Proceedings of the Standing Senate Committee on
Energy, the Environment and Natural Resources
Issue 9 - Evidence - June 17, 2010
OTTAWA, Thursday, June 17, 2010
The Standing Senate Committee on Energy, the Environment and Natural Resources met this day at 8:11 a.m. to study the current state and future of Canada's energy sector (including alternative energy), (topic: Canadian offshore oil/gas exploration and drilling: the current status of operations/applicable regulatory rules and regulations).
Senator W. David Angus (Chair) in the chair.
[English]
The Chair: Good morning. I welcome everyone to this meeting of the Standing Senate Committee on Energy, the Environment and Natural Resources. We are continuing our in-depth study on the energy sector in Canada, with a view to developing a policy framework going forward.
We have had a slight deviation since April 20 in view of the tragic events in the Gulf of Mexico with the drilling ship Deepwater Horizon. We have held a series of hearings to focus on the Canadian offshore oil and gas exploration industry with a view to establishing the facts for Canadians who seem a little concerned, if not panicked, by events in the U.S. A public opinion poll showed half of Canadians favoured a complete shutdown of our offshore industry, which is part of our Canadian industrial fabric.
Knowing there was no drilling happening on the West Coast or the Arctic, we thought it was important to lay out the facts. We have been studying this issue since early June. We are delighted today to have representatives from EnCana and Husky. EnCana represents gas exploration off Nova Scotia and Husky represents the oil industry. Our witnesses will explain their involvement.
I am Senator David Angus, chair of the committee, from Quebec. Also present today are: Lynn Gordon, our able clerk; Sam Banks, our researcher from the Library of Parliament; Senator Robert Peterson from Saskatchewan; Senator Judith Seidman from Quebec; Senator Daniel Lang from the Yukon; Senator Richard Neufeld from British Columbia; Senator Fred Dickson from Nova Scotia; Senator Linda Frum from Ontario; and Senator Bert Brown from Alberta. We have a few other members of the committee that have competing games this morning. Unfortunately, as we wind down this session of Parliament, we have duplicate sittings of other committees. I will introduce other colleagues as they come and go.
Honourable senators, I want to introduce you to our guests. Paul McCloskey is Vice-President of East Coast Operations for Husky Oil Operations Limited, which I believe is part of the Husky Energy group, a great company with antecedents in Hong Kong and K.S. Li. He is a great friend of mine, and it is always nice to see his able people coming to help us perform our public duty in Ottawa. Mr. McCloskey was appointed to his position in 2009. He has more than 30 years of knowledge and experience in the upstream petroleum sector. He holds a Bachelor of Science in chemical engineering from Birmingham University and is a graduate of Duke University's — the Blue Devils — Advanced Management Program. He lives in St. John's, Newfoundland and Labrador.
Accompanying Mr. McCloskey is Al Pate, General Manager of Exploration and Production Services. He was appointed to this position in 2007. Mr. Pate also brings 30 years of knowledge and experience, particularly in the drilling and completion sector. Mr. Pate holds a Bachelor of Science in mechanical engineering from University of British Columbia and lives in Calgary.
Honourable senators, we originally thought we would have a panel of the Husky and EnCana witnesses together. However, the gas and oil operations are obviously different. The witnesses suggested, and we agreed, that it is more appropriate to separate the two. We hope this separation will help us see the difference between the types of operations involved between what Husky and EnCana do.
Husky will begin. I believe Mr. McCloskey has an opening statement. We are delighted to have you with us, and we are delighted to hear your wisdom.
Paul McCloskey, Vice-President, East Coast Operations, Husky Oil Operations Limited: Thank you, chair. On behalf of Husky Energy, I want to thank you for the opportunity to appear before the committee.
Our condolences go out to the families, friends and industry colleagues of those lost aboard the Deepwater Horizon. Our thoughts also go out to the communities in the Gulf Coast whose lives are so greatly impacted. We are monitoring events in the Gulf closely, and the lessons we learn will be incorporated into our operations.
Husky has been active on Canada's East Coast for 27 years. In that time, we have safely and successfully drilled more than 60 development, exploration and appraisal wells. Our primary area of operation is a region known as the Jeanne d'Arc Basin. It is located approximately 350 kilometres east of St. John's. This region is home to the White Rose Field operated by Husky. We distributed a map to show the position of our operations off the East Coast of Canada. We will be happy to come back to that map.
The Chair: All senators have it appended to Mr. McCloskey's opening statement .
Mr. McCloskey: For this area, the primary regulator is the Canada-Newfoundland and Labrador Offshore Petroleum Board, C-NLOPB.
Relative to the area of the Gulf of Mexico in which the Deepwater Horizon was operating, the Jeanne d'Arc Basin is in much shallower water. It is less than 200 metres. Our waters are also much colder.
Safety and responsible environmental stewardship are core values at Husky, and underpin the way we operate. These values are embedded in our operational management system. The Husky Operational Integrity Management System, HOIMS, incorporates world-class practices in regard to health, safety and environmental protection. It takes a systematic approach to anticipating, identifying and mitigating hazards.
As prudent operators in the offshore, we must be ready to respond to a spill, large or small. However, our primary focus is on prevention. To this end, Husky and its partners put considerable resources into developing safe and environmentally responsible practices. Well-control and spill-prevention measures are incorporated throughout our offshore drilling operations. We not only meet, but strive to exceed, government regulations.
While we are confident in the safety and integrity of our operations, we decided to conduct a review of our well- control systems following the incident in the Gulf of Mexico. This review looked at a number of things, including policies, procedures, training, equipment and contingency plans. This review confirmed that our existing well-control practices meet or exceed regulatory requirements. However, we are now going a step further and commissioning third- party reviews of our drilling operations to ensure we are best in class.
Likewise, once the findings of the Gulf of Mexico investigation are released, they will be reviewed and any applicable learnings will be implemented into our operations.
There are many review stages in the well-planning and execution process. These stages are undertaken by both our onshore and offshore teams. Each well design is submitted to the regulator, which issues authority to drill a well. This authority is effectively our licence to operate.
Our facilities, including well control equipment, undergo rigorous third-party reviews and assessments to ensure we meet the highest standards.
Drilling rigs selected for use offshore Newfoundland and Labrador have been certified to operate in our challenging environmental conditions. Rigs must hold a valid certificate of fitness, issued by an independent certifying authority, indicating that the rig meets all requirements set forth by the regulations. The rig must also receive a letter of compliance from Transport Canada. During their operating lives, the rigs undergo special periodic surveys, during which time critical systems, including well-control systems, are overhauled and re-certified.
Emergency drills and exercises are held regularly, and are designed to keep crews alert to the potential of well- control events and to reinforce operational safety. Depending on the nature of the drill, it could be run weekly, monthly or during each trip into the wellbore.
Husky also uses the latest technology and procedures in early detection. These procedures include dual redundant pit level sensors and flow-line sensors, logging-while-drilling tools and real-time data transmission to onshore technical teams. Advanced modeling software allows us to fully evaluate pressures within the wellbore, and flow-checks are completed frequently.
Our East Coast drilling and completions team has almost 400 years of offshore experience, 275 of those years directly related to Canada's East Coast. In addition to meeting the regulatory requirements for well-control training, all of Husky's drilling and completion engineers are trained and certified in well-control methods. All have spent time in the field becoming familiar with the equipment and the practical implications of rig operations.
We also have an in-house, well-control subject matter expert. This individual is a certified, internationally recognized well-control trainer.
While prevention and monitoring are key primary control tools, secondary well control equipment and methods include use of blowout preventers, BOPs, and other procedures designed to shut in wells. Again, chair, attached to our speaking notes, there is a schematic of a typical BOP system for the offshore. I will be happy to refer to that during questioning. Like the rigs themselves, the well-control equipment is certificated by an independent, internationally recognized certifying body approved by the regulator.
Because we are operating in water depths of less than 200 metres, the two drilling rigs currently in use by Husky have pilot-operated BOP hydraulic control systems. These systems have several layers of redundancy, including multiple control stations, redundant interconnecting hydraulic lines and redundancy and flexibility within the BOP configuration. The driller has full authority to operate the BOP to maintain safe operations. In fact, all personnel are authorized to close the well by activating the BOP in an emergency.
The Chair: Sir, you have mentioned the key word, personnel. I was quickly leafing through your notes. I do not think you are dealing with the complement of the personnel on board the rig — or maybe you are in your report. However, if not, can you give us a few words on how many there are and the safety regime for these folks?
Mr. McCloskey: Certainly; a typical rig complement varies, depending on the rig, between maybe 90 and 120 people.
The Chair: Is that regardless of whether it is a semi-submersible or a platform rig?
Mr. McCloskey: To clarify, for semi-submersible, it is between 90 and 120 people. Depending on the nature of the operations, there is typically a core crew, which will be on rotation. They work typically several weeks offshore and then several weeks on break, and they live on the facility. Then we have specialists who come in for particular elements of the well. They might be completion engineers or logging engineers, and they arrive and stay only for the duration of the task they are assigned to.
Husky currently operates only semi-submersible rigs. In earlier testimony, you will have heard references to the Hibernia facility. That platform has two platform rigs. I do not know the complement of the staffing on board.
Regarding the safety regime, I referred to the HOIMS, the safety management system. That is the overarching management system we apply, and it is expected to be applied by all our contractors and staff. We can touch upon that system later, if you wish.
The functions of the blowout preventers can be controlled from three different surface locations on board the rig. In addition, the BOP can be closed using a remote operated vehicle, ROV. Each rig has two independent remote operated vehicle systems. Husky also maintains a light intervention vessel, which is equipped with a full suite of ROV equipment.
I emphasize that Husky believes prevention is the best line of defence. However, we are prepared to respond to an offshore spill, should one occur. Husky has a three-tiered oil-spill response program, and each tier provides for access to equipment and resources appropriate to the magnitude of the spill. These plans are supported by training and regular drills involving Husky personnel, contractors, other operators, regulators and other key stakeholders.
In seeking regulatory permission to conduct offshore drilling and development activities at the White Rose field, significant effort went into assessing safety and environmental risks. Formal environmental assessments and studies were undertaken, which included spill path modeling.
Husky looked at a number of spill scenarios. In all cases, the models indicated that oil should head out into the open ocean. Chair, if you speak to anyone in Newfoundland and Labrador, they will be familiar with the Labrador Current, which comes down the coast of Labrador from the north and then heads out into the Atlantic.
Our spill models are updated on an ongoing basis as new oceanographic data is gathered from the White Rose field. We have a robust and comprehensive spill prevention response plan in place.
That said, the events in the Gulf of Mexico are a sobering reminder that we must remain vigilant. We will monitor the events in the Gulf, along with our industry peers, to determine what went wrong and how it can be prevented from happening in the future. We will also study the response efforts to continuously improve our own plans. Husky and the entire industry will learn from this event.
Mr. Pate and I will be happy to answer any of your questions.
The Chair: Thank you very much, sir. I will go to my list of questioners in a moment, but I want to exercise my chair's prerogative today in the absence of the deputy chair and sneak in a few questions of my own. A little bird told me you have been busy following our deliberations here and you have seen some of our transcripts. Did you have an opportunity to review the testimony of the Chevron people?
Mr. McCloskey: We did, chair.
The Chair: Chevron is the other oil explorer and driller that we have heard from directly. They are out a little further in the Orphan Basin, and I guess you have heard they are in a much deeper water operation. Is there anything in the presentation they made to us that you disagree with or want to add to?
That was our first direct exposure to a hands-on operator. I think it is people like you that are in that business directly that have Canadians wondering if we should be scared. Should we be concerned?
That is a general opening question. Can you address it?
Mr. McCloskey: I am happy to address that question.
The Chair: By the way, I do not know if my colleagues received the document I received yesterday — a one-and-a- half-inch document called ``The Chevron Story.'' I thought it was a further exhibit from Chevron, but on the contrary, it was from some international environmental groups that have put together this story that is a negative one. We strive not only for balance and fairness; our primary interest is the truth and what really goes on.
Mr. McCloskey: Chair, I read the testimony from Chevron. There are many echoes in that testimony that you will hear repeated today. At Husky, we will not do something unless we can do it safely, and I think you heard that many times from the Chevron folks.
I have to acknowledge that, at one point in my career I worked for Chevron. I was seconded from another company into their operations and I can testify to their safety culture.
The Chair: Maybe you were the man that did not hold the handrail going downstairs.
Mr. McCloskey: I cannot possibly comment on that. I always hold the handrail.
I think that reference to doing things safely and doing them right is the Husky ethic as well. One of the factors that persuaded me to join Husky was seeing a company that shared those values. They talked a lot about their operational precautions and that prevention is the key. Again, Husky concurs with that value. Our focus is on prevention.
Their operation, however, is different from ours. They are in significantly deeper water depths, and they are operating with a dynamically positioned drillship. We are using semi-submersibles, which are anchored, because our water depth is more modest.
Some of the operational discussions were also a little different. They referred to multiple means of functioning their blowout preventers. In our water depths because of our conditions, we use two methods of activation, hydraulic activation — which I referred to in my statement — and the use of ROVs, but that situation is driven purely by the operational setting. There is nothing in their statement I would seek to contradict.
The Chair: Throughout your presentation, you used the word ``spill.'' Of course, I have spent most of my career as a maritime lawyer, and with the word ``spill,'' we generally had the connotation of a tanker or even a dry cargo carrier having an accident from its own fuel or bunker tanks, but I have a sense that ``spill'' in your language is slightly different. We realize that the Gulf started with an explosion, which killed 11 people and injured some 28 others, and led to an escape. What should we understand by these terms?
Mr. McCloskey: I think that we are probably adding to the confusion here. The shorthand that we use for ``spill'' is any release into the environment. However, with what you have described, you have made an important distinction. There is what we term ``batch spills,'' where there are certain amounts of fluid released into the environment, and that is the end of the matter. Then there is the situation like in the Gulf of Mexico, where there is a continuous release. We refer to those as ``spills,'' although I accept that they are much different in character.
The Chair: Their spill gives the word ``gusher'' a new meaning. Even this morning we can turn on CNN and see it. It is not a trickle.
To capture a sense for the Canadian people who, as I said earlier, do not understand how much activity there is, you are in the White Rose field. How many drilling rigs do you have? Is it only one?
Mr. McCloskey: If you look at Husky's position on the East Coast, we have exploration acreage and development assets, which are where we have discovered hydrocarbons but we have not yet brought them into production, and then we have producing fields. White Rose is a producing field that Husky operates. We have recently brought on stream a second producing field called North Amethyst, which came on at the end of May.
The Chair: Is it in the same area?
Mr. McCloskey: It is in the same area, within a few kilometres from White Rose. It is a prolific area for us.
In support of development and exploration operations, we have one rig called the GSF Grand Banks, and that rig supports our development activity. It is a semi-submersible rig, it is anchored and it has been operating with Husky for some time now.
We have a second drilling unit called the Henry Goodrich under a rig share agreement with two other operators, Statoil and Suncor. We have between a third, 33 per cent, and 40 per cent of access to that rig's time while it is on contract. Typically, we use that rig for our exploration activities.
To recap, we have two drilling rigs, both semi-submersible, both anchored, one supporting development operations and one supporting exploration, plus a producing facility at the White Rose field, which is a floating production and storage and off-loading facility, and then the North Amethyst field, which is in production and is tied back into the White Rose.
Senator Lang: Thank you for appearing; we appreciate it.
I want to centre our attention on the question of regulations and the minimum that is required of a company such as yours, or any other company, so we may clarify requirements for the record here. I will refer back to the Gulf of Mexico. Of course, that is why we are here, because we are viewing that every day. What I am starting to glean from the evidence that is being provided before the hearings in Washington is that there appears to be no minimum requirement for a company when they drill. The testimony is starting to come out that the size or thickness of the pipe may not have been correct. The procedures that were required do not appear to have been enforced. There are a multitude of mistakes as we have proceeded. This comparison is simplistic, but when I build a house, I am required to use two-by-six construction. An inspector comes out and ensures that.
The question I have for you is, through the provincial and federal authority, by regulation and by law, is it required that you have a minimum standard set for the blowout preventer for the size of your pipe, and all the other aspects of your operation?
Mr. McCloskey: Each of our wells is planned separately according to its objectives. The planning starts with an environmental assessment. It then moves into the planning around the execution of the well itself. At that stage, we develop a plan of execution, which we submit to the C-NLOPB for their review. This step is required for every well. Even on a producing field where we are drilling many wells with the same objective, in each instance, we have to put forward this plan. That plan is scrutinized and reviewed. We often receive questions on the plan for clarification. As we move through that process, we finally work to a point where we can obtain an approved plan.
It is a given that our equipment must be certified and suitable for the purpose it is being applied for; that our casing strings and mud design are appropriate for the purpose for which the well is being drilled. That appropriateness is determined prior to our receiving the authority to drill. That process is clearly important to us because it establishes our authority to operate. Without that authority, we cannot drill a well.
To give you an assurance, it is not a prescriptive program that determines there must be particular casings or particular sizes because that is according to the well objective. We have specific standards to maintain, and those standards are met or exceeded in all of our operations.
Senator Lang: To clarify for the record, these are minimum guidelines not set down by regulation?
Mr. McCloskey: Recently, we have had new drilling guidelines issued from the C-NLOPB. They tend not to be prescriptive in terms of specifics, for example, casing sizes or mud weights because each of those are tailored and designed to the specific well. However, I suppose there are general operating principles that have to be met. We have to demonstrate that the casing design is appropriate for the pressure regime we are working in, and for the well depths we are drilling to. We have to bring evidence for all those specifics in submitting our well plan.
Senator Lang: Time is short, so I will move to another area of questioning.
First, if a situation occurs and we face something like what is happening in the Gulf of Mexico, you talked about your three-tiered response to deal with a spill. Have you a contingency plan for the third-tier response you will have to put in place? Has it been demonstrated physically — maybe a table-top exercise — to show what you would do?
Second, in the Gulf of Mexico, it appears no one is in charge if a disaster occurs. At the end of the day, if a spill happens — hopefully it will not — where does the buck stop when decisions are being made on an hourly basis?
Mr. McCloskey: I will answer the second question first because it goes to the heart of the matter. The buck stops here. We are absolutely clear at Husky, when we receive authority to drill, we are the operator. Being the operator carries obligations. In the highly unlikely event of a mishap, Husky has that responsibility. We are accountable. We would be the authority managing the incident.
We have an incident control centre and structure that has incident commanders trained in crisis and emergency management. They would be the authority managing the resources deployed to manage the incident. We are clear on that issue.
I think in prior testimony, the C-NLOPB described how they will work in a monitoring role. We understand they will monitor, but we will be in charge. The only instance where that may change is if they determined that our response was not effective and they wanted to replace us. I am under no doubt that Husky is accountable.
The first part of your question was about our tiered response. To date, we physically conduct drills up to a tier-2 response. We have not conducted a drill to a tier-3 level at this point, although we have additional resources we can deploy from international locations. I think you heard from the Eastern Canada Response Corporation on Tuesday that they have additional resources they can mobilize on our behalf.
The Chair: Is the Eastern Canada Response Corporation under contract with you?
Mr. McCloskey: They are under contract with us as well. They hold and maintain some of our response equipment for us. They train our teams. We meet with the ECRC on a regular basis — about every quarter — to ensure we are properly aligned and the equipment works.
To answer your question, we have not conducted a tier-3 drill.
The Chair: I think you are talking at cross purposes.
Senator Lang: I do not quite understand. You have a drill-3-tier response and a drill-2-tier response drill. Does that mean it is not a deep well?
Mr. McCloskey: Let me clarify. I apologize for the use of term ``spill.'' If a spill is relatively small in size, our tier-1 response is managed with equipment we have on site. Each of our Floating Production Storage and Offloading, FPSO, supply vessels has equipment to deploy immediately.
A tier-2 response is required if the spill is of a greater magnitude. We will mobilize equipment from onshore. We, as operator, have purchased our own equipment, including state-of-the-art Norwegian skimmers and booms. These skimmers and booms are held for us by ECRC. Other operators on the Grand Banks also have equipment that can provide mutual aid. That is the equipment we refer to in tier 2 along with the equipment that ECRC has.
The tier-3 response will be activated only if the spill is of a significant magnitude. At that point, tier 1 and tier 2 will still be deployed. We will also call upon additional resources to assist in the effort. These additional resources potentially will include mobilization of Canadian Coast Guard resources, additional ECRC resources from other places in Canada and international support. We have a contract with Oil Spill Response Limited, OSRL, which is based in Southampton in the United Kingdom. They can deploy significant resources, including a couple of Hercules aircraft to fly in additional equipment.
In terms of our response, tier 1 is immediate, tier 2 takes perhaps 14 to 16 hours and tier 3 will occur in perhaps 24 to 48 hours.
Senator Lang: I will continue in the next round chair, if there is one.
The Chair: Thank you Senator Lang. Your first question mentioned the lack of clear lines of authority and criticisms regarding the Gulf incident leading up to the $20 billion cheque.
Is Husky also involved in the Gulf of Mexico?
Mr. McCloskey: No, we are not. Husky is not operational in the United States, but we have downstream interests.
The Chair: Are you in a position to tell us the differences, if any, between the regimes in the US and Canada? We understand they are different, and one should not be too concerned about Canada.
Mr. McCloskey: There has been discussion in previous testimony about the regulatory regime in Canada. In my experience, I have worked in many international locations. Canada measures up against any environment I have ever operated in.
There are some important differences between Canada and the U.S. Certification of equipment is more rigorous in Canada. I mentioned that our rigs undergo a five-year inspection, and critical systems are reviewed. Well-control systems are re-certified every five years, including function and full-body checks. I do not believe re-certification is required in the United States. Re-certification of equipment is a layer of assurance and thoroughness that exists in the Canadian system.
The Chair: I want to introduce you to Senator Paul Massicotte from Montreal who arrived a moment ago.
Senator Frum: You mentioned that your tier-2 response will use a state-of-the-art Norwegian skimmer and that you will have responsibility for the cleanup. The technology you will use is also at your discretion. If you or another company does not have the state-of-the-art skimmer, they can use a retrograde skimmer.
Will there be no intervention in the quality of equipment used?
Mr. McCloskey: Husky takes its responsibility in this regard seriously. We looked for state-of-the-art equipment when we purchased or secured equipment under agreements with other operators in an emergency for our use and use by those other operators.
We upgraded a couple of years ago. We also worked on the development of an earlier system — the single-vessel side-sweep system — which was a vane kind of capture. We felt this upgrade of our response equipment was needed because we need to be cognizant of the environment in which we operate. Conditions in the North Atlantic are often severe. One thing that attracted us to the Norwegian system is its ability to operate under high sea states, because we might encounter high seas during our operations.
We were not directed to acquire this equipment. We did it because we felt it was the best technology for application in our environment.
Senator Frum: Again, it speaks to Senator Lang's point that there is no regulation that obliges you to have a certain standard of cleanup equipment on hand.
Mr. McCloskey: I am not aware of there being a standard.
Senator Dickson: Have you had a spill in the Newfoundland area since you have been operating there? If so, what was the size and how was it dealt with?
Mr. McCloskey: In our 27 years, we have had no spill related to a well control incident. The largest spill we have experienced was from our production operations. We were conducting cargo transfer between our floating production system and a tanker, and we had a failure in that system. We had a release of 30 barrels of crude, which we addressed with our offshore equipment. That is the largest spill we have suffered of a hydrocarbon product.
Senator Dickson: Can you explain briefly your relationship with the Eastern Canada Response Corporation? Are they a contractor to you?
Mr. McCloskey: They are a contractor to us. We have them available to support our operations as a response agency. They hold equipment that Husky has purchased; they help maintain that equipment and store it for us. They work with our crews in terms of training and the deployment of that equipment and they also support us in drills.
Every year on the Grand Banks, there is a combined operator drill called Operation Synergy. The leadership of that drill rotates between the operators; it was Husky's responsibility last year. This year, I think Exxon Mobil and Hibernia Development Corporation will lead that exercise.
They are a contractor to us, but they are a specialist contractor for those specialist services.
Senator Dickson: The manager of that corporation appeared before us yesterday. I understand, in the process, that Eastern Canada Response Corporation does not see the safety plan prior to there being an actual spill. There is no review; there is no cooperation. I found that rather strange.
Mr. McCloskey: I read that in testimony. I have tried to find some clarification on that process and I am afraid I cannot shed any light today. However, that is a matter I will be happy to come back to you with and clarify at a later date.
Senator Dickson: Do you think it would be good practice for them to see the plan before a spill?
Mr. McCloskey: I have to be cautious here. We have an ongoing working relationship with ECRC, and we meet with them on a quarterly basis. I would have anticipated that there would be some discussion around our safety plans, but I cannot confirm that today. I would like to revert on that, if that is possible.
The Chair: It is important, and we are comfortable with you sending in materials to our clerk for us to take cognizance of and incorporate. One thing that raised our eyebrows was that bald statement that ECRC does not see the plan; whereas the plan is given great importance in terms of reassuring the public that before you are granted the licence and begin drilling, this plan has been approved and reviewed. The Eastern Canada Response Corporation is an integral part of that plan, and it blows our minds to think they are an integral part of a plan they do not see. We are hoping that was a misunderstanding perhaps, but we need to clarify.
Mr. McCloskey: I agree it needs clarification. I will say, in terms of our drill, for Operation Synergy, we run scenarios we can anticipate in terms of our safety plan. I need to bottom that out, but I was surprised to hear that.
Senator Brown: I went through your presentation, and on page 6, you mentioned several times blowout preventers, multiple control procedures and pilot-operated hydraulic control systems for BOPs.
I have been beating on this drum for the last few weeks. Why can we not have more than one blowout preventer? I was looking at your diagram on your last page; why can they not be stacked on top of each other or even stacked horizontally?
Then, regarding the redundancy you talk about in terms of taking the controls, it says anyone that operates the rig has the right to activate the blowout preventers. My understanding is that the blowout preventer blew up in the Gulf. Would it not be better to have multiple ones, and have them configured in such a way that you shut down the last one first and then work your way down to the next one and so on if you have an accident from a blowout preventer?
I know they must be expensive; I imagine they are probably $1 million apiece or more. However, at this kind of level and with this kind of danger we have seen now with what has happened with BP, it seems like that redundancy is important.
I see the redundancy in everything you mention. You are controlling your ability to use different ways of shutting down the blowout preventer. However, if the blowout preventer blows up, then the redundancy is useless. It seems to me that if you had more than one blowout preventer, you would be able to control pretty much anything possible that might occur.
Mr. McCloskey: First, in terms of what happened in the Gulf of Mexico, I do not think today we know whether the BOP blew up or what the cause of the incident was. What you are referring to — the need for many different methods of shut-in — is encapsulated in the design of the blowout preventers.
Perhaps Mr. Pate can walk through that diagram and describe how the BOP stack works, because it may give you some reassurance. It is not a single unit, but a combination of units, each with a slightly different purpose that can be called upon to effect a shut-in.
Senator Brown: I understand there are different ways of shutting off the valve in a blowout preventer, but apparently nothing worked in the Gulf. That is why I say, why not more than one blowout preventer?
The Chair: We will hear from Mr. Pate. I think it is a good idea generally, and our researchers are anxious to know the size of that BOP. Is it 300 metres?
Al Pate, General Manager, Exploration and Production Services, Husky Oil Operations Limited: It is 120 metres, chair.
The Chair: Let us know the size as you go through your description of the stack.
Mr. Pate: I will walk through the BOP configurations. We will start with the schematic of the rig. It is a floating semi- submersible rig that is anchored in place. Extending from the rig to the BOP is the riser, which is a piece of pipe that is 21 inches in diameter — a very thick wall. It is designed to be a conduit for drilling fluid back to the surface of the rig so we can circulate the well.
It connects to what we call the lower marine riser package. If you look on the right-hand side of the diagram, there is the riser and a flex joint. As you can appreciate, the rig moves around on surface, so the riser and the BOP need to have some flexibility. That is what the flex joint does.
Below that, there is an annular preventer, which is essentially a rubber doughnut. They apply hydraulic pressure to it and it squeezes around drill pipe, casing, wire line or anything else in a wellbore, and it can seal off an open hole. If they have to shut the well down, they can do it with that top annular.
Below that, there is what they call a connector. If they need to, it allows them to disconnect the lower marine riser package, which is that upper portion, from the rest of the BOP stacks. In the event they had to perform an emergency disconnect because of ice issues or whatever, they can actually suspend the well properly, close the BOPs, disconnect the riser and the lower marine riser package and take the rig away. That is important in our operation.
Below that, there are a series of other preventers. There is another annular preventer, another rubber doughnut. As you note, it provides some dual redundancy there. That is the second rubber doughnut. Below that, there is a set of sheer rams, which are designed to cut the drill pipe in the event of an emergency. Below that, there are three sets of pipe rams. The pipe rams are essentially semi-circular pieces of steel with a rubber seal that again can close around the drill pipe or other types of pipe in the wellbore. There is another set of three redundant rams.
When you talk about stacking BOPs together, the essence of all of this is we essentially have that. Each one of these rams is designed to seal around certain things, and there is redundancy in all areas, with the exception of the sheer blind rams where, in this case, we have only one. Again, we can close the annular and it will also close off an open hole.
There is redundancy throughout this BOP. To give you a bit of a concept of what this thing looks like, this piece of apparatus, the BOP system, is over 200 tonnes of material. It has a bore of 18 and three quarter inches, but the overall dimensions are huge. It is a massive piece of equipment, and it is rigidly set into the wellhead on the seabed. It is a stiff, solid piece of material. It is designed to take a lot of load and stress. In terms of height, it is 40 feet to 50 feet. The BOP is a tremendously large piece of equipment.
When we talk about dual redundant systems, we have separate hydraulic systems that can be switched from one to the other to control any of these rams or any of the annular functions. There are lots of ways to close the stack.
The answer to your question is, what we have in place is, in essence, a number of BOP stacks, if you will.
The Chair: The dimensions are 40 feet to 50 feet in height and 200 tonnes of weight?
Mr. Pate: Yes; Eighteen and three quarter inch inside diameter and, depending, it is 15 feet wide. I might be a bit out.
With respect to the pressure rating on this equipment, the annular preventers are good for 10,000 pounds per square inch, psi, and the rams are all good for 15,000 psi. These are solid and substantial pieces of equipment, and they are designed to close the well in.
Senator Brown: With what happened in the Gulf, then, maybe the pictures they showed were not accurate.
The Chair: We do not know what happened in the Gulf. Let us not go into that.
Senator Brown: I understand that, but what I am saying is from the pictures that were shown, as taken by a submarine that went down, there was a piece of pipe that was bent over at right angles. I did not see anything else from those images.
Mr. Pate: That piece of pipe you were looking at is the riser on top of the BOP stack. Again, I cannot comment on exactly what happened. When I look at our systems, I am confident that we have the ability to close our wells, if needed.
The Chair: Thank you. We are tight for time. I am glad you covered the BOP. I wanted to introduce Senator Nancy Greene Raine who has arrived. All the other senators have been introduced.
Senator Peterson: Thank you for your presentation. No matter how careful we are, accidents can and do happen. President Obama has stated with respect to the Gulf incident that there will be no financial cap. Do you think this is reasonable? How will that situation impact your risk management metrics?
Mr. McCloskey: For us, there is effectively no change. Under current regulations, if we are at fault, there is no cap.
Senator Peterson: You operate under the same regime?
Mr. McCloskey: We already operate under those conditions.
Senator Peterson: You are drilling in shallower water, but if you had to, how long would it take you to drill a relief well?
Mr. McCloskey: It is difficult to generalize because it depends on the well being drilled and the depth it is drilled. I would say, typically for the wells we drill, of the order of 30 days to 45 days, plus the time it takes to mobilize a rig to location. Perhaps it would take less than 60 days in total.
Senator Frum: Thank you for the excellent presentation. You stressed at least twice in your presentation about the shallower depths at which you are drilling. The chair asked you about Chevron's testimony. One thing they said in response to a question I asked was that there was nothing magical about the 5,000 foot depth. I was wondering if you can comment on that statement. Clearly, for you to stress the shallow depths you are drilling at, you are implying there is a difference.
Mr. McCloskey: First, there is nothing magic about a number. I agree with that.
What distinguishes our operations in shallow water is that they are at a depth where the hydraulic systems in terms of activation of BOPs work extremely well. Effectively, the signal does not have to travel very far.
In deeper water, companies have looked at different methods of activation. There was probably reference to an acoustic system or to an auto mode method of operation; I think even remote operation.
In our circumstances, with our water depths, because of the very short distance of the hydraulic signal, we find the hydraulic works extremely well. It possibly works better than other systems like the acoustic system. In our water depths, background noise from the operation of machinery can interfere with that acoustic system; whereas in deeper water, obviously they do not have the same level of interference, so it might be more effective.
We constantly look at the mode of activation, and we find for our environment and the primary method of actuation, the hydraulics method is appropriate, but in case it does not work we have a backup, which is the remotely operated vehicle. In Chevron's circumstances, I can understand that they have looked at these different methods of activation.
Senator Seidman: Thank you for coming. I asked Chevron about their level of research and development, specifically for cases of remediation; in other words, in the worst-case scenario of a major spill. This question was specifically regarding R&D for oil containment and cleanup. They said that BP was intending to put $500 million of their R&D budget towards remediation, and I thought it was a bit like locking the barn door after the horse has already escaped. It seems that R&D has been almost exclusively in the area of oil drilling.
Can you tell us something about the kind of R&D that your company engages in for this worst-case situation?
Mr. McCloskey: Certainly; over the last five years, Husky Oil has invested approximately $30 million in R&D in Newfoundland and Labrador. Of that, approximately $5 million was related to what I call ``environmental subjects.'' These range from our support of the development of the single-vessel sites recovery system to projects looking at habitat for marine life. We support a seabird rehabilitation centre. Many of our employees and those who work on our supply vessels are volunteers and are trained to handle birds. We think it is important in the event there is a mishap.
That research broadly captures the areas we have investigated to date. We are open to looking at other investments in research and development — going to the previous senator's point — to improve technologies of recovery or containment. The challenge is finding the right investment vehicle and concept to invest in. We are happy to pursue that investment.
Senator Seidman: I have another question, but I know there is no time. You mentioned your tier-3 response plan. The witnesses that appeared on Tuesday indicated what happened in the Gulf is a tier-3-plus incident. I did not understand what your tier-3 response plan is.
Have I any time, chair, for an answer on that question?
The Chair: I have to deploy our time control preventer, TCP. We will have to pass because I want to give Senator Massicotte a chance, although he came late.
Make a comment because we almost addressed it a moment ago. I think it is only fair to Senator Seidman.
Mr. McCloskey: If there are any questions that we do not have an opportunity to respond to today, please send them to my attention and we will provide answers. I am more than happy to do that.
The Chair: Senator Massicotte, you have two minutes before I will deploy these preventers.
Senator Massicotte: I apologize for being late. I was stuck in another committee.
In follow-up to an earlier question, Canadian legislation is such that you are responsible for all damages caused by your oil spill. Does that responsibility also include economic damage, for example, to fishermen whose stocks are imperilled or to the hotel manager whose beach is polluted?
Mr. McCloskey: I must admit that I am not absolutely clear. As the situation relates to fisheries, there is a compensation program to which we have already agreed. I am happy to revert on that.
Senator Massicotte: Can you come back with more information?
Mr. McCloskey: Certainly.
The Chair: Gentlemen, as you can see, there is great interest in this subject and we could continue all day. I have to move to the next witnesses, and I believe you gentlemen have to leave. By the way, you have been on television, and I am already receiving rave reports on your testimony. Thank you.
Honourable senators, Senator Greene Raine is filling in this morning.
Our witnesses for this second panel are from EnCana. We are pleased to welcome Malcolm Weatherston. He has been the Project General Manager of Deep Panuke with the Canadian Division, Atlantic Canada of EnCana Corporation since 2001. What was the corporate antecedent of EnCana?
Malcolm Weatherston, Project General Manager, Deep Panuke, Canadian Division, Atlantic Canada, EnCana Corporation: EnCana is the amalgamation of two previous entities, the Alberta Energy Company and PanCanadian Energy, both of which were headquartered in Calgary.
The Chair: Mr. Weatherston has more than 30 years of progressive experience in the offshore oil and gas industry. He has worked in engineering and construction management, strategic planning and overall project management in both the North Sea and Atlantic Canada. Since joining the project, he has advanced Deep Panuke through regulatory approval, the field centre bid competition, internal project sanction, the award of major contracts and the current construction phase of the project.
We also have William Zukiwski, who is the Drilling and Completions Superintendent with Deep Panuke. He joined the project in June 2009. Mr. Zukiwski has nearly 40 years of progressive experience in drilling operations in the oil and gas industry, both onshore and offshore. He has worked from the drill floor to the management level during his career on projects in North America, the Middle East, Africa, South America and Western Europe. He joined EnCana in 1997 to support drilling operations in Western Canada, western Newfoundland, and Nova Scotia.
I want to say for the record that you were present when our previous witnesses from Husky testified. We do not need to repeat the introductions of those present again. I had an opportunity to chat with Mr. Weatherston earlier this week. We will be enlightened by the time he finishes testifying. Thank you for appearing.
Mr. Weatherston: Thank you for inviting me to speak to the committee this morning. I am the Project General Manager for Deep Panuke. With me today is William Zukiwski, one of our two drilling and completions superintendents, who is actively engaged in the project.
To provide a background on our project, we prepared an opening statement. Following that, we are happy to answer your questions.
EnCana is cognizant of the tragic circumstances in the Gulf of Mexico that led you to invite us here today. Eleven lives were tragically lost on the Deepwater Horizon. The environmental consequences of the oil spill are devastating. We wish to express our sympathies to the families and those who continue to suffer from the effects of this tragedy.
While I will be unable to offer any analysis today of the situation in the Gulf, I will be able to explain to you what EnCana is doing at the Deep Panuke project to ensure, to the best of our ability, that we have safe and reliable drilling and completion operations in our project.
To begin with background on the EnCana Corporation, the company developing the Deep Panuke project, to clear up any misconceptions the name ``Deep Panuke'' is somewhat misleading. The reality is that this project is located in approximately 45 metres of water. The rig we are currently using, the Rowan Gorilla III, rests on the seabed during our drilling and completions program.
EnCana is headquartered in Calgary, Alberta, with a regional office in Halifax, Nova Scotia, where Mr. Zukiwski and I work, which is the project office for the Deep Panuke development.
EnCana is an innovative natural gas producer that produces safely and responsibly, and provides energy used in communities across Canada and the United States. EnCana specializes in unconventional gas production, which means production from onshore resources, largely in Alberta, British Columbia, Wyoming, Colorado, Texas and Louisiana. Deep Panuke is the company's Canadian offshore development.
At Deep Panuke, safety is our core value, and we work diligently every day to ensure that a safe and sound environment is continually maintained. At EnCana, we have a guiding phrase, when it comes to safety: ``If we can't do it safely, we won't do it.''
The safety of individuals is paramount to the success of the Deep Panuke project, and nothing is more important than that. We are also constantly mindful of the potential effects to the environment from our operations.
The Deep Panuke project's goal is to prevent all incidents and accidents. Should they occur, EnCana makes every effort to mitigate the incident as rapidly as possible to prevent recurrence, while minimizing the effect on the people, the environment and property. We take our environmental health and safety responsibilities seriously, and have developed programs, procedures and protocols that I will describe in more detail shortly.
The Deep Panuke project is located offshore, approximately 250 kilometres southeast of Halifax, Nova Scotia, and 47 kilometres west of Sable Island in approximately 44 metres to 45 metres of water depth. The Deep Panuke natural gas pool is located on the Scotian Shelf, and EnCana Corporation is the owner and operator of that Deep Panuke facility.
The Chair: Colleagues, I refer you to the map that was appended to the earlier witness's statement. It is not a detailed map, but it gives a relative sense of where Deep Panuke is as opposed to the Orphan Basin, where Chevron is, which is right off the chart.
Mr. Weatherston: Thank you, chair. Four existing wells were first drilled and cased during Deep Panuke's exploration phase between 2000 and 2003. At that time, the wells were drilled and suspended so that they could be re- entered later and converted into production wells. There is no extraordinary drilling at Deep Panuke. It is an infield development drilling and completions program, where the geology and the associated reservoirs are better defined than with exploration programs.
The Chair: I may have misheard you, sir, but I think you said there is no extraordinary drilling, but you meant to say exploratory — quite different words.
Mr. Weatherston: I apologize. Thank you.
The Chair: You were down to the drilling and completions program.
Mr. Weatherston: The drilling and completions program consists of drilling one new well and the re-entry and completion of four existing wells. The new well is for the safe disposal of hydrogen sulphide and carbon dioxide, which is a by-product of that process offshore.
Deep Panuke gas is ``dry,'' which is oil and gas industry language for natural gas that is not associated with large volumes of free liquids such as condensate. The low volumes of condensate produced at the Deep Panuke facility will be treated offshore and used as a primary fuel source in the production field centre, PFC, which is the production platform for the project. Condensate is similar in consistency to naphtha, the fuel used in camp stoves, for example.
The market-ready natural gas from Deep Panuke will be transported via pipeline approximately 175 kilometres long to an interconnection with the Maritimes and Northeast Pipeline in Goldboro, Nova Scotia.
All wells will have subsea trees, which are flow control modules and barriers affixed to the top of each well. A subsea pipeline isolation valve will also be located approximately 50 metres from the PFC. This valve can be activated to isolate all natural gas in the pipeline to the shore from the PFC and the production wells. We anticipate first gas from Deep Panuke will be in the second half of 2011.
I wanted to spend a little time with respect to the regulatory process in an attempt to demonstrate the rigour of our regulatory regime here in Canada.
The Chair: That is fine, as per our discussion. You will have to appreciate none of us is an engineering expert on drilling and exploration in the oil and gas field, but we have been able to figure out there is quite a difference between drilling for oil and drilling for natural gas. If there is an escape of oil, we obviously have the thick black oil slicks; whereas in the case of gas — I know this is an oversimplification — if it were to escape, basically there is not an environmental horror show. It evaporates into the environment, I think, but there is the condensate.
If you can make that distinction clear for us and for our report, that will be good. I know it seems simple to you, but it is important to us to understand what the risks are. We understand there is a flammability issue and the possibility of explosion, which is equally frightening to contemplate, given the number of folks who work on your installations. I think you see my point.
Mr. Weatherston: Chair, would you like me to answer that question?
The Chair: I do not see it in the rest of the submission and I do not think it will take you long. Then we will understand the regulatory process and the response plan a little better.
Mr. Weatherston: Allow me to try to do that. The gas field we are currently in is a normally pressured gas field, with very low levels of free liquids. The drilling takes place in 45 metres of water. The critical well control equipment that we have all spent a lot of time talking about — such as the BOPs, for example, and other secondary well control systems — is located on the rig itself. In our case, the critical hardware that we have been discussing is there and it is accessible by people on the rig, rather than being located subsea at the seabed.
In the event of a severe upset condition, a major gas release, the gas would permeate through the seabed if the release were at the seabed or from the BOP stack on the rig. That gas would be liberal and volatile, and would dissipate quickly into the atmosphere.
Under those circumstances, the first and second levels of emergency response prevail. We contain the area, safely evacuate the personnel and seek to intervene in the most appropriate way to stop that flow in the shortest and safest way possible. I will ask Mr. Zukiwski later to describe in detail those control practices.
Associated with a gas release of that type, there are free condensates. In our case, the condensate is in small amounts. It is approximately 3.2 barrels of condensate per million cubic feet of gas liberated. The effect of that condensate, in simulations and tests we have done, is to lay a thin sheen on the water. This thin sheen is about 15- microns thick at the initial instance of a gas release and explosion. Quickly, within minutes, it dissipates to less than 1 micron. It is much like watching gasoline evaporate on water; that is the constituency of the product.
The Chair: That explanation is excellent. You were on page 5 at the regulatory approval process.
Mr. Weatherston: Again, this explanation may be wordy, and I apologize for that, but having read all the testimony of our peers I think it is worth trying to provide comfort and confidence in the rigour of the regulatory process under which we work in Canada.
There is extensive regulatory oversight for Deep Panuke. A comprehensive environmental assessment was completed for the project, and the project has been closely scrutinized by our regulators, the Canada-Nova Scotia Offshore Petroleum Board, CNSOPB, and the National Energy Board, through a development plan application and NEB filing in 2006 and subsequent joint hearings that took place through 2007.
Following the CNSOPB development plan approval and the conclusion of the environmental assessment, EA, process, two additional levels of authorization or approval are still required from the CNSOPB prior to commencing the Deep Panuke drilling and completions program.
First, the Drilling Program Authorization is required for the overall program; in our case, four re-entries of existing wells and the drilling of a new disposal well.
Second, separate well approvals are required for each well to be drilled or re-entered, and a separate program has to be submitted for each of those wells. Prior to receiving the Drilling Program Authorization, a series of regulatory requirements were met to address safety and environmental protection, including a safety plan, an environmental protection plan, an environmental effects monitoring plan and an emergency response plan. EnCana has also filed a comprehensive package to demonstrate evidence of financial responsibility in compliance with the regulatory requirements.
Finally, with respect to the Drilling Program Authorization, EnCana provided a Declaration of Operator declaring that the program and the facilities used for this program are fit for purpose, the related operating procedures are appropriate and the personnel are properly qualified and competent to undertake the work.
The final level of approval process for our drilling and completions program is a requirement to obtain an approval to drill a well or an approval to alter the condition of a well. The application for each well provided detailed information on the drilling and completions program itself and the well design.
Moving to safety, EnCana's safety culture is driven by EnCana's corporate responsibility policies, the EH&S principles and the EH&S management system.
The Chair: What is EH&S?
Mr. Weatherston: EH&S is environmental health and safety.
Specifically for our Deep Panuke offshore drilling and completions program, EnCana has clearly defined its EH&S program jointly with the company's rig contractor through a series of safety workshops held with our rig contractor and other offshore service providers. Prior to commencement of the drilling and completions program, we developed a safety theme. The safety theme is ``Target Zero,'' meaning our target is zero lost time incidents and zero spills during this program. Working closely with our contractors, we developed the following ``Safety Tenets'' to best achieve the zero target: One — obviously important — safety is our core value; two, protect the environment and health and safety at all times; three — very important — obligation to stop unsafe work, acts or conditions; four, identify, assess, discuss and mitigate all risks. We can discuss the tools we use to do that in a moment. Five, there is always time to do it safety — do it safely or not at all; no short cuts. Finally, report all incidents and near misses.
All workers have obtained an obligation and responsibility to intervene to stop unsafe work as per the stop program implemented on the drilling rig. Workers are instructed not to wait until it is too late. Workers understand that their concerns will not be subject to repercussions, but rather, will be treated with encouragement and respect. Laminated wallet cards were issued to all project personnel that empower them to stop any unsafe work. These cards listed the aforementioned safety tenets. We brought cards with us today.
The Chair: I am holding one up, as are you. I think you have circulated them to all members of the committee. This is interesting. Thank you.
Mr. Weatherston: The safety culture, coupled with the efforts of EnCana and Rowan onshore and offshore personnel have produced positive safety performance results since November 2009, which was the start of our re-completions campaign, with zero lost time incidents to date.
The Deep Panuke risk assessment and management program was established to identify and effectively manage EH&S risks during all phases of the project. EnCana believes that the recognition of risk is the first step toward reducing it. EnCana has conducted thorough and detailed risk assessments of all aspects of our current offshore drilling and completions program, including drilling, well re-entries, completions, well testing and well control activities.
The mitigating measures identified through these risk assessments are communicated to supervisory personnel on the drilling rig for reference on site where the work is being conducted. These measures are discussed and verified on site with the crews every shift using tools such as the permit to work system, job risk assessment, pre-job safety meetings and so on.
The Chair: You have used the term ``well re-entries.'' We have heard that during the exploration phase there is drilling of wells that, in many cases are plugged up, and you come back to them later. Is that what ``well re-entry'' refers to?
Mr. Weatherston: Yes.
The Chair: What is the process for plugging them up, and is there any risk there, or is that a no-brainer?
William Zukiwski, Drilling & Completions Superintendent, Deep Panuke, Canadian Division, Atlantic Canada, EnCana Corporation: If I may assist my colleague, when the wells were originally drilled, they were also cased and cemented. Before we take the drilling rig away, we place barriers inside the wells, which consist of mechanical barriers plus cement barriers. Those multiple barriers placed in the well allow a safe suspension of the well until access has to be regained. That is the re-entry of the well to complete it and bring it into production.
The Chair: Thank you.
Mr. Weatherston: EnCana's focus is safe drilling and completions operations at all times. These operations are directly supervised by EnCana personnel. The contracted drilling rig, Rowan Gorilla III, is provided by Rowan Companies, an experienced North Atlantic drilling contractor.
To date, we have completed the conversion of one re-entry well and are working to complete the second re-entry well. In addition, one new well has been drilled and completed, that being our disposal well. Well-control training specific to EnCana's Deep Panuke's project was presented to all crew members, supervisors and Rowan Gorilla personnel prior to commencement of the project. Refresher training for unique scenarios that may be encountered in the well entries is conducted using simulators that mimic the operation being conducted. Crews are taught blowout prevention and well-control techniques.
When the existing wells are re-entered, the wellbore has a minimum of two, and up to three, of the following safety barriers in place between the reservoir and the drill floor.
First, a weighted brine — sodium chloride — completion fluid exerts a pressure in the wellbore higher than the gas reservoir pressures.
Second, a system of hydraulic valves at surface under the drill rig floor called blowout preventers can close around any size of pipe in the BOP or an open hole and stop the flow from the well. Blowout preventers are installed before any critical pressure work is commenced on the well. All work on each well takes place through the blowoutout preventer stack. The blowout preventer stack can be controlled from two remote locations on the drill rig if an emergency occurs.
Third, a fail-safe subsurface safety valve is also installed in the production tubing string — fail-safe meaning it will stay open only when positive hydraulic pressure is applied to it from the surface through a line from the drilling rig or in production operation from the production facility itself. Otherwise, it will shut down by default.
At no time in the Deep Panuke project is there an uncontrolled direct path for gas to flow to the surface. It should be noted the blowout preventer stack is located on the drill rig, not on the seabed, making access and maintenance much easier. Closing time for blowout preventers is much quicker than if the blowout preventer were located on the seabed.
The Chair: Is that because of the difference between oil production and discovery, and gas?
Mr. Zukiwski: That is a good question. The difference between the surface blowout preventer is the location of the blowout preventer stack at surface versus a subsea blowout preventer stack, which is on the seabed. The reaction time to close the blowout preventer when it is on surface is far shorter.
The Chair: We understand that. The point is whether they could have the blowout preventer on the oil rigs at the surface like you do.
Mr. Zukiwski: In some cases they do, but in deepwater operations, it is not possible to do that. It would require an extremely high pressure riser and that technology for extremely deepwater operations does not exist yet.
Senator Massicotte: What is the difference in response time? Is it seconds, minutes or hours?
Mr. Zukiwski: It is seconds, and there is a set of worldwide standards by API Standards that can be referenced for the timings required for surface blowout preventers to close and also subsea blowout preventers to close. That document is API RP 53, Recommended Practices for Blowout Prevention Systems for Drilling Wells.
Senator Raine: What happens if there is a break in the line between the rig and the gas reservoir?
The Chair: In the riser?
Mr. Weatherston: In the water column.
Mr. Zukiwski: If there is a break in that line, we have our subsurface safety valve that closes. In addition, there are other hydrostatic means. We have a fluid barrier, which is the drilling fluid or completion fluid, which is also considered a barrier. If that barrier has a high enough hydrostatic pressure, it will overbalance the reservoir pressure and retain the gas at the bottom of well. You will see no gas to surface.
Mr. Weatherston: During drilling and completion operations at Deep Panuke, emergency response training exercises are conducted regularly on the drilling rig, for hydrogen sulphide release, evacuation, man-overboard and fire and well control. Competency of crew members is continuously assessed by supervisors throughout the exercise, and the frequency of training exercises is increased as required. Continuous improvement in response times continue to be observed.
To ensure that crews returning from days off are reacquainted with safety and evacuation procedures, training exercises are always conducted shortly after crew changes. Newcomers to the rig must go through a full safety and well- control orientation as well as a detailed rig orientation before they can commence working.
With respect to the emergency spill response, the Deep Panuke project has developed an emergency management plan and a spill response plan that provide effective and consistent responses to any emergency situation that may arise during the course of the Deep Panuke drilling, completion, testing, installation, construction, production and operations phases. The plan clearly outlines the means to initiate and organize the appropriate response and by whom to reduce the effects of the emergency situation initially and during the course of an emergency event.
The plan also provides clear communication and exchange of information, strict accountabilities and the pre- establishment for planning and logistical support for any accident. The plan ensures an effective use of resources during an emergency.
All personnel undertaking either core or support roles have received training as to their roles and responsibilities, including periodic mock exercises to practice the team response under simulated scenarios.
In conclusion, for all Deep Panuke operations, safety and the protection of the environment are our core values. Risks have been studied extensively, and risk assessments have been used to design and build numerous safety measures into every aspect of the project.
The Deep Panuke project's overarching goal is to prevent incidents and, where necessary, mitigate any incident as rapidly as possible while minimizing the impact to people, the environment and property.
We are fully committed to safe offshore operations. Deep Panuke is not an offshore exploration program. Offshore operations at Deep Panuke represent the development of a known natural gas reservoir in the shallow waters off Nova Scotia.
There is extensive regulatory oversight for the Deep Panuke through the Canada-Nova Scotia Offshore Petroleum Board and the National Energy Board. We welcome the involvement of the regulators, and we will cooperate fully with any additional direction provided by them in the days to come.
We thank you for listening to us today.
The Chair: Thank you. I will proceed directly to questioning because of our time. In the gas operations off Nova Scotia, we understand you are a major operator but is Exxon Mobil also in that area? Are you the main two companies?
Mr. Weatherston: At the moment, yes, we are. There is the Sable development.
The Chair: Exxon Mobil is not in Deep Panuke. It is at Sable.
Mr. Weatherston: It is at the Sable field development.
The Chair: That is not on Sable Island, but in the area.
Mr. Weatherston: It is in the area of Sable Island, as are we. Their development somewhat covers the northeast and northwest flank of Sable Island.
Senator Raine: I am a substitute on the committee, but I have many questions.
Is this project your only offshore gas drilling operation?
Mr. Weatherston: For EnCana Corporation currently, this is our only offshore gas development.
Senator Raine: Do you see it as a prototype for other gas fields offshore in Canada, and where would they be located?
Mr. Weatherston: Speaking for a moment about EnCana's corporate vision, EnCana Corporation has moved progressively towards establishing a major leading position in onshore North America. The interests of EnCana progressively have come in the exploitation of unconventional gas reserves, which are the shale gas reserves that we hear so much about, and their interests continue to focus on that development and their longer term vision for the corporation.
Senator Raine: Can you explain more about the disposal well? Does this differ? I understand that in this case, you are putting things down into the ground, so are the blowout preventers used in the same fashion?
Mr. Weatherston: Yes; in fact, we are pleased and proud of our approach with respect to the process in this facility offshore. We received a great deal of support and kudos from our environmental colleagues and green colleagues with respect to the design of this project.
Without taking too long, the disposal well is located about one kilometre or a kilometre and a half away from the proposed field centre. The disposal well is drilled to a depth of 2,400 metres. It is quite a depth but much less than the depth of the actual gas-producing reservoirs. The intent of that is to put H2S and CO2 — greenhouse gas — in single phase compression back down into the structure at source. The benefit of this approach is that we do not need a sulphur plant onshore or a large ecological environmental footprint. The process, as currently designed, produces sales-quality gas right off the platform. All these things are stripped offshore and disposed of offshore in a safe and environmentally friendly way. Sales-quality gas is transmitted to shore without the necessity of any onshore facilities whatsoever.
Senator Seidman: Good morning, gentlemen, and thank you for being here.
This is the first time that we are hearing about gas specifically because we have been discussing oil. There is a lot to try to understand in terms of how it all works. I know that when a gas leak occurs due to a break in the pipeline, there is great fear of an explosion. For example, when that happens in Montreal, where I live, they close all the streets down for hours until they deal with it.
I am trying to understand what would happen. We have talked a lot about level-1, level-2 and level-3 emergencies. We have a level-3 emergency in the Gulf of Mexico. How combustible or how unstable is the gas in the first instance when a break in the pipeline or in the water occurs? How combustible is the disposal well? Is it unstable? I am trying to understand the equivalent potential catastrophic event and how well we might be prepared for that event?
Mr. Zukiwski: If I may answer, chair, I remind everybody that safety is paramount with EnCana Corporation, and most certainly, there is a danger with gas. We have multiple gas detectors on the drilling rig that sense the minute levels of methane gas in most natural gas and hydrogen sulphide gas, which is a small component of the gas that we produce. If there is the smallest of leak at surface, we will be able to detect that leak and the location of the leak in its close vicinity. As a result, we can immediately shut down the operation; activate mechanical barriers, such as the blowout preventers or sub-surface valves; and close off any flow to prevent any possible explosion that could occur.
You asked a question about the disposal well. When we inject gas into the disposal well, we have our sub-sea Christmas tree of valves on the ocean floor that are remotely controlled from surface and are able to be controlled from the seabed.
These valves on the Christmas tree structure, in the event that there is a leak from the production facility or in the pipeline, can be activated remotely as well. They are also fail-safe valves such that if we happen to lose hydraulic pressure to those valves, the loss is spring-loaded and the valve will close immediately. The down-hole sub-surface safety valve will close immediately to stop any flow of gas.
Senator Seidman: Are you telling us that there is no equivalent type of catastrophic event with gas compared to what we see in the Gulf today with oil? I am trying to understanding whether there is an equivalent. If the fail-safes are such that they detect and shut down the gas, does it mean that we could not see the same kind of catastrophic event with gas?
Mr. Zukiwski: We must remember the preventive measures we have taken to install the additional barriers at the seabed and in the production tubing strings to prevent the flow of gas or uncontrolled release of gas to surface. It is with those preventive measures and those pieces of equipment that we can stop those releases. To have multiple failures of those pieces of equipment at one time is highly unlikely.
Further to that question on the sensing of any leak in a gas system, we have an emergency response plan in place on the drilling rig, or what will come later in our production facility that will be activated. When we activate that emergency response plan, the people are mustered to a safe area and, if the gas leak is substantial, we will evacuate the facilities and activate emergency response and additional barriers to close off the gas and prevent it from coming any further.
Senator Frum: I have two separate questions in pursuit of the magic number for how deep is too deep. Can you characterize the magnitude of the risk differential at two operations; one with a blowout preventer on the surface and one with a blowout preventer at deep water levels?
Mr. Zukiwski: If I may answer, chair, that is a good question. We follow the analogy that if we can see the piece of equipment in front of us, it is a lot easier to know whether we have a leak or failure. We have a responsibility to monitor the safety of this equipment, its operational procedures and the preventive maintenance that occurs to that equipment.
When the equipment is at surface, it allows us greater opportunity to provide and conduct preventive maintenance as required. When we function-test that blowout preventer, we can see to know that the blowout preventer is functioning by indications on the preventer. We pressure-test the blowout preventer every two weeks and function-test daily. We can look at the preventer to determine whether we have a leak. We monitor pressure by gauges and charts but being able to see it is so much better.
Senator Frum: My question at the other end of the scale is about the human element. We spend most of our time talking about the technical element, and you stress that in your safety card number 3. What policies do you have for the crew regarding the use of drugs and alcohol? Is that an issue or do you have corporate policies?
Mr. Zukiwski: EnCana Corporation is extremely serious about drugs and alcohol. We have a drug and alcohol policy. As well, all the contractors who work for us have drug and alcohol policies. Our drilling contractor has up to 54 men on our installation most of the time — our largest contractor. The contractor is extremely stringent, and there is zero tolerance of any drugs or alcohol.
When we transport people to the drilling rig, any smell of alcohol on anyone will be noticed when they arrive at the helicopter. They are not allowed to board. They are also likely to be discharged immediately from their position by their companies.
There is zero tolerance for drugs and alcohol.
Senator Frum: How often does that happen?
Mr. Zukiwski: We check everyone every time. How often does it happen that we have people caught under the influence of drugs and alcohol? We have not had a case of drugs or alcohol in our operation on the East Coast of Canada during this time period.
The Chair: That is a good point. Senator Lang had a point of clarification, as well as Senator Frum's question. You have time for both.
Senator Lang: For clarification on the drug and alcohol policy, are drug tests taken on a regular basis?
Mr. Zukiwski: Yes, our drilling contractor undergoes drug and alcohol tests at specified frequencies.
Senator Lang: In your presentation, you said you have operations in Louisiana. Is this your only offshore operation in the world?
Mr. Weatherston: Yes.
Senator Lang: What is asked of you from the regulator regarding your operation in Canada versus your other operations in the world? You mentioned receiving kudos from organizations not directly involved with your operation. Is Canada asking for things to be done differently from other operations, for example, in the Gulf of Mexico or other parts of the world? If Canada does, what is different?
Mr. Weatherston: My experience over the past 20 years has been East Coast Canada and dealing with regulators in Newfoundland and Labrador and Nova Scotia. My career in excess of 30 years has been with respect to offshore environments almost exclusively. I am not comfortable in trying to speculate with respect to other onshore jurisdictions. However, I am happy to have someone who is familiar with regulations in the U.S. and Western Canada from EnCana address that question.
Senator Lang: That would be interesting if there is someone in your organization with an understanding of the differences. We are trying to determine whether differences exist in Canada, offshore in this case, and the United States or elsewhere. Is our regulatory body working in a manner such that we mitigate any catastrophe to the best of our ability from a safety point of view?
Mr. Zukiwski: My experience is more global. I have experienced regulatory regimes in other parts of the world.
Regulatory bodies that we work with on the East Coast of Canada are far more stringent than what I experienced elsewhere in the world. The regulators are extremely diligent in their responsibilities in providing solid goalposts that operators and drilling contractors must abide by from drilling and production, environmental health and safety to certificates of fitness.
As a Canadian, I am proud of how well regulated this Canadian industry is from a personal standpoint. I will stress that these regulators are stringent and provide us with great goals to achieve.
Mr. Weatherston: Much of what we have been talking about recently is retrospective action, inspection, attestation and certification — show me what you do and that you do it. One thing about the regulatory regime in the Canadian offshore environment is that it is proactive. It is more proactive in quality assurance aspects of offshore developments. The regulator is involved with us in the early stages — in submission of the development application plan — years before anything is moved into detailed design, procurement or manufacture.
At each step, we are in consultation with the regulator. The most value that we can possibly achieve is being proactive at the conceptual design of these facilities. How do we design inherent safety from the beginning regarding the materials, reliability and redundancies in the system? That engagement with the regulator in Canada starts early. The regulators have an independent, third-party arm's-length certifying authority that acts as their agent in the more detailed design and risk assessment, layouts, execution strategies, et cetera.
Throughout that entire time, and prior to being confronted with an asset sitting in the ocean, there has been significant interaction with the regulator. That quality ultimately results in higher levels of confidence, technical integrity and safety in the assets offshore. It is generated from that earlier engagement with operators during the design, procurement, manufacture, in-process inspection and pre-commissioning and commissioning start-up proceedings. Regulators are involved in all aspects as we move along.
I hope that gives you improved confidence that we are regulated appropriately. We respect the regulators and, at all times, strive to meet or exceed those requirements. We are open with the regulators about where we are, what we do and how we solve problems as we go.
The Chair: This question probably requires a one-word answer. Oil and gas companies are big international corporations. The suggestion in the U.S. is that the relationship between the regulators and drilling companies may not have been totally at arm's length. Can you assure us the relationship in Canada is at arm's length? Are we open to allegations or suggestions of your companies being in bed with the regulators?
Mr. Weatherston: I can tell you from a personal perspective that I am not in bed with the regulators. I think we have a healthy and mutual respect for our respective positions.
The Chair: You know what I am getting at?
Mr. Weatherston: Yes, I do. Their objectives are to ensure that we operate safely and have the highest levels of technical integrity and redundancy in our facilities. Those objectives are no different from our objectives. In that, we are aligned.
Senator Brown: We were told by a witness from one of the companies that the equipment they use can take pressure up to 10,000 pounds per square inch. The deeper we drill, of course, the higher the water pressure becomes. In the Gulf of Mexico currently, something like 90,000 barrels per day of oil is coming from that well. That pressure all has to come from the pressure of gas, does it not? The gas that is in the formation where the oil is coming from has to be extremely high pressure. Can tell me what the highest pressure ever recorded has been?
Mr. Zukiwski: That is a good question. From a formation pressure standpoint, the formation pressure that exists in any formation — and especially in the reservoirs — is a combination of a few things. It is the weight of the rock that is above that reservoir, plus the weight of the fluid contained within all that rock above the reservoir. That weight creates the pressure in the reservoir.
Inside the reservoir, you must have what is called ``porosity,'' which is free space in the rocks, and also permeability, which are the connections between those free spaces in the rocks. Visualize a sponge that you would wash yourself with; that is typically what a reservoir rock looks like, but in an exploded view.
The contents of the reservoir do not necessarily have to be gas and oil. The contents can be only oil, oil and water or pure gas. It is hard to speculate what BP's reservoir is like because I have not seen their geology, and different reservoirs are different throughout the world and throughout the Gulf of Mexico.
I can tell you what our reservoir is like. The content of our reservoir is natural gas; it has a water drive behind it, which is down below the natural gas. The pressure in our reservoir is slightly lower than 5,000 psi — to be exact, about 4,820 psi. That means that the blowout preventer rating for our stack could be in that 5,000 psi range. One has to consider that the gas, when it comes to surface, has a hydrostatic pressure. Essentially, the pressure we see at surface is approximately 4,250 psi.
At Deep Panuke, we use an 18 and three-quarter inch, 15,000 psi blowout preventer stack. A pressure rating that high is not required for us, but the size of the blowout preventer is required for us because of the tools that we must run through that stack to be able to complete our well for production. The pressure rating of the stack by far exceeds the reservoir pressure rating, but that is the equipment that is available to us on today's market.
Senator Brown: My concern is, is it true that with every well you drill that is deeper than previous wells, you face greater pressure of some kind from something — whether it is water, rock or gas?
Mr. Zukiwski: Definitely, as you drill deeper, the pressure gradient increases; it has to. That is Mother Nature's pressure. She will give you much more pressure for each metre of depth that you drill deeper. There are times when the pressures that are down in the earth will be much greater than what the blowout preventer stack is rated for.
However, the hydrostatic pressure that is applied to that well when it is drilled is more than what that reservoir pressure is. Regarding the pressure rating of the blowout preventer stack, we try to design that blowout preventer stack to meet the expected surface pressure.
Senator Brown: As a comment, we were in Norman Wells a little over a year ago, and they have three wells in the middle of the Mackenzie River. They stated that the wells have been flowing for 30 years without a pump, and they estimated that the pool of oil will still be 50 per cent when it no longer comes up without a pump. That made me think that the pressure must be incredible.
Senator Massicotte: Further to earlier questions, I am trying to understand better the difference between an oil spill and a natural gas one. We can see on CNN what an oil blowout is; obviously, there is a significant difference.
I know your answer is that there is little probability of that happening and that you have all kinds of measures. However, even your own report says, ``to the best of our ability.'' In other words, there is a slight risk of a catastrophe, but there is a risk. To understand, on CNN, we see the oil. What is a major disaster on the gas side? What is the consequence of a disaster if you have a gas problem?
Mr. Weatherston: Again, the probability of something like this occurring is remote. The number of failure modes —
Senator Massicotte: I appreciate that, but if there is one?
Mr. Weatherston: If there is one, part of our submission through the environmental assessment process under the Canadian Environmental Assessment Agency, CEAA, was to model those potential events. What would they look like? We had to sit down and set aside the fact that this could not happen and say it has happened.
What we have, then, is full open communication between the gas reservoir at Deep Panuke and the atmosphere. What does that look like? We consider plume dispersions, condensate dispersion modelling, what area is affected, what would it do to wildlife, to birds and fish and so on?
A full catastrophic failure of a well in Deep Panuke that was totally exposed and open to the atmosphere would cause an exclusion zone around that well of approximately one kilometre. We would have to maintain a complete exclusion zone in the ocean around that well until such time as we could properly kill the well and regain control of it.
The gas would come out at some velocity and immediately up into the atmosphere. The major concern with that situation is the small amount of condensate that we talked of earlier. This condensate — and I have seen it personally — is very light oil. As a comparison, it looks like light pilsner beer, also a refined product.
When it is spilled on the ocean, it spreads out quickly. We have seen dispersion modelling that says it could be a kilometre in diameter. That is the extent of the condensate on the surface. It lands on the surface at about 15 microns; and within minutes, between evaporation and dispersion due to ocean movement, it is about 1 micron. At 1 micron, it has no deleterious effect on seabirds or anything of that nature.
The concern would be someone coming along and throwing a cigarette butt on it, which we not want to have happen. There are emergency response plans in place to deal with that eventuality. That had to be submitted through an EA process and fully described and understood by all of the environmental agencies and all the other regulatory agencies. Then the appropriate emergency response plans we talked about earlier — levels 1, 2 and 3 responses — would be called into play, depending on the significance of that emergency.
Senator Massicotte: In summary, there does not appear to be much risk of damage to the environment. I presume the risk is more to human life from explosions, is that correct?
Mr. Weatherston: Yes.
Senator Lang: To follow up on this point, you are not the first offshore gas operation. Has there ever been this type of a blowout anywhere in the world, to your knowledge?
The Chair: Do you mean gas?
Senator Lang: In gas.
Mr. Zukiwski: Yes, there has.
The Chair: Where?
Mr. Zukiwski: There has been a blowout in the Gulf of Mexico. There has been a recent blowout off the coast of Tunisia; this was about three to four years ago when a drilling rig was burnt down. Also, in India, a platform was struck by a supply vessel and caught fire and burned.
Senator Lang: In those cases, to your knowledge, did it take days to contain it, or are we talking months?
Mr. Zukiwski: I would have to research how long it took to put those fires out and contain those wells, but we can do that and get back to you.
The Chair: Thank you, gentlemen. It has been extremely helpful for us to hear your evidence this morning. We appreciate the time and trouble you have taken to come here from the East Coast and tell us about what you do, and also the undertakings you have made to give us further data, which I gather you will channel through our clerk. Thank you both very much indeed.
I will suspend the meeting. I want to talk to members of the committee in camera for a short time.
(The committee continued in camera.)