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Common Reasons for Injection Project Approval Delays LA SPE March 9, 2010

Department of Conservation Division of Oil, Gas, and Geothermal Resources Underground Injection Control Program. Common Reasons for Injection Project Approval Delays LA SPE March 9, 2010. GOALS of this presentation:.

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Common Reasons for Injection Project Approval Delays LA SPE March 9, 2010

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  1. Department of Conservation Division of Oil, Gas, and Geothermal Resources Underground Injection Control Program Common Reasons for Injection Project Approval Delays LA SPE March 9, 2010

  2. GOALS of this presentation: • To provide industry with clear guidelines on the submittal of injection project applications • To streamline the Division’s review process for injection project applications by clarifying data requirements • To encourage operators to do their own AOR to identify problem wells before submitting injection project applications for approval

  3. To meet these Goals this presentation will: • Clarify the Division’s authority for underground injection • Identify the Division’s mandate • Outline Injection Project Application Requirements • Provide insight to the Division’s review of project applications What are we looking for and why?

  4. Quick Acronyms • Division or DOGGR - Division of Oil, Gas, and Geothermal Resources • UIC - Underground Injection Control • AOR - Area of Review • MIT - Mechanical Integrity Testing

  5. DOGGR Authority from 3 Sources • 1) California Law: • Public Resources Code (PRC) • Division 3. Oil and Gas Section 3000 et seq Section 3106 - Division Mandate • 2)California Regulations: • California Code of Regulations (CCR) • Title 14 Natural Resources • Division 2 Department of Conservation • Chapter 4 Development of Oil and Gas Resources Sections 1712 – 1998 Section 1724.7 - Project Data • 3) Primacy Agreement with U.S. EPA

  6. U.S. EPA Authority • Federal Law • Safe Drinking Water Act (SDWA – 1974) • Part C – Section 300h et seq • Prevent Endangerment of Drinking Water Sources • Federal Regulations • 40 CFR Part 144 Sections 144.1 et seq • Underground Injection Control Program • Delegate Primary Authority to the States to carry out the federal program (feds maintain authority to take enforcement action if the State fails to act on a violation)

  7. March 14, 1983 Primacy for Class II UIC Program DOGGR U.S. EPA Injection Well Program UIC Class II Program “One permitting agency” California UIC Class II Injection Program

  8. Current CA Division Injection Program • Injection Project Approval + Well Permits • Protection of USDW’s 10,000 mg/L TDS • MIT testing (internal and external MIT) • Area of Review (AOR) or Area of Influence (AOI) • Aquifer Exemptions

  9. Fundamental Mandate of the Division • PRC Section 3106 – provides the fundamental duties of the State Oil and Gas Supervisor for the supervision of oil and gas activities in the State. (a) … to prevent: • damage to life, health, property, and natural resources; • damage to underground oil and gas deposits from infiltrating water and other causes; • loss of oil, gas, and reservoir energy; and • damage to underground and surface waters suitable for irrigation or domestic purposes, by the infiltration of, or the addition of, detrimental substances. …to encourage the wise development of oil and gas resources.

  10. Prior to Injection • Two Parts to Permitting Injection 1) Injection Project Approval(sec. 1724.6) 2) Individual Well Permits (sec. 1722 (d))

  11. Project Application: Major Elements 1) A statement of the primary purpose of the project 2) A detailed engineering and geologic study 3) Reservoir and fluid characteristics of each injection zone 4) Evidence that plugged and abandoned wells within the AOR will not have an adverse effect on the project 5) Casing diagrams and plugging information of wells within the AOR 6) Proposed well-drilling and abandonment program 7) An injection plan (sec 1724.7 Data Requirements)

  12. We are going to focus on those elements that cause the most delays.

  13. Main Reasons for Project Approval Delays 1) Failure to state purpose of the project 2) Incomplete or inaccurate data 3) Data is not detailed 4) Casing diagrams not current 5) Problem wells within the AOR 6) Failure to include directionally drilled wells in the AOR

  14. Project Application Review The following questions may be used to determine if the Division mandates will be met. “Prevent damage” and “Ensure ultimate recovery of the resource”

  15. Most common questions? 1) Is this a new project or expansion of an existing permitted project? 2) What is the primary purpose of the project? 3) What wells will be impacted? 4) What is the condition of each well affected by the project? Will the injection fluid be contained? 5) Any pathways to migration? Continued

  16. Common Questions continued … 6) Are casing diagrams included for all wells in the AOR, including directionally drilled wells? 7) Does the injection fluid meet the Class II well definition? 8) What is the source of the fluid? 9) What is the injection plan? 10) Will injection affect offset operators?

  17. Most common questions:1) Is this a new project or expansion of an existing permitted project?

  18. What Triggers Project Expansion or Modification? • Adding a new injection zone • Adding injection wells beyond the AOR • Increasing the geographic area • Adding or changing the source of injection fluid

  19. 2) What is the primary purpose of the project? CCR Sec 1724.7 (a)(1) • EOR Waterflood Steamflood Other • Disposal Water Disposal Commercial Water Disposal “We need a clear statement of the purpose so we know what to permit!”

  20. 3) What wells will be impacted by the project? (a) List all wells in the AOR or AOI that penetrate the intended zone of injection • Wells within the AOR or AOI • Wells directionally drilled into the AOR or AOI • Wells in the AOR/AOI belonging to offset operators • Wells in the AOR/AOI located on federal lands “1/4 mile radius” CCR Sec 1724.7 (a)(4)

  21. Area of Review • California Requirement • Prior to approval, the operator must submit an engineering study that includes casing diagrams…of wells within the area affected by the project. • CCR Sec 1724.7 (a)(4) and Primacy Application pages 15 - 16 • Federal Requirement • The area of review for each injection well, field or project area shall be determined according to either: • (a) Zone of endangering influence • (b) Fixed Radius • 40 CFR Sec 146.6

  22. Area of Review(AOR) ¼ mile radius

  23. Fixed Radiusminimum ¼ mile radius

  24. Fixed Radius minimum ¼ mile fixed radius

  25. Directionally Drilled Wells

  26. (b) List of all wells not penetrating the zone of injection if wells within the AOR do not protect the zone above the proposed injection zone and/or base of fresh water “Potential risks”

  27. AOR for Project Expansion

  28. Adding proposed injection wells outside the original ¼ mile area of review – Expansion

  29. Area of Influence • Computation of the Zone of Endangering Influence • The area the radius of which is the lateral distance in which the pressures in the injection zone may cause the migration of the injection and/or formation fluid into a USDW • Calculated for an injection time period equal to the expected life of the injection well or pattern • Bernard’s equation • Modified Theis Equation (one form of the equation) • 40 CFR Sec 146.6 (a) “Fluids must be confined to the permitted zone of injection.”

  30. AOI • The Bernard pressure build up equation is given as P(r,t) = Pi + (5575 q μ / k h)(log t + log (k / φμ C r²) - 3.32 + 0.875s) Where: P(r,t) = pressure as a function of radius and time (pounds per square inch, psi) Pi = initial zone pressure (pounds per square inch, psi) r = radius (feet, ft) t = time (hours, hrs) q = injection rate (gallons per minute, gpm) μ = injection fluid viscosity (centipoises, cp) k = zone permeability (millidarcys, md) h = net zone thickness (feet, ft) φ = porosity (percentage in decimal, e.g. 5% = 0.05) C = injection fluid compressibility (square inches per pound, 1/psi) s = skin factor (ratio, no dimensions)

  31. Bernard’s Equation Example P(r,t) 1,408.82 psi s 0 Pi 1,400.00 psi r 690 ft q 145.8333 5,000 bpd u .8 cpΔ P 8.82 psi k 300 mdft rise 20.38 h 1,000 ft t 21,902.4 hrs 30 months φ .22 C 3.20 E-06

  32. 4) What is the condition of each well affected by the project? • Must show evidence that wells within the AOR/AOI will not have an adverse effect on the project (CCR 1724.7 (a)(4)) • Must demonstrate confinement to the permitted zone of injection to: (CCR 1724.7 (c)(3)) • Ensure project meets its purpose • Protect USDWs • Prevent damage to oil and gas reservoirs • Prevent surface break through • Protect other reservoirs “Will the injection fluid be confined to the intended zone of injection?”

  33. 5) Any pathways to migration? • Is there sufficient cement behind casing to prevent fluid migration? • Will the injection fluid be confined to the intended zone of injection? • Is there cement behind casing protecting the base of freshwater? • Cement regulations require the annular space behind casing to be at least 100 feet above the BFW • A CBL, temperature, or other survey may be used to determine cement fill behind casing CCRSec 1722.2 – 1722.4

  34. Casing diagrams 1) Include casing diagrams for wells in the AOR/AOI: • Producing • Idle • Plugged and abandoned (include offset operator’s wells) 2) Must show current condition Provides a quick view of the condition of each well

  35. Casing Diagram Requirements • Operator, lease, well number, API number, date well drilled, location (Sec T&R) and drafting date, elevation of the well and datum reference • All casings, liners (size and weight) • All hole sizes (rotary drill holes, estimate if cable tool) • All perforations, cp points, WSO, etc. • Cement fill behind casing. Include cement volume and top of cement fill (note if actual or calculated). Tagged top of cement before drill out. • Depth to geologic markers, BFW, top of injection zone, injection intervals, etc. • Mud weight, if well is plugged and abandoned • Damaged casing, junk in hole, etc. • Kick-off and original hole diagrams

  36. Common missing casing diagram data • Redrilled wells, plugging and abandonment data for each redrill hole • Junk in hole and squeeze cement data • BFW depth • If well is directionally drilled • Depth and name of geologic markers

  37. Operators completing an AOR prior to submitting an application can identify problem wells and propose remedial work or an alternative injection plan

  38. 6) Are casing diagrams provided for all wells in the AOR, including directionally drilled wells? CCR Sec 1724.7 (a)(4)

  39. 7) Does the injection fluid meet the Class II well definition? • Integrally related to oil and gas production operations • California non-hazardous for water disposal wells CCRSec 1724.6 and CCR Sec 1724.7 (c)(7)

  40. 8) What is the source of the fluid? • Source of Fluid • Chemical Fluid Analysis • To ensure the fluid meets Class II well definition • To ensure the fluid is compatible with reservoir fluid CCR Sec 1724.7 (c)(7)

  41. 9) What is the Injection Plan? • Project Applications Require an Injection Plan that provides the following data: (for complete list see CCRSec. 1724.7 (c)) 1) Number of anticipated injection wells 2) Maximum anticipated: • Daily injection volume • Surface injection pressure • Daily rate of injection by well “Will the injection fluid be confined to the permitted zone of injection?”

  42. Injection Plan cont… 3) Monitoring system or method to be utilized to ensure no damage is occurring in the intended zone or zones of injections and that the fluid is confined to the intended zone or zones of injection.(CCR 1724.7 (c)(3)) (evaluated on a case-by-case basis) 4) Mechanical Integrity Testing (MIT) • Internal MI - no significant leak in casing, tbg, and packer • External MI - no significant fluid movement behind casing 5) Method of injection • Tbg and packer • Gravity feed “Will the fluid be confined to the zone?”

  43. 10) Will injection affect offset operators? • Application must include copies of letters notifying offset operators of the proposed injection project with copies of certified receipt of these letters. CCR Sec. 1724.7 (8)(d)

  44. All data must be supported

  45. Gap in Division Inhouse Data • Well records may be incomplete because: • Old wells • Operators have not submitted records of all work • Review of well histories may have missed cement information and other well data • E-logs, directional surveys, other logs not on file

  46. Application delays can be minimized if Operators either submit supporting data with their applications or Review well files in the District Office and ensure DOGGR data is complete

  47. Electronic Format • Please submit Injection Project Applications in hardcopy and include a scanned version either on a DVD or via email • pdf format • 300 dpi resolution

  48. Thank You • Any questions, please contact the UIC Engineer in your local Division District Office • For more information • www.conservation.ca.gov

  49. QUESTIONS?

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