Spill Prevention and Response

Risk of a Blow-out / Blowout Preventers (BOPs)

COMMENT: BP Canada is underestimating the probability of a blow-out event. It has been pointed out that the Deepwater Horizon incident in the Gulf of Mexico in 2010 was caused by a faulty BOP, so they are not a reliable tool to stop an oil spill. If it failed in the past, it is naïve to think it won’t happen again.

FACT:  BP Canada’s Environmental Impact Statement, prepared by Stantec acting as their consultant, states that historical data indicates that the probability of a blow-out incident is extremely low. It is estimated that for wells with a subsea BOP installed, including shear rams and following the two barrier principle, the frequency of a blowout incident is 3.1 x 10-4 (0.00031, or 0.031%) per exploration well drilled (OGP 2010 and DNV 2011). This probability estimate is based on data from the Gulf of Mexico, United Kingdom and Norway between 1980 and 2004. These data are relevant to a period prior to the implementation of additional controls and mitigation measures that are in place for the exploration well being drilled by BP Canada, including:

  • An independent well examiner review of the well design;
  • Additional shear rams on the BOP – BP Canada has three shear rams on the BOP. In addition, there are two variable pipe rams.
  • Third-party verification of BOP testing and maintenance, including a 5 year re-certification of the equipment;
  • The verification of shearing capability at maximum anticipated pressure, to ensure effective sealing of a well;
  • The requirement to have a dedicated emergency hydraulic power source within the BOP, as well as auxiliary hydraulic power available from a remote operated vehicle;
  • The requirement to deploy a remote operated vehicle at the time the BOP is installed, to conduct functional testing and verification;
  • Regular system and pressure testing of BOP;
  • Enhanced training and competency assessment for individuals and crews with accountability for well control and other well operations;
  • Onshore remote real-time monitoring by drilling experts to oversee and support well operations;
  • Enhanced contingency and spill response plans;
  • Net environmental benefit analysis (to support the development of appropriate spill response strategies); and,
  • Enhanced regulatory oversight by CNSOPB staff during drilling operations.

You can learn more about some of these on our website here.

Capping Stacks

COMMENT: A capping stack should be located in Nova Scotia, not in Norway. 

FACT: Capping stacks are strategically located globally to enable the efficient deployment to the many countries who have offshore drilling taking place at any given time.

It's important to understand that the primary ‘capping stack’ is in essence the BOP that is located on the well-head at all times.  A capping stack may be required in the unlikely event that crude oil or natural gas flows uncontrollably from an oil or gas reservoir that has been penetrated during a drilling program. An uncontrolled flow occurs when the well control techniques are not able to control the pressure of the surge from a well and, ultimately, the BOP fails to close and seal in the well.

If other subsequent well containment activities (e.g. the launching of a ROV to manually activate the BOP) fail to bring the situation under control, then a capping stack would need to be deployed.  An operator would initiate the mobilization of a capping stack immediately upon encountering a loss of well control event. At the same time, necessary preparatory work on the seafloor, such as debris removal and making the well site location safe for the deployment of the capping stack, would be initiated.

In order to deploy the capping stack mobilized from Stavanger, Norway, a heavy lift vessel is required. Currently and typically, there are no such heavy lift vessels located in Atlantic Canada or the eastern seaboard of the United States. Heavy lift vessels are available in close proximity to Stavanger, Norway. Should a capping stack ever need to be mobilized, the heavy lift vessel would collect the stack and sail directly to the well location.

Depending upon the amount of debris that needs to be cleared, and other work required to ensure safety, such preparatory work may still be ongoing when the capping stack arrives at the wellsite.

In the Environmental Impact Statement submitted by BP Canada to the Canadian Environmental Assessment Agency as part of the Environmental Assessment process, it was identified that the capping stack would be mobilized from Stavanger, Norway. The CNSOPB in its subsequent reviews identified that the availability of a heavy lift vessel to transport and deploy the capping stack as being critical in minimizing the timeline. The CNSOPB has therefore required BP Canada to monitor on a daily basis (when drilling in target hydrocarbon zones) the proximity of heavy lift vessel(s) that could transport, and then deploy, the capping stack from its storage location. BP Canada must confirm that, during the times they are drilling in target hydrocarbon zones, there is at least one heavy lift vessel that could be dockside and ready for loading by the time the capping stack could be mobilized, tested and moved to the dock from the warehouse location in which it is stored. By implementation of this requirement, the resultant optimized schedule indicates that a capping stack could arrive at the wellsite, should it be required, within 12 to 13 days.
 

COMMENT: Because a capping stack is required to stop a blowout, it should be available to be deployed within hours.

FACT: In the event of a blowout, a capping stack would not actually be deployed within hours, even if it was located at the well site location. Other well containment strategies would first be activated, such as the launching of a remote operated vehicle (ROV) to the ocean floor to latch on and manually activate the BOP to seal the well. Additionally, debris may have to be removed, and the well site location would need to be made safe for the deployment of the capping stack. Depending upon the scenario, this preparatory work could take considerable time to complete. 
 

COMMENT: There are concerns around the length of time it would take to transport a capping stack across the ocean from the North Sea to BP Canada’s drilling site, especially in the wintertime.

FACT: The current well being drilled by BP Canada is scheduled to be completed during the summer of 2018.  No additional wells have been proposed as of this time. The company (Offshore Spill Response Limited) which owns the capping stacks that would be relied upon by BP Canada, will shortly (approximately mid-June 2018) have available an Antonov AN-124 compatible transport frame that would enable its capping stacks to be transported in one single unit by air.  This potentially could reduce delivery time of a capping stack to the well site location, especially during the winter months.
 

COMMENT: Other countries require a capping stack to be located at the drill site, so Nova Scotia should be no different.

FACT: Global requirements are quite similar in nature, that being that operators must demonstrate that they have access, and the ability, to deploy a capping stack, along with other necessary supporting equipment, and that this can be accomplished within a reasonable amount of time. Global requirements do not typically dictate a specific storage location or proximity to a well site.  Having said this, regulations in place for drilling in the U.S. Arctic do result in a necessity to have a capping stack available locally given the remoteness of the region. Transportation times from current capping stack storage locations are long and the drilling season is short, meaning that there is a risk that a capping stack may not arrive before ice could move back in at the end of the drilling season. This would make the capping of a well much more difficult to complete, or may delay the deployment of a capping stack by several months until the ice clears.

Training and Competencies

COMMENT: One of the major variables in any disaster is human error - more questions need to be asked about the people who will be working on the rig and their qualifications.

FACT: As the regulator of offshore oil and gas activities, we agree with this statement. Training and competency requirements have significantly increased since the Deepwater Horizon incident in the Gulf of Mexico in 2010, and confirmation of the adequacy of operator training and competency assurance programs are a key part of pre-authorization reviews and audits conducted by CNSOPB staff.

Operators are also required to have in place a well verification scheme to assure that exploration wells are designed, constructed, and maintained adequately so that there can be no unplanned escape of fluids from the well. Such reviews must be conducted by a well examiner that is independent of the team who designed the well. For the BP Canada well, it is further required that data that is continuously collected from the well during the execution of the drilling program be sent to an onshore base in real-time. This data is then monitored by qualified drilling experts 24 hours a day, seven days a week, to ensure that drilling personnel on site do not overlook something that could lead to a loss of well control. The onshore personnel are able to phone to the drilling installation and speak directly with the drilling personnel to discuss what they are observing and actions that may need to be taken. These mechanisms provide additional layers of oversight that previously didn’t exist.

Dispersants

COMMENT: In the case of a major oil spill, BP Canada has already been approved to use dispersants.

FACT: In terms of the use of spill treating agents (which includes dispersants), it is important to understand that the granting of an authorization for a drilling program (and any related approvals to drill a well), does not grant approval for the use of a dispersant in responding to an oil spill.

Even though dispersants are referenced as a tool in BP Canada’s spill response plan, it does not mean they can automatically use them. If a major incident were to occur, and an operator was to consider the use of a dispersant, legislation requires that a specific request for approval be made at that time to the CNSOPB’s Chief Conservation Officer (CCO).  Such a request would have to be accompanied by an incident-specific net environmental benefit analysis. The use of dispersants would only be considered in cases where a net environmental benefit analysis concludes that it is better for the environment to do so.

The CCO would first consult with experts of Environment and Climate Change Canada’s National Environmental Emergencies Centre’s Science Table, which brings together relevant experts in the field of environmental protection in all levels of government, scientists, other stakeholders, and the response community. Additionally, the CCO is obligated by legislation to consult with the federal Minister of Natural Resources Canada and provincial Minister of Energy before granting approval to use a dispersant.   

Spill treating agents that may be used in Canadian waters were approved by regulation in 2016, and include Corexit 9500 (dispersant) and Corexit 9580 (surface-washing agent).

It’s imperative that all oil and gas activity taking place in our offshore is completed in a safe and environmentally responsible manner. Out team of experts have dedicated much time and effort to ensure that a strong regulatory framework and rigorous monitoring and enforcement programs are in place. While prevention is the ultimate goal, we ensure that operators must be ready to respond to a spill.