manual 001: facility and well site inspections

Manual 001: Facility and

Well Site Inspections

Enforcement and Surveillance Branch

June 2014

24 hour Emergency Number

1-800-222-6514

Energy or Environmental Emergency

Complaints

AER Field Centres and Offices

• AER Offices

AER Inquiries

1-855-297-8311

[email protected]

Key Messages

Directive 019 is a key component to compliance

assurance

Manual 001 identifies the most common

noncompliances for well sites and facilities (oil, gas,

and waste management)

The AER responds to industry incidents, including

releases, fires, and complaints

Directive 019: Compliance Assurance

Risk assessments

Response to noncompliant events

Persistent Noncompliance Framework

Appeals

Voluntary Self Disclosure

Compliance performance information


Proactive correction

No enforcement if conditions are met

Improved relationships

Improved public health and safety

Protection of the environment

Conservation of the resource

Regulatory confidence


The licensee must

be the first party to contact the AER,

not fall under one of the circumstances,

where a self disclosure will not be accepted,

correct the noncompliance in a timely manner,

develop and implement a written action plan.

Inspection Selection Process (OSI) Computer Generated

Operator Performance – provincial basis

inspection record and complaints

Sensitivity

forest, agricultural, populated areas

Inherent Risk

sweet vs. sour, single vs. multi-well

As Part of a Facility Inspection, AER Looks

at

The inspection history of a company

Complaint and incident history

Production records on PETRINEX (previously,

Petroleum Registry of Alberta)

The Emergency Response Plan (ERP)

Manual 001

Manual 001 is available on the AER Web site at

www.aer.ca/Rules&Directives/Manuals

Manual 001 highlights the most prevalent oil

and gas noncompliances encountered during routine

surveillance

Manual 001

Gas Measurement

Gas must be measured by

meters (> 0.5 E3M3 per day), or

determined by an engineering estimate, and

volumes => 0.1 E3M3 must be reported to

PETRINEX

How Often Should Gas Meters be

Calibrated?

In the first month of operation

Following a service or repair

Semi-annually for royalty trigger points (gas plant

sales)

Annually for all others

*Tag or report must be attached*

How Often are you Required to do an

Internal Inspection on Gas Meters?

Semi-annually for royalty trigger points

Annually for all other meters

Inlet Gas Plant Measurement

Must have inlet separation

Must have continuous measurement for all fluids

(gas, hydrocarbon liquids, and water)

Fuel Gas Measurement

Calibration Tag

16

Temperature

Compliant Compliant

18

Inappropriate Temperature Measurement

Needle Valves

Noncompliant Compliant

20

Liquid Meter Proving Frequency

Annually for wellhead, group, and injection

Semi-annually for gas plant

Monthly for delivery point

*Tag or report must be attached*

Measurement

Compliant Noncompliant

22

Accounting (Sales) Meters Require

Full port valves (same size as sensing lines)

Sensing lines must be a minimum 1/2” tubing for a

meter run greater than or equal to 4” in diameter, or

A minimum 3/8” tubing for a meter run less than 4” in

diameter

Sales Meter

Meter Tag/Chart Information

25

Meter Installation

26

Produced Water Injection

27

Water Injection Meter

Meter Calibration

29

Gas Plant Inlet Measurement

Orifice Plate

31

Sensing Lines Must

Have separate valve manifolds for each measuring

device

Be suitably winterized

Be self-draining

Chart Recorder Winterized

Gas Measurement Metering

Minimum temperature

reading frequency

Criteria or events

Continuous Sales/delivery points

and/or EFM devices

Daily > 16.9 103m3/d

Weekly 16.9 103m3/d

Daily Production (proration)

volume testing, non-routine

or emergency flaring and

venting

Oil and Emulsion Must be Measured by

Meters

Gauges, or

Weigh scales

Weigh Scale

Testing Requirements Oil Proration

S&W Analysis Requirements for Oil

Proration

Use a centrifuge for water cuts below 10 percent

Use a graduated cylinder and centrifuge for water cuts

10-80 percent

Use a graduated cylinder for water cuts above 80

percent

Petrinix Reporting

42

Petronix Reporting

43

Reporting

Must report volumes of flared/vented/incinerated gas

greater than or equal to 0.1 E3M3/month to PETRINEX

Operators must maintain a log of flaring, venting, and

incinerating events; and respond to public complaints

Petrinex Reporting

45

Petrinex Reporting

46

Spacing Requirements

Spacing Requirement

48

Spacing

50

Furnace

Ignition Source

56

Flare/Incinerator Stack Design and Operation

Decision Making and Planning When Flaring

or Venting

If vented gas can support stable combustion, burn it

Conserve, if possible

Venting should be the last resort

Decision Tree Analysis

Decision Tree Analysis

*Document analysis*

Can venting or flaring be eliminated? If no…why?

Include costs and economics

Venting Requirements

For temporary, short-term venting

Gas must be sweet

Volume must not exceed 2.0 E3M3 and duration must

not exceed 24 hours (excluding the clean-out phase

for testing)

Notification requirements must be met

Solution Gas Conservation

Must conduct an economic evaluation on all flared

volumes > 900 m3 per day

Must conserve if volumes are > 900 m3 per day within

500 metres of a residence

Licensees of production facilities operating within

3 kilometres of each other must jointly consider

“clustering” when evaluating solution gas conservation

economics

Flare Spacing Requirements

Must be 50 metres from wells and storage tanks

Must be 25 metres from processing equipment

Solution Gas Conservation

There are limitations for non routine flaring at solution

gas conserving facilities.

Any outage (planned or emergency) > 4 hours

inlet must be reduced by 75%

no flaring of solution gas >10% H2S

residents within 500 metres must be notified

Various requirements for outages < 4 hours and

partial equipment outages.

Liquid Separation must be Equipped with

A visual level indicator

A high level shutdown or alarm


Back Flash Prevention

Use flame arrestors between combustion points and

separators, or

Sufficient sweep gas to purge oxygen

Wind Guard/Flame Arrestor

No Flame Arrestor

Flare Ignition

1% H2S or higher, must have a pilot or auto igniter

Gas plants with 10ppm or more H2S requires a pilot

and an auto igniter

Pilot and Ignition Device

72

Flaring Limits: 6 Major Events in 6 Months

Below 1 billion m3/year (raw gas inlet volume)

vent/flare/incineration cannot exceed 0.5% of receipts

Above 1 billion m3/year (raw gas inlet volume)

vent/flare/incineration cannot exceed 0.2% of receipts

Plant Inlet Major Flaring Event

> 500 E3M3/d 100 E3M3

150 – 500 E3M3/d 20% of design daily inlet

< 150 E3M3/d 30 E3M3

Dispersion Modeling for Sour Gas Flaring

Dispersion modeling must be

conducted for the flaring or

incinerating of gas containing

>1% H2S, regardless of

volume

Well Test Notifications

Flare Pits


Low Risk Noncompliance

79

Incinerator/Exposed Flame

Signs and Security

Licensee or operator name

24 hour emergency phone number

Surface location

Appropriate warning symbol

flammable, or

sour - if above 10ppm H2S

Signage Requirements

83

Primary Entrance

84

Noncompliant Signage

Well pad Signage

86

Fencing Requirements

Batteries >1% H2S

cattle type fence with a minimum of four strand barbed wire

and either a gate or cattle guard

Batteries >1% H2S within 800 metres of a dwelling or

public facility

2 metre high mesh fence with a locked gate when

unattended

Pumping unit within 800 metres of a public facility

2 metre high mesh fence with a locked gate when

unattended

Sour Battery

ncing

Fencing Requirements

89

Wellhead Protection

Wellheads are to be conspicuously marked or fenced

so they are visible in all seasons

Farm or other vehicles must not operate within a

3 metre radius of the wellhead

Surface Casing Vent

Compliant NonCompliant

97

Emergency Controls and Relief Systems

Oil PSVs must be tied into a pop tank

Vessels must have a high level and high pressure

shutdown and be tied into a flare if >1% H2S

PSV Lines

99

H2S > 1%: Separator Controls

102

Surface Containers (< 1m3)

A licensee can store

1m3 onsite without

secondary containment

Anything more has to be

stored on a barrel dock

or inside secondary

containment

Container Storage Requirements

104

Bulk Storage Tanks (1m3 - 5m3)

Licensee can store up to 5m3 on site in a single

walled tank without secondary containment

Anything more, the licensee must have secondary

containment

Do monthly inspections to verify the tanks integrity

Single-walled Aboveground Storage

Tanks > 5m3

A dike and liner required

Dike capacity should be able to hold 110%

Spill control devices at fluid transfer points

Pre-1996 tanks require a 5-year integrity test (if no

liner installed)

High Risk Noncompliance’s

111

Oilfield Waste Storage

Aboveground Double-walled Storage

Tanks > 5m3

No dike or liner is required

Have measures in place to prevent overflow

(visible/audible alarm or a high level shutdown

*function tested monthly*)

Monitor the interstitial space monthly

Must have spill control devices on load lines

Aboveground Flare Knockout Tank

115

Underground Storage Tanks

Must be double walled (if installed after 2002)

interstitial space must be monitored monthly

Pre-2002 (single-walled) requires a 3-year integrity

test

Must have a level indicator or a high level alarm (to

prevent overfilling)

Steel tanks must have cathodic protection

Single Walled U/G Tank

117

U/G Tank Not In Service

118

Flare Knockout Tank

119

5 Year Integrity Test

122

Double Walled Tank

High Level Shutdown

123

124

Double Walled Tank

High Level Shutdown

Double Walled Tank

125

Secondary Containment

127

Secondary Containment

High Risk

Biopile/Excavated Contaminated Soil

Withdrawing a Tank from Service

Remove all fluids and keep it empty

All lines leading to the tank must be disconnected

Tag the tank Out Of Service

Compressor Installation

75kW and larger requires a

licence

Temporary compressor (less

than 21 days), AER approval

is not required

Must have landowner and

surrounding residents’

consent

Emergency Response Plan (ERP)

Requirements

A licensee must have a corporate ERP

A licensee may be required to have a site specific

ERP based on requirements under Directive 071:

Emergency Preparedness and Response

Requirements for the Petroleum Industry

Contact AER when activating the ERP to confirm

the emergency level and convey the specifics of the

incident

Questions the AER May Ask

Is there a site-specific emergency response plan

(ERP) where required?

Is safety equipment that is specified in the ERP

installed/available?

Is a copy of the ERP readily available onsite?

More Questions the AER May Ask

Is the ERP up to date?

When was the last ERP exercise held? Were the

details documented?

Is the licensee/operator onsite representative familiar

with the ERP?

Does the licensee/operator communicate regularly

with residents in the emergency planning zone (EPZ)?

Emissions

H2S emissions/odours not allowed off lease

No H2S emissions/odours allowed during

transportation of sour fluids

Noise Complaints

No Noise

Suppression

Noise Suppression

140

Benzene Emissions

Dehydrator Engineering and Operations Sheet

(DEOS) must be posted on site

DEOS must be revised annually or upon change in

status

Residents within 750 metres must be notified

Benzene Emissions Limits

Benzene Control Systems

Ways to reduce benzene emissions

incinerators

flares

condensers

*Note: the best control to reduce benzene emissions

is by operating the glycol dehydrator efficiently so the

glycol circulation rate is as low as feasible.

Noise Control and Common Noise Sources

Compressors

Pump jacks

Drilling and servicing operations

Keep the site in a clean condition

*No Staining*

Waste must be stored properly

Waste must be shipped to approved facilities

Waste tracking system (manifesting) must be

maintained

Waste Management

*Control and clean up spills immediately*

Notify the AER if identified as

> 2m3 on lease

off lease

any release from pipelines

on site and of a size that may cause, is causing or has

caused an adverse effect

“Notify the landowner of all off lease spills”

Spills and Fires Reporting

Release criteria for surface water

chloride content < 500mg/L maximum

pH between 6.0 and 9.0

no visible hydrocarbon sheen

no chemical contamination

flow not allowed directly into any watercourse

landowner consent obtained and documented

Surface Water

Injection Wells

Must have continuous measurement at the wellhead

(including acid gas injection wells)

Must not exceed maximum injection rates (as

specified in the injection well approval)

Emergency Controls and Relief Systems

Surface casing vent is required

Flowing well >5% H2S requires 2 master valves

Pumping well >1% H2S, capable of flow, requires an

hydraulic rod and environmental Blow Out Preventer

(BOP)

Flowing well >1% H2S requires surface shutoff valve

A Well is Determined Suspended When

There has not been any volumetric activity in a

12 month period

Critical sour and acid gas wells that have not had any

volumetric activity in a 6 month period

A licensee must evaluate the risk using AER Directive

013: Suspension Requirements for Wells, table 1,

that outlines all inactive well requirements

TABLE 1: SUSPENSION

REQUIREMENTS

Suspended wells must be inspected (1-5 years

depending on the type of well)

All outlets must be bull plugged or blinded

Valves must be chained and locked; or the valve

handles removed

*Note: a low risk well becomes a medium risk well

after 10 years of being in suspension (see down hole

requirements)

Suspended Wells

Abandonment

Critical Sour Wells

Requires a physical barrier that is clearly visible

around the well

Requires 2 master valves

If capable of flow to atmosphere, the well requires

a subsurface safety valve

Wellhead working pressure must not be less than

the bottom hole pressure

Requires a site specific ERP

If well is on rod pump, the well must have an

environmental BOP on top of the stuffing box

Surface Casing Vent Flow/Gas Migration

Any surface casing vent flow or gas migration must be

reported and repaired (if serious)

Isolation Packer

Packer isolation tests are required on

water injection/disposal wells

acid gas injection wells

wells >5% H2S

Packer isolation tests must be conducted annually and

reported to the AER

Casing Failures

Explosions

Fires

Pipeline hits and breaks

Spills

Landowner complaints

Incident Examples

What’s New

Manual 001 presentations for external stakeholder

access can be found at:

www.aer.ca/Compliance&Enforcement/education

New edition of Directive 039 (effective January 2013)

Revisions to Directive 017 (effective May 2013)

New Directive 083: Hydraulic Fracturing – Subsurface

Integrity (effective May 2013)

manual 001: facility and well site inspections

Documents