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
Goals of this presentation are:
To provide clear information on State requirements for new or expanded/modified injection project applications
To describe data required for a complete application so the review process can proceed efficiently
To enlist the support of operators by encouraging them to perform their own Area of Review (AOR) and identify problem wells before submitting their application to the Division 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 et seq
Section 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 – 1998
Section Project Data
3) Primacy Agreement with U.S. EPA
The DOGGR’s basic authority for the operation, maintenance, and abandonment of oil, gas and injection wells in the state.
Authority
CA Law
CA regulations
Primacy Application

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 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)
SDWA - requires permit prior to injection
injection will not endanger drinking water sources
includes inspection, monitoring, record keeping and reporting to US EPA by state

7. March 14, 1983 Primacy for Class II UIC Program
DOGGR U.S. EPA
Injection Well Program UIC Class II Program
“One permitting agency”
One Permitting agency instead of 2
DOGGR 1) enhance recovery
2) protect fresh waters
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
1) One permitting agency DOGGR – Encourage the ultimate recovery of the resource
Prevent Damage – waters, life, health, property,
natural resources
2) Two Permits required:
Project Approval Letter
Individual Well Permit
Protection of USDW’s = 10,000 ppm TDS
MIT testing - Internal MIT’s (determine significant leak of casing, tubing and packer)
- External MIT’s (determine no injection fluid migration behind casing, tubing and packer)
AOR or Area of Endangering Influence – calculated for injection period equal to expected life of the injection well/project.

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.
Base of Fresh Waters (BFW) = historically 3,000 ppm TDS

10. Prior to Injection Two Parts to Permitting Injection
1) Injection Project Approval (sec )
2) Individual Well Permits (sec (d))
Geologic
Engineering study
Injection plan

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 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
Data submitted is incomplete either because Division records are not complete or operator failed to file well histories and supporting data
Inaccurate data. Data submitted does not conform to data in Division records
AOR – identify problem wells
Well lacking cement behind casing at the BFW and above the zone
Holes in casing, especially old wells.
Improperly abandoned wells – lacking cement behind casing behind plug

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? Continued
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
5) Any potential pathways for migration of fluids? 6) Is the BFW protected?

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?
New projects will require more data review
Expansion or modification of an existing 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!”
EOR and WD have different monitoring requirements
WD and Commercial have different monitoring and bonding requirements

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 (a)(4)

21. Area of Review California Requirement Federal 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 (a)(4) and Primacy Application pages
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 Radius minimum 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 (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 / φ μ C r²) s)
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)
Burt changes

31. Bernard’s Equation Example
P(r,t) 1, psi s 0 Pi 1, psi r 690 ft q ,000 bpd u .8 cp Δ P 8.82 psi k 300 md ft rise 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 (a)(4))
Must demonstrate confinement to the permitted zone of injection to: (CCR (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?”
1) No migration into USDW or BFW
2) Zonal isolation

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
CCR Sec –
Regulations require the annular space behind casing to be 500 feet above oil and gas zones or anomalous pressure intervals.

34. Provides a quick view of the condition of each well
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

37. 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

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

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

40. 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
CCR Sec and CCR Sec (c)(7)

41. 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 (c)(7)
For EOR injection fluid source must be continuous
Fluid Analysis must include TDS, specific gravity, pH, specific conductivity, etc

42. 9) What is the Injection Plan?
Project Applications Require an Injection Plan that provides the following data: (for complete list see CCR Sec (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?”

43. 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 (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?”

44. 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 (8)(d)

45. All data must be supported
Gaps between Operator records and Division well records.
Especially old wells
Operators can come into District office and check well records for completeness
Engineers reviewing project data compare information submitted with in house well file data In some cases, in house data is incomplete especially wells older than 1940’s
In other cases, data has not been submitted

46. 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

47. 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
Recap
Mandate - “prevent damage”
How – 1) protect fresh waters
2) confined to approved zone(s) of injection
Evaluation - data must support information
data gaps => time
data processing => sheer volume of information
scanned/electronic
1) Completeness of project application – first step
2) Evaluation of data - AOR
casing diagrams
e logs evaluation of zones
Class II fluid
3) Injection Plan - purpose of project EOR / WD
determining MASP
frac gradient
step-rate test

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

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

50. QUESTIONS?

51. Appendix Class II Well Classification and Fluid Definition
PRC Sections - Abandonment of Wells

52. 40 CFR Sec. 144.6 Classification of wells
(b) Class II Wells which inject fluids: (1) Which are brought to the surface in connection with natural gas storage operations, or conventional oil or natural gas production and may be commingled with waste waters from gas plants which are an integral part of production operations, unless those waters are classified as a hazardous waste at the time of injection (2) For enhanced recovery of oil and natural gas; and (3) For storage of hydrocarbons which are liquid at standard temperature and pressure

53. July 1987 FINAL POLICY – Classification of Class II Wells
Aside from EOR operations, four kinds of fluids can be injected into Class II wells.
Waste waters (regardless of their source) from gas plants which are an integral part of production operations, unless those waters are classified as hazardous waste at the time on injection.
Brines or other fluids brought to the surface in connection with oil or natural gas production or natural gas storage operations.
Brines or other fluids described in item 2 which, prior to injection, have been:
Used on-site for purposes integrally associated to oil and gas production or storage,
Chemically treated or altered to the extent necessary to make them useable for purposes integrally related to oil and gas production or storage, or
Co-mingled with fluid wastes resulting from the treatment in (b), so long as they do not constitute a hazardous waste under 40 CFR Part 261.
Fresh water (i.e. water containing less than 10,000 mg/l TDS) from ground-water or surface water sources, added to or substituted for the brine may also be injected, as long as the only use of the water is for purposes integrally associated with oil and gas production or storage
Fro EOR projects the fluid must come from a continuous source

54. Class II Wells
Aside from produced brines, the State Oil and Gas Supervisor has determined that a Class II WD well may accept the following non-hazardous fluid types that originate from oilfield activities:
1) Diatomaceous earth filter backwash;
2) Thermally enhanced oil recovery cogeneration plant fluid;
3) Water-softener regeneration brine;
4) Air scrubber waste;
5) Drilling mud filtrate (slurry);
6) Slurrified crude-oil saturated soils;
7) Tank bottom sludge; and
8) NORM (Naturally Occurring Radioactive Material)
9) Cuttings

55. E & P Waste Is the waste intrinsic to oil production? Yes,
(e.g. waste generated by contact with production stream) No
(e.g. wastes not generated by contact with the production stream)
E & P Exemption may apply,
depending on the characteristics of the wastes
E & P exemption does not apply
Does the waste meet any of the criteria for
hazardous waste in CA:
Ignitibility, Corrosivity, Reactivity or Toxicity?
(22 CCR, Article 3)
Does the waste meet any of the criteria for
hazardous waste in CA
Ignitibility, Corrosivity, Reactivity or Toxicity?
(22 CCR, Article 3)
Yes No
Yes No
Is waste hazardous solely by
meeting TCLP criteria
for Toxicity?
(22 CCR, Sec )
Waste not hazardous in CA
manage in accordance with
laws applicable to
exempted E & P waste
Manage as hazardous waste
in accordance with
applicable laws
Manage as non-hazardous solid
waste, in accordance with
applicable laws Yes
Yes
No, it meets other criteria
For hazardous waste
flowchart from the “Oil Exploration and Production Waste Initiative” May 2002 CA EPA - Department of Toxic Substances Control Hazardous Waste Management Division Statewide Compliance Division
E & P exemption applies,
Wastes not hazardous in CA
manage in accordance with
laws applicable
to exempted E&P waste.
E&P exemption does not apply
manage as hazardous waste,
in accordance
with applicable laws
From DTSC Pub. Oil Exploration and Production Wastes Initiative, May 2002

56. PRC Section 3228
Section 3228
Before abandoning any well in accordance with methods approved by the supervisor or the district deputy, and under his or her direction, the owner or operator shall isolate all oil-bearing or gas-bearing strata encountered in the well and shall use every effort and endeavor to protect any underground or surface water suitable for irrigation or domestic purposes from the infiltration or addition of any detrimental substances.

57. PRC Section 3208
Section 3208
A well is properly abandoned when it has been shown, to the satisfaction of the supervisor, that all proper steps have been taken to isolate all oil-bearing strata encountered in the well, and to protect underground or surface water suitable for irrigation or farm or domestic purposes form the infiltration or addition of any detrimental substances and to prevent subsequent damage to life, health, property and other resources.