m
2558 m
2617 m
2587 m
0 ft 0 m
Water Shut Off (WSO)8475 ft
No slots are on the gas-lift mandrel (MMG) 8397 ft
EZSV Plug 8393 ft
Tubing tail 8496 ft
top of liner 8559 ft
TD 8749 ft 2667 m
Water Shut Off (WSO)8583 ft
2594 m
5.5 in liner, 120 mesh, slotted 8592-8748 ft
Perfs 8510-8559 ft
6500 ft cement1981 m
Presumptive hole in casing
Formal root cause analysis initiated by CA Public Utilities Commission
• One of 114 gas storage wells• Conversion to gas storage 1973• Last casing inspection 1979• T and noise logs back to 1991• Well had tubing and packer
• injection and production through both tubing and casing for better throughput
• Complicated flow path due to slots in tubing from removal of subsurface safety valve
• All AC wells have been or are being surveyed for noise and temperature in the past year-during the leak time frame and since the leak incident
• In the 5 years prior (2015–2010), most wells were surveyed annually for temperature
• In the next 5 prior years (2010–2006), most wells were surveyed every other year
• For the time frame 1990–2005, most wells were surveyed at time intervals greater than every other year
• For the time frame from 1990 to the conversion date (1970s), surveying was sporadic
• There are infrequent additional geophysical log data for the storage wells that could possibly have been used to assess well integrity, but nothing recent nor systematic.
Well Inspections at Aliso
6
Info on activities posted online by State of CA at: http://www.conservation.ca.gov/dog/Pages/AlisoCanyon.aspx
• South Coast Air Quality Management Board (SCAQMB) and California Air Resources Board (CARB) conducted emergency air monitoring
• Purposes:• Assess potential exposure to various pollutants• Evaluate extent of emissions in surrounding area• Provide info to Porter Ranch community members
• Collection methods:• Instantaneous grab samples and 12- and 24-hour cannisters• Fixed contiuous monitoring sites• Mobile methane monitoring
Atmospheric monitoring at Aliso
• Additional aerial and satellite images showed distributions of methane in atmosphere
IR Image – EDF.
EO-1 satellite photo
What about other UGS sites?
8
• ~415 storage facilities, ~17,500 wells• 2 other major incidents in past 15 years:
– Yaggy, Hutchinson, KS, 2001– Moss Bluff, Liberty County, TX, 2004
• Failure rates estimated only for major incidents, and not complete
• Records for most “minor” failures do not appear to be collected or maintained
Yaggy, 2001
Salt Caverns Europe
Salt Caverns Worldwide
Oil/Gas Fields Europe
Oil/Gas Fields
WorldwideNumber of well failures
1 10 1 5
Operating experience (well years)
Upper
Lower
65,000
24,000
83,000
59,000
153,000
81,000
860,000
603,000
Failure rate (per well year)
Lower
Upper
1.5 x 10‐5
1.2 x 10‐41.2 x 10‐4
1.7 x 10‐46.5 x 10‐6
1.2 x 10‐55.8 x 10‐6
8.3 x 10‐6
Health and Safety Laboratory, 2008
• Many wells converted from oil & gas to gas storage operations (e.g., Aliso)• ~15% of wells older than 1921 (zonal cement isolation)• ~80% of wells older that 1980• Not uncommon to see gas produced through casing without tubing or
through both casing and tubing• Many O&G non-storage wells within UGS field area• Maintenance practices vary significantly from site to site
Many U.S. UGS wells have been around for a long time
9
• Divergent opinions and deep dive into several issues• Federal vs state responsibility & Interstate vs intrastate• Regulations (prescriptive vs “risk-based”) • Well construction (barriers, ISO/TS 16530) • API 1170 & 1171• Transition period (17,500 existing wells)
• Key takeaways –• State of California released proposed regulations (CA has all intrastate storage)• DOC/DOGGR Order 1109• Formal Risk Management needed• Downhole safety valves need more attention (not enough hard data)• PHMSA will regulate and what rights states will have is uncertain
Well integrity workshop
10
www.eesa.gov/wellintegrity
Operators 65
Academic/research 51
Regulators 34
Services/Consult 39
• Operators should phase out wells with single-point-of-failure designs.
• Operators should undertake rigorous well evaluation programs.
• Well testing must be a top priority for lowering well integrity risk.
• Well integrity testing should use a tiered approach.
• Well integrity testing should use multiple methods.
• Storage operators should deploy continuous monitoring systems.
Task Force Recommendations
11
Topic 1: Well Integrity
• Risk management plans should be comprehensive and reviewed periodically.• Operators should institute complete and standardized records systems.• Operators should implement risk management transition plans <1 year.• Operators and regulators should account for a broad range of risk factors.
Task Force Recommendations
12
Topic 2: Risk Management
Topic 3: Research and Data Gathering
• A quantitative analysis of downhole safety valves (DHSVs) is needed.• Systematic study comparing the effectiveness of casing evaluation tools is
needed.• Wellbore simulation tools should be reviewed and evaluated.• A thorough investigation of well registration, record keeping, and survey
practices is needed.• Proximity of gas wells to population centers should be investigated.
• Current monitoring activities at Aliso• An infrared fence-line methane-monitoring system• Around-the-clock pressure monitoring of all wells in a 24-hour
operations center• Daily patrols to examine every well conducted four times each day• Daily scanning of each well using sensitive infrared thermal
imaging cameras that can detect leaks• Enhanced training for employees and contractors
• Continuous monitoring required by new CA UGS rules• Laser line of sight technology readily available now for
natural gas applications• States First Gas Storage Guide recommends:
• Gas monitoring and isotopic gas analysis• Downhole pressure changes• Fluid-level monitoring (if necessary)
UGS Monitoring
Rongere, 2016
SoCalGas
• Ground-based optical gas imaging (hand-held)
• Aerial surveys
• Point measurements (handheld)
• Point measurements (stationary)
• Open Path Infrared
Surface Leak Detection Approaches
Continuous monitoring is becoming more accurate with decreasing cost. ARPA-E MONITOR program focus on methane emissions detection technology.https://arpa-e.energy.gov/?q=arpa-e-programs/monitor
• Storage in oil and gas fields, saline aquifers
• Requires new wells (Class VI) for injection
• Full well cemented (Class VI)
• Comprehensive well integrity and site monitoring requirements
• Non-flammable, denser than air
• No odorant used, maybe tracer
Comparison between CCS and UGS
• Storage in oil and gas fields, saline aquifers, and salt domes
• Repurposes old oil and gas wells for injection and production
• Long well intervals without cement
• Flammable, lighter than air
• Use of odorant
• Some production through tubing and casing
• >15,000 wells at >400 facilities (US)
• ~4 TCF stored in U.S., much produced annually
Geologic Carbon Storage Underground Gas Storage
May have active oil production in same fields (area) as GCS and UGS
https://energy.gov/under-secretary-science-and-energy/downloads/report-ensuring-safe-and-reliable-underground-natural
Thank you!
16
17
• CaCl2 fluid (~33% higher viscosity than water), the gas leakage dipped but not killed.
• Gas leakage increased briefly during liquid injection then decreased due to two phase flow in well
• Subsurface pressure pushed back out the injected liquid (green curve).
• After maximum liquid return flow, the gas leakage became violently oscillatory until about 80 min, when almost all injected liquid removed from well.
TOP KILL simulation example
LBNL, 2016
• In this simulation RW is initially filled with liquid (9.0 lb/galCaCl2 fluid).
• Gas leakage stops within 10 min after milling into SS-25 9.0 lb/gal CaCl2 fluid.
• Liquid leakage increases with time after ~70 min after both wells are filled with liquid.
Filling relief well stopped gas flow
Reservoir pressure 1100 psi
Filled with liquid
LBNL, 2016
• SoCal Gas has petitioned DOGGR to reopen part of field for injections
• 45 of 114 wells have passed pressure tests• One well (SS-25) permanently plugged and abandoned
• New operating procedure for wells• Tubing has been replaced in the 45 wells ready for operation• Production will only occur through tubing• The 45 wells are continuously monitored for pressure
• Daily infrared thermal imaging scanning for surface leaks
• The “new” field working gas storage capacity will be capped at a lower level
Current Aliso Status
20
Thank You!Questions and Comments
