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CO 2 Sequestration

CO 2 Sequestration. Dave Hill. Overview. Class I wells - Hazardous wastes and non-hazardous industrial or municipal wastes are injected beneath the lowermost underground source of drinking water (USDW). Class II wells (second half of this talk)

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CO 2 Sequestration

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  1. CO2 Sequestration Dave Hill

  2. Overview • Class I wells - Hazardous wastes and non-hazardous industrial or municipal wastes are injected beneath the lowermost underground source of drinking water (USDW). • Class II wells (second half of this talk) - Enhanced oil recovery (EOR) injection and disposal of oil and gas wastes. • Class III wells - Associated with solution mining.

  3. Federal Overview • Class IV wells - Shallow injection of treated hazardous wastes and are banned except when used as part of authorized groundwater remediation projects. • Class V wells - Shallow injection of non-hazardous fluids not covered by Class I wells, and experimental wells. • Class VI wells - Recently created by EPA, are associated with CO2 capture and storage (CCS) activities.

  4. The Various Means of CCS

  5. Senate Bill 1387 (SB 1387), 2009 • SB1387: In 2009, the Texas Legislature passed, and the governor signed a bill, “relating to the capture, injection, sequestration, or geologic storage of carbon dioxide”. -Response to draft of federal Class VI rules -Underground Injection Control (UIC) part of the Federal Safe Drinking Water Act (SDWA).

  6. Anthropogenic Carbon Dioxide • SB 1387 in large measure deals with anthropogenic CO2 which is “ carbon dioxide that would otherwise be released to the atmosphere…”. - Includes CO2 from gas processing plant or an industrial emissions source. - Excludes naturally occurring CO2 recaptured, recycled, or reinjected as part of enhanced oil recovery (EOR) operations.

  7. 16 TAC Chapter 5: RRC CO2CCS REGS • Site characterization • AOR and corrective action • Well construction/Plugging • Mechanical integrity/Monitoring • Emergency response • Financial Security • Post-injection facility care

  8. Plans Required • §5.203 (f): Logging and Sampling Before Injection • §5.203 (h) Mechanical Integrity Testing • §5.203 (i) Facility operating plan. • §5.203 (j) Monitoring after Initiating Operations • §5.203 (k) P & A of Injection & Monitoring Wells. • §5.203 (l) Emergency and Remedial response. • §5.203 (m) Post Injection Care and Closure

  9. Notice and Hearing • §5.204 includes notice and hearing requirements. - Notice by local publication - Local and public placement of a copy of the application - Criteria for persons to be notified - Requirements for a hearing.

  10. Fees, Financial Responsibility, and Financial Assurance • §5.205 includes description of Fees, Financial Responsibility, and Financial Assurance requirements. - Fees to be paid for applications - Financial responsibility verification - Financial assurance criteria regarding operations and phases of the facility.

  11. Permit Standards • §5.206 statesRRC may issue a permit if: • No endangerment/injury to oil, gas, other minerals, • Water protected from CO2 migration or displaced fluids, • No endangerment/injury to human health/safety, • Reservoir suitable for preventing CO2 escape/migration, • Applicant meets statutory and regulatory requirements.

  12. Permit Standards • §5.206 also includes • Implementation of plans (previously listed) • Requirement of a Letter from RRC Groundwater Advisory Unit stating that the facility will not injure USDW’s.

  13. Reporting and Record Keeping • §5.207 includes reporting and record keeping requirements. - Test records - Operating reports - Reporting frequency depends on the type of information reported. This ranges from 24 hours to annual reporting

  14. Chapter 5: NEWEST REGULATIONSAssociated with EOR/EGR PURPOSE: Provide for certification of CCS of CO2 incidental to enhanced recovery operations for which: • there is a reasonable expectation of more than insignificant future production volumes or rates as a result of the injection of anthropogenic CO2 ; and • operating pressures no higher than reasonably necessary for enhanced recovery

  15. Chapter 5: NEWEST REGULATIONSAssociated with EOR/EGR Registration for Certification Requires registration of enhanced recovery facility for which the operator proposes to document CCS of anthropogenic CO2 incidental to enhanced recovery

  16. Chapter 5: NEWEST REGULATIONSAssociated with EOR/EGR Monitoring, Sampling and Testing Plan: This is required for determination of the quantities of anthropogenic CO2 permanently stored within the enhanced recovery reservoir. For this, there are two options. §5.305 (2) is one of them. This includes “mass balancing or actual system modeling”

  17. Chapter 5: NEWEST REGULATIONSAssociated with EOR/EGR Monitoring, Sampling and Testing Plan: §5.305 (3) is the other option. The owner / operator may submit to RRC, a copy of the same information submitted to EPA under Subparts RR or UU of 40 CFR Part 98, Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide.

  18. Overview (Revisited) • Class I wells - Hazardous wastes and non-hazardous industrial or municipal wastes are injected beneath the lowermost underground source of drinking water (USDW). • Class II wells - Enhanced oil recovery (EOR) injection and disposal of oil and gas wastes. • Class III wells - Associated with solution mining.

  19. Sources of CO2 and Users

  20. CO2 EOR Sources

  21. SACROC – Eastern Edge of Permian Basin Scurry Area Canyon Reef Operators Committee (SACROC) unitized oil field • Ongoing CO2 injection since 1972 • Combined enhanced oil recovery (EOR) with CO2 sequestration • Depth to Pennsylvanian- Permian reservoir ~6,500 ft • Approximately 3900 miles of CO2 pipelines(Dooley et al)

  22. SACROC Well Map

  23. KM currently operates SACROC and is providing much assistance with the project SACROC Previous CO2 Injection • 3 trillion standard cubic feet (TCF) or 150 million metric tons (MMt) CO2 injected for enhanced oil recovery (EOR) since 1972 by multiple field operators (BEG, 1984; KM, 2008) • 1.5 TCF (75 MMt) CO2 recovered as of October 1, 2008 (KM, 2008) • Southwest Partnership (SWP) researchers are among first to test if this CO2 is trapped in reservoir zones or if it has leaked into overlying strata

  24. BEG and TWDB Water Well Data at SACROC Geologic units Surface geology from BEG Big Spring and Lubbock GAT sheets Q – Quaternary undifferentiated P-Eog – Paleocene-Eocene Ogallala TrD – Triassic Dockum P – Permian undifferentiated

  25. Cross Section Rebecca C. Smyth, Bureau of Economic Geology, Gulf Coast Carbon Center, Jackson School of Geosciences, The University of Texas at Austin and Brian McPherson, New Mexico Tech and University of Utah (modified from Duffin and Benyon, 1992)

  26. Temporal Trends of all TWDB & BEG Data

  27. Temporal Trends of all TWDB & BEG Data

  28. SACROC AREA WATER QUALITY 36 of 60 wells completed in both Ogallala and Dockum Santa Rosa water- bearing units; 17 wells inside and 19 wells outside SACROC; highest data

  29. Historic CO2 Sales

  30. Current Situation – CO2 EOR Projects

  31. Current Situation – CO2 EOR Production

  32. Injection/Disposal Well Permit Testing and Monitoring Seminar Manual • http://www.rrc.state.tx.us/forms/publications/HTML/pmt-outl.php#techrev - I. Administrative Review Check non-technical filing requirements - II. Attachments for new wells - III. Transfer and Amendments - IV. Technical Review Compliance with well construction, operation, and injected fluid confinement requirements - V. Permit Processing Stages of review - VI. Protested Applications Stages for protested applications - VII. Post Permitting Report requirements after the injection permit is issued.

  33. Administrative Review – Basic Filing requirements 1. Application Forms. * Forms H-1 , and H-1A. (Injection into a Reservoir Productive of Oil or Gas, Rule 46). - A productive reservoir is one with past or current production within a 2-mile radius of the proposed injection well. * Form W-14 , (Injection Non-productive reservoir, Rule 9). 2. Fees. These fees are non-refundable. a. $100 disposal permit application (Rule 9) filing fee (per wellbore). b. $500 injection permit application (Rule 46) filing fee (per wellbore). c. $375 (additional) for each exception request.

  34. Post Permitting • Annual Monitoring Report (Form H-10): - Report Injection pressure and volumes unless the well is actively producing and they file an annual production status report (Form W-10 or G-10) instead. • Mechanical integrity test (MIT) (Form H-5): - Verify that the well won’t leak before injection. MITs must be performed periodically for the life of the permit. • Completion report (Form W-2 or G-1): - Within 30 days of conversion, document the actual completion details of the well. Staff will review form against the approved permit.

  35. Facilities and Water Wells * The majority of these complaints are drought related. Many others involve one time sampling events for oil and gas constituents, where lab data show no impact. About two wells per year are confirmed to be attributable to Oil & Gas activities.

  36. The End

  37. Contact Info   http://www.rrc.state.tx.us/ david.hill@rrc.state.tx.us 512 463 3011

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