Frequently Asked Questions
The Water Act Application Manual has been drafted, but has not yet been implemented; as such it is not available on the Commission website. It is unknown at this time when the Water Act Application Manual will be finalized and posted to the Commission website. In the interim, please refer to the Environmental Protection and Management Guidebook for information regarding seismic lines, stream crossing methods and stream crossing best management practices. Waterbody classification is outlined in the Environmental Protection and Management Regulation.
Orders established by the Ministry of the Environment for Wildlife Habitat Areas, Ungulate Winter Ranges, Fisheries Sensitive Watersheds, and Temperature Sensitive Streams, which continued those designations made under the Forest and Range Practices Act (FRPA) at the time that the EPMR came into effect (October 4th, 2010), were approved by the Deputy Ministry of Forests, Lands and Natural Resource Operations on August 18th, 2011. All subsequent areas established by order will be legal under OGAA and the EPMR at the time of designation, and will be established spatially in the province’s Land Resource Data Warehouse.
Once an area has been legally established by Minister’s Order, it brings into effect “government’s environmental objective” for that area. In accordance with section 25 (1) of OGAA, the Oil and Gas Commission must consider government’s environmental objectives for the species associated with the designated area.
Section 23 of the Environmental Protection and Management Regulation (Regulation) states the riparian classes of wetlands. The wetlands are classed based on size and biogeoclimatic zones. Please refer to the Regulation for more detail on the individual classifications of wetlands, and Section 5 of the Guidebook.
Visual quality objectives, as defined under FRPA, do not pertain to oil and gas activity; thus visual quality polygons should not influence application requirements. You are correct in the assumption that visual quality is not regulated under OGAA. In some circumstances where significant values have been identified, or where there is sufficient justification, it may be appropriate to ask an operator to consider or mitigate impacts to visual values.
As below, the previously required setbacks are no longer outlined in the Regulation. This is not an error. Operators must still ensure however that environmental objectives set out in the Regulation are met. Furthermore, operators must be aware of other acts that affect their operations. Other acts may include but are not limited to the Water Act, Wildlife Act and the Species at Risk Act. Section 26 of the Environmental Protection Management Regulation (Regulation), Wildlife Habitat Features Identified states:
- The minister responsible for administering the Wildlife Act, by order, may identify any or all of the following as a wildlife habitat feature:
(a) a fisheries sensitive feature;
(b) a marine sensitive feature;
(c) a significant mineral lick or wallow; (
d) a nest of
(i) a bald eagle,
(ii) an osprey,
(iii) a great blue heron, or
(iv) a category of species at risk that is limited to birds;
(e) any other localized feature that the minister responsible for the Wildlife Act considers to be a wildlife habitat feature.
- Identification of a wildlife habitat feature under subsection (1) may be by category or type and may be restricted to a specified geographic location. In addition, Section 6.9 of the Environmental Protection and Management Guidebook (Guidebook) Wildlife Construction Setbacks states: The following are the minimum suggested construction setbacks for each identified habitat feature: • Trumpeter Swan Nest – 200 meters; • Other nesting sites (i.e.: Osprey stick nest, sandhill crane ground nests) – 100 meters; • Mineral licks – 100 meters; • Bear dens (applies to winter construction only) – 50 meters; In some cases, additional setbacks may be required due to lack of topographical relief, sparse vegetation density, extensive use of habitat, and other special considerations. Where the minimum suggested construction setbacks are not being maintained, proponents are expected to submit to the Commission, as part of the oil and gas activity application, a rationale for the activity placement in proximity to the habitat feature and demonstrate how the integrity of the feature will be protected through mitigation. The Water Act, Wildlife Act and any other acts and regulations that may affect operations must be adhered to by any operator.
The C&N regulation does not apply to roads being proposed within a road allowance. However it is expected that the applicant will be advising any adjacent landowners of their proposed use of the road allowance. Trappers and guides do not require notification as road allowances are simply between quarters.
Below is a definition for each tool within the NEWT application.
- Use the pan and/or navigation buttons to find the desired location on the map
- Select the “Identify with tools” button, then use the “Select” tool
- Click a location on the desired stream or lake. The upstream watershed area will now be displayed with a red outline and crosshatched interior.
- The NEWT tool box will now display the selected watershed results, click result to zoom to the selected watershed.
- By default, the “Report Title” on the NEWT tool box will be filled in. This can be changed if desired. The report can now be exported in either PDF or CSV format.
- Select the “Enter Values Manually” tool
- Enter the UTM coordinates for one or more points in the format of Easting, Northing (eg. 516410, 6630377)
- Select submit
- The watershed area(s) will now be displayed with a red outline and cross hatched interior.
- The NEWT box will now display the watershed results. If you entered multiple points there will be multiple watershed results listed. Click on a watershed to zoom to zoom to it.
- By default, the “Report Title” will be filled in on the NEWT tool box. This can be changed if desired. The report can now be exported in either PDF or CSV format.
Air emissions are regulated under the Environmental Management Act. Smaller facilities are authorised to discharge under the Oil and Gas Waste Regulation, which contains NOx emissions limits. Larger facilities including gas processing plants and compressor stations with >3000 kw of compression require a waste discharge permit.
Submit a facility permit amendment to change the maximum H2S concentration at the facility as described. The permit amendment application must include a project description, engineering assessment of the piping and equipment design and materials, and an emissions review which will include dispersion modeling if a continuous flare exists. BC-20 has been replaced by a facility permit application (KERMIT), and the BC-21 has been replaced by the Facility Schedule 1 Form. The landowner and public consultation and notification requirements are explained in the Consultation & Notification Regulation and C&N Manual. For consultation and notification purposes in this case, the application to increase the H2S concentration to 2% H2S would be a major amendment.
We require the cumulative facility venting rate, existing and proposed (new).
For additional equipment, see pages 78/79 of the Facilities Manual for examples of what would require a notice instead of a permit.
This would require a Facility Permit Amendment – Add/Delete Equipment.
Generally all metering requires a permit.
The current regulatory process for a well linkage change using the new Schedule 1 form (replacement of the previous BC-21 Well or Facility to Facility Linkage) is to submit a well linkage Notice of Intent (NOI) through KERMIT. KERMIT home page ? Applications ? NOI Facility (Upstream) ? Linkage Change This is not a permit application, and prior to the change being accepted, a database check confirmation and population task is completed. The Schedule 1 is then emailed or faxed to the person submitting the NOI. This process is not for new well linkages, as these are part of a facility permit or permit amendment application. Well linkages for in-line testing are part of the in-line testing notice submission process defined in the Pipeline Operations Manual. This process is explained in the revised Facilities Manual.
Yes, estimation of small flare / vent sources is acceptable. Refer to Section 11 of the Flaring and Venting Guideline for more information.
The BC 20 form no longer exists as the required information is now collected in KERMIT. This Change of Service will require a facility permit amendment, and the amendment will be designated major and will require the full consultation and notification.
This question would be answered, “No” in this instance as the scrubber is not recovering the vented gas stream. The gas would need to be captured and re-compressed into the main process stream through a vapor recovery system, or utilized as fuel gas, etc. to be viewed as recovered.
Yes, please submit a Facility Amendment – Add/Delete Equipment for no new land and the Schedule 1 - Well and Facility linkage.
The current process is outlined in the Corporate Land Management Manual. If a New Permit Holder or Corporate Structure Change Application Form is submitted and is complete, the Commission targets to establish the new permit holder in less than a week.
A frac-sand storage sites is a Crown Land Application, under Miscellaneous Forms and Guidelines. Frac-sand pits are applied for through ILMB.
Yes, if the campsite requires a Licence of Occupation, please apply for both temporary and permanent on the application.
Any authorized signatory of the applicant company may sign the Written Report Cover Sheet, accepting responsibility for the information contained in this form.
Any additional assets held by the company do not have to be included within the line list.
The intent of the mapping requirements is to help parties visualize how the potential oil and gas activity affects them. The scale of the maps is at the discretion of the applicant.
No. Applicants are required to list each tenure regardless of holder, as the line list must demonstrate that each rights holder (tenure specific) was addressed as per regulatory requirements.
An Agricultural Lease holder is a landowner. One who has a lease has an ownership: a disposition of Crown land issued under the Land Act. Woodlot licensees are rights holders under the Consultation and Notification Regulation, so some notifications and consultations apply to them, but they are not landowners and Section 31 of OGAA (requirement to notify landowners upon amendment) would not apply.
There is now an email address to which stakeholder information may be submitted: OGC.WrittenSubmissions@bcogc.ca. It is only to be used for submissions from affected persons or landowners as per OGAA section 22(5). The format of the submission should be the same as referenced in the manual (i.e. they may use the submission form or any other form of documentation such as a letter which provides the information the Commission needs to consider their interests).
Sumps located on privateland must be submitted with a well permit application.
If the replacement is in-kind, it is deemed an NOI (which would require the submission of a Notice of Construction Start, Notice of Pressure Test and Leave to Open for that activity). There is no notification or consultation required for an NOI because those are within the scope of the permissions and authorities on the application approvals. If the pipe changes at all, it is considered an amendment; consultation or notification would be required based on the class of the amendment (major or minor).
Only two sections of the old handbook still exist, Emergency Response Plans and Drilling Waste. All other information is within the application and operations manuals. Emergency Response Plan information is located under "Wells Forms and Guidelines" and Drilling Waste Management is located under "Waste Management and Reclamation".
These requirements are no longer in effect. The applicant can propose a project up to the established park or protected area boundary. There are no requirements limiting the nature of the type activity up to those boundaries unless otherwise legislated.
No. The project number is used for applicant internal tracking purposes.
Cheques are payable to the "Oil and Gas Commission"
The equipment would be either an oil facility or a non oil and gas facility; however, note that applications for these facilities on land that is already the subject of a permit (in this case a well permit) do not attract application fees. If, however, the wellsite includes equipment in the nature of compressors, dehydrators or gas processing plants, there is an application fee.
No. The only facilities classified as natural gas facilities are compressors, dehydrators, and gas processing plants. If the product is natural gas, and the facility is not one of these three, it is a “non oil and gas facility”.
Yes. A unique identifier will be applied to each amendment invoice to coordinate invoice payments.
At this time, amendment fees are not required when submitting a minor or major amendment application. The fee will be determined after the permit amendment application is received at the Commission. Once the decision-maker confirms whether the permit amendment is minor or major, the correct fee is then calculated and an invoice will be generated and mailed to the applicant.
The roads can be included under the ancillary application. 2) Only the borrow pits being applied for need to added to the table. However the additional pit not being applied for will be considered as part of the cumulative area.
A drilling event may not have occurred on the lease; however, the Commission has reason to believe that construction had started (e.g. clearing, road construction, cut/fill, etc.) Therefore these wells have been flagged ‘cancelled with surface disturbance’ and will require restoration work be completed in order to have a Certificate of Reclamation issued.
No. At this time WIPs are not taken into account. Under the program the permit holder of the site holds 100% of the deemed liability and production assets.
Because WIPs are frequently changing we are unable to consistently keep our records current enough to tie into the LMR program. Ultimately, the permit holder is held responsible by the Commission.
A number of things may have happened.
- A surface casing vent flow/ gas migration issue was identified, therefore a premium is added to the wells individual deemed liability.
- A drilled/cased well completion has been entered into the Commission database.
- A cancelled wellsite was later identified as being cancelled with surface disturbance.
- A well previously never having produced/injected, does so.
Complete abandonments: Deemed liability will decrease when a well is abandoned and the appropriate documentation is submitted to and approved by the Commission
Apply for a Certificate of Restoration (CoR): The deemed liability assigned to a site will be removed when the wellsite is reclaimed and a CoR is issued.
Terminate a facility: A Facility’s deemed liability will only be removed when a facility is decommissioned, removed from site and terminated in the Commission database.
The Commission may require a site-specific liability assessment for one or more permits to be used in the calculation of an operator’s LMR or, in the case of a problem site, for the determination of a required security deposit. The only time an operator may make the choice to submit a site-specific assessment is as part of a security deposit dispute process. As part of the process an operator must submit for review, along with a operator specific netback calculation, site-specific liability assessments completed by a qualified third-party professional for each well and facility permitted to the operator. More information on the dispute process and site-specific liability assessments can be found on pages 16 and 17 of the LMR Program Manual .
The OGC currently funds orphan well abandonments with a tax on production ($.06/m3 oil and $.03/e3m3 gas). One option used in other jurisdictions is through a fee based on a company’s liabilities as a fraction of industry liabilities.
The existing production-based Orphan Levy has been enacted in legislation. The Commission has no current plans to seek a change in legislation.
It is the intention that the LMR program will result in adequate security to cover well plugging and reclamation activities if a company becomes insolvent. The program is a protection measure to cover liabilities should a company fail to meet its closure obligations. However, there may be a potential for orphan wells should a company become insolvent that has failed to pay the required security.
Producers: No, you do not have to complete this form unless you choose to dispute a required security deposit by submitting a dispute request to the Commission. Under the current LMR program, a universal netback is calculated for all producers based on current CAPP statistics.
Non-producers: Yes, you do have to submit this form upon request from the Commission if a Permit holder wishes to receive a deemed asset for a designated gas plant or disposal station. The netbacks used in the determination of a deemed asset for processors and disposers is based on an average of all submitted industry netbacks from the most recent year-end totalled and calculated individually for each non-producer category.
Permit holders that chose not to submit a netback will be given a deemed asset of zero.
The industry average netbacks for non-producers will be valid for a period up to three years; sufficient notice will be given when the Commission is required or deems it necessary to update the industry average netbacks.
Permit holders who fail to submit required security deposits within the allocated timeframe may be in noncompliance with Section 30 of OGAA. If the security deposit was required to approve a permit transfer application, the application will not be approved. If the security deposit was required under an initial or bi-monthly assessment, additional compliance action will be taken against the permit holder. This may result in the cancellation of permits or orders to cease operations.
LMR ratios for BC operators are posted to the Commission’s website here. Ratios are calculated and updated daily. An operator may also request an Operator Detail Report (a report that lists the deemed assets and liabilities for each individual permit held by an operator) by emailing Liability.Management@bcogc.ca .
The Commission recognizes that other jurisdictions have previously implemented liability rating programs and believes that a consistent process between western provinces is a valid approach. However, there are no existing plans or agreements to harmonize a liability rating program among western provinces.
At this time no further consultation periods will be held for the producer and non-producer programs. That being said, the Commission is always open to feedback from stakeholders regarding our programs.
Typically, no. Only those that had an LMR less than 1.0 at the initial review at the inception of the LMR program in November 2011 were grandfathered into the phased payment schedule. New to BC operators who are drilling or purchasing their first wells, and those operators whose LMR falls below 1.0 as a result of a transfer or during a bi-monthly review, are required to bring their rating to 1.0 in a single security installment.
The letter of credit beneficiary and cheques are payable to, BC Oil and Gas Commission.
Security deposits are to be couriered to:
BC Oil and Gas Commission
#300, 398 Harbour Rd
Victoria, BC V9A 0B7
Security deposits will be accepted as a certified company cheque, or an irrevocable letter of credit, or electronic/wire transfer, from a recognized Canadian financial institution. Please note, letters of guarantees, safekeeping agreements, performance bonds, and personal cheques, will not be accepted.
Security will be returned for one of two reasons.
- The Commission will consider, upon request by an operator, the return of a security deposit when a non security-adjusted LMR greater than 1.0 has been maintained for the most recent six or more consecutive months.
- Security will be automatically returned when an operator no longer holds any permits in BC.
No, interest will not be paid. Only the amount that was held as security will be returned. This policy was rolled over from the Ministry of Finance administration.
No, access to ePASS and ePASS requirements have not changed.
You will need access to KERMIT to perform the following fuctions as of July 23, 2007:
- Submit Pipeline and Facility Applications (New, Revisions, Amendments and Field Changes)
- Submit Pipeline and Facility Construction Starts, Pressure Tests, Leave-To-Open's or As-builts.
- Submit Pipeline and Facility Notices of Intent
- Respond to all inspection deficiencies and submit suspended well inspections
- Submit Winter Stream Crossings
- Search Pipeline Projects and Facility Sites
- Manage user account security
As per Information Letter OGC 017-13 Electronic Submission Process for Pipelines and Facilities, all Pipelines and Facility Applications and Engineering Notices (eg Construction Starts, Pressure Tests, Notice of Intents etc) will require mandatory digital submission effective Monday July 23, 2007
KERMIT (Knowledge, Enterprise, Resource, Management, Information, and Technology) is the BC Oil and Gas Commissions new database application that will provide industry with an electronic submission process for pipelines and facilities.
"Section 76 (1) of OGAA says that carrying out a prescribed activity cannot take place without either the agreement of the pipeline owner or an order from the Commission. Specifically 76 (1) (c) notes that the agreement must be in writing and may be limited to “the construction or the carrying out of an activity....” In the event a party’s efforts to receive written agreement from the pipeline permit holder have failed, the party may apply to the Commission, explaining the situation and requesting an order. The party should provide detailed information with respect to the scope of the project, the perceived impact on the buried pipeline, and the attempts made to secure agreement from the pipeline permit holder. The Commission will then review the information and make a decision on whether or not to issue an order. "
The Pipeline and Liquefied Natural Gas Facility Regulationn, Section 6 (3) (b) states that notice must be given at least 5 days before beginning the work. The C&N effort should have identified the proposed activity and the 5 day period simply gives the recipient adequate notice that the activity for which they were previously consulted / notified, is about to begin. The onus is on the permit holder to assess information shared during C&N and adjust notice accordingly if additional time is required.
If the line is crossing lease boundaries by going from one lease to the next, it is a pipeline and must be applied for as a pipeline application.
The reportable spill amounts are found in the Environmental Management Act: Spill Reporting Guidelines. Spills are to be reported promptly; there is no specific requirement under the new regulations to submit a written report within 14 days; however, a post incident report may be requested by the Commission.
Water is used for various stages of unconventional gas development. It is used during geophysical exploration, for washing equipment, to freeze winter ice roads, for dust control, for drilling wells, as part of the hydraulic fracturing injection process and for hydrostatic testing of pipelines.
During the hydraulic fracturing stage of unconventional gas development, water is mixed with sand and chemicals and pumped down the wellbore. Fractures are then created in the target formation, allowing natural gas to flow up the wellbore.
The BC Oil and Gas Commission (Commission) has delegated authority to issue short-term water use permits under Section 8 of the Water Act. The Commission looks at a number of key points when reviewing water applications, such as runoff levels in rivers, other users and ecological values of the area. Community and ecological needs must be able to be sustained before a permit is issued and conditions may be attached to the permit. The Commission is a proactive regulator with the authority to intervene when necessary.
In most river basins, the total approved short-term water use is a fraction of the mean annual runoff. In 2012, 3.77 million m3 of water was reported as used. The water reported as used was 18.5 per cent of the total approved for use in 2012.
The volume of water used per well ranges from 10,000 to 70,000 m3 depending on the targeted formation. For the majority of basins, approved water use corresponds to less than 0.2 per cent of mean annual runoff. Actual water use as reported by the approval holders in individual basins is a small fraction of the approved water use, and was less than 0.075 per cent of mean annual runoff in all river basins between January and December 2012. Basins with the largest total approved water volumes as a percentage of mean annual runoff are listed in the Annual Report on Water Use in Oil and Gas Activities.
Provincial laws outline how the oil and gas industry must ensure water resources are protected during drilling and production operations. A number of measures are required to protect the water supply such as setbacks to maintain distance between water wells and drilling operations. Pressure-tested steel casings are cemented in place to prevent hydraulic fracturing fluids from migrating into freshwater aquifers, and the integrity of the casing can be evaluated to ensure it is maintaining an impermeable barrier. There has never been an instance of groundwater contamination due to hydraulic fracturing in British Columbia.
The water table is in most cases thousands of metres above unconventional gas target zones. Potable water is found between 18 and 150 metres down while unconventional gas target zones are typically at a depth of 2,000 to 3,200 metres.
When the well is no longer being used it is plugged with dense impermeable cement. The casing is cut off below ground and the well is capped.
Provincial laws ensure produced water never comes into contact with the environment. Currently, about 40 per cent of produced water is reused in hydraulic fracturing operations. Produced water is disposed of in deep injection wells or stored temporarily, both which are subject to strict regulations.
To ensure river and lake levels are conserved for community water supplies and fish and aquatic resources are not impacted, the Commission can and does issue suspensions of short-term water use by the oil and gas industry during drought conditions.
Currently, 65 per cent of water used for oil and gas activities comes from surface water such as lakes and rivers. The remaining 35 per cent comes from recycled water such as flowback fluids from operations or deep groundwater aquifers located more than 800m below the surface. Some water comes from shallow groundwater aquifers between 0-200m underground.
There is an abundance of water in northeast B.C. but it needs to be managed carefully, for example by halting industry water withdrawals during periods of seasonal low flow and drought as the Commission did in both 2010 and 2012. The Commission has also launched hydrology modelling for Northeast B.C. and created a tool that gives water license and permit decision-makers access to stream flow data, water approval data and recognizes water availability for every river or lake in Northeast B.C.
The Commission publishes an annual water report and quarterly water data. The latest quartlerly water use summary can be found here. The 2012 Annual Report on Water Use in Oil and Gas Activities can be found here.
For each basin, the mean annual discharge and runoff are listed. A list of current Section 8 permits is also available on www.bcogc.ca and is updated daily.
The Northeast Water Tool provides information for decision makers on current stream flow data and other water approvals. http://www.bcogc.ca/northeast-water-tool-newt
If you have further questions about water use for oil and gas activities in B.C. or the Commission in general, please email email@example.com.
Section 5 of the Drilling and Production Regulation addresses the positioning of wells.
General guidance on equipment spacing is included on pg 38 of the Well Completion, Maintenance and Abandonment Manual. It is important to note that beyond the guidance provided in the Well Completion, Maintenance and Abandonment Manual it is the responsibility of the permit holder to maintain sufficient equipment spacing under Sec. 45 and 47 of the Drilling and Production Regulation.
If the water is used for frac operations or other methods of oil and gas development and production, a permit is required. A permit is not required for potable water.
The Commission requires the cumulative facility venting rate; existing and proposed (new).
There is no specific requirement for the installation of high pressure or high level shutdown devices in vessels unless specified in a permit condition, or if these devices are used as controls to satisfy requirements of particular sections in the Drilling & Production Regulation such as, but not limited to, Section 39, Safety & Pollution Prevention, Section 45(3), Fire Precautions, Section 50(1), Prevention of Losses. These devices are typically installed as a best practice to ensure measurement integrity and for over pressure protection purposes.
Yes, a permit application for tower with a scada device would be either a new facility permit or a permit amendment, dependent on if there is already permitted facility equipment on the site.
Yes, estimation of small flare / vent sources is acceptable. Refer to section 11 of the Flaring and Venting Guideline for more information.
No, flaring activities are not included in the consultation/notification requirement. Consultation and Notification is restricted to the applications for activities described in the C&N regulation, which does not include flaring notification. Resident notification requirements prior to flaring are specified in well permits, and is required 24 hours prior to the start of flaring.
Guidelines for abandonments during drilling operations are found in the Drilling Guideline. Guidelines for cased-well abandonments are found in the Completions Guideline. Cased well abandonments conducted in accordance with ERCB Directive 20 meet the intent of the regulatory requirements for well abandonments in B.C. A cement plug at surface is not required.