Common Reasons for

Injection Project Approval Delays

LA SPE March 9, 2010

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

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?

Quick Acronyms

Division or DOGGR - Division of Oil, Gas, and Geothermal Resources

UIC - Underground Injection Control

AOR - Area of Review

MIT - Mechanical Integrity Testing

DOGGR Authority from 3 Sources1) 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

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 Regulations40 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)

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

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

Fundamental Mandate of the DivisionPRC 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.

Prior to Injection

Two Parts to Permitting Injection

1) Injection Project Approval (sec. 1724.6)

2) Individual Well Permits (sec. 1722 (d))

Project Application: Major Elements1) 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)

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

delays.

Main Reasons for Project Approval Delays1) 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

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”

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

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?

Most common questions:

1) Is this a new project or expansion of an existing permitted project?

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

2) What is the primary purpose of the project? CCR Sec 1724.7 (a)(1)

EORWaterfloodSteamfloodOther

Disposal Water DisposalCommercial Water Disposal

“We need a clear statement of the purpose so we know what to permit!”

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)

Area of ReviewCalifornia 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

Area of Review(AOR)

¼ mile radius

Fixed Radiusminimum ¼ mile radius

Fixed Radius minimum ¼ mile fixed radius

Directionally Drilled Wells

(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”

AOR for Project Expansion

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

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.”

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) - 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)

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 cp Δ P 8.82

psi k 300 md ft rise 20.38 h 1,000 ft t 21,902.4 hrs 30 months φ .22 C 3.20 E-06

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?”

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 1722.2 – 1722.4

Casing diagrams 1) Include casing diagrams for wells in the

AOR/AOI:

ProducingIdle Plugged and abandoned

(include offset operator’s wells)

2) Must show current condition

Provides a quick view of the condition of each well

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

Casing Diagram Requirements

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

Operators completing an AOR prior to submitting an application can

identify problem wells and propose remedial work or an alternative

injection plan

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

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 1724.6 and CCR Sec 1724.7 (c)(7)

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)

9) What is the Injection Plan?Project Applications Require an Injection Plan that

provides the following data: (for complete list see CCR Sec. 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?”

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?”

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)

All data must be supported

Gap in Division Inhouse Data

Well records may be incomplete because:

Old wellsOperators have not submitted records of all

work Review of well histories may have missed

cement information and other well dataE-logs, directional surveys, other logs not on

file

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

Electronic FormatPlease submit Injection Project Applications in

hardcopy and include a scanned version either on a DVD or via email

pdf format 300 dpi resolution

Thank YouAny questions, please contact the

UIC Engineer in your local Division District Office

For more information

www.conservation.ca.gov

QUESTIONS?

Appendix

Class II Well Classification and Fluid Definition

PRC Sections - Abandonment of Wells

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

July 1987 FINAL POLICY – Classification of Class II Wells

Aside from EOR operations, four kinds of fluids can be injected into Class II wells.

1. 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.

2. Brines or other fluids brought to the surface in connection with oil or natural gas production or natural gas storage operations.

3. Brines or other fluids described in item 2 which, prior to injection, have been:

a) Used on-site for purposes integrally associated to oil and gas production or storage,

b) Chemically treated or altered to the extent necessary to make them useable for purposes integrally related to oil and gas production or storage, or

c) 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.

4. 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

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; and8) NORM (Naturally Occurring Radioactive Material)9) Cuttings

E & P Waste

Is the waste intrinsic to oil production?

Yes, (e.g. waste generated by contact with production stream)

Does the waste meet any of the criteria for hazardous waste in CA:

Ignitibility, Corrosivity, Reactivity or Toxicity?(22 CCR, Article 3)

E & P Exemption may apply, depending on the characteristics of the wastes

No(e.g. wastes not generated by contact with the production stream)

Yes

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)

No Yes No

Is waste hazardous solely by meeting TCLP criteria

for Toxicity? (22 CCR, Sec. 66261.24)

Waste not hazardous in CAmanage in accordance with

laws applicable to exempted E & P waste

Manage as hazardous wastein accordance with

applicable laws

Manage as non-hazardous solid waste, in accordance with

applicable laws Yes

Yes No, it meets other criteriaFor hazardous waste

E & P exemption applies,Wastes not hazardous in CAmanage 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

flowchart from the “Oil Exploration and Production Waste Initiative”May 2002

CA EPA - Department of Toxic Substances ControlHazardous Waste Management Division

Statewide Compliance Division

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.

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.