CATEGORIZED | 2013, January/February

Stakes run high in risk management, training, delivering transparency

Posted on 30 January 2013

Unprecedented proximity to populations in shales means industry must provide steady stream of information, ensure operational integrity

web_Lacy-Kevin-07-8x7@300-CLBy Linda Hsieh, managing editor

Kevin Lacy is senior vice president of global drilling and completion for Talisman Energy.

One of Talisman Energy’s key focus areas is North American shales, where you have active operations in the Eagle Ford and Marcellus, as well as in Canada. How do you see Talisman and the rest of the industry working to improve management of issues around hydraulic fracturing, which are affecting not only the industry’s public image but also its license to operate?

There are a couple of fundamental things the industry has to understand that are unique about the situation. Because of the shale boom and the activity levels, we are working in people’s backyards or their neighbor’s backyards. Our proximity to them is unlike it’s ever been before. We’re not offshore and we’re not on state or federal lands – we’re on school playgrounds and in people’s backyards or on their farms. That is a very different situation than we’ve been accustomed to before.

Secondly, it’s very difficult for industry to attempt to use technical explanations to convey the concept of fracturing. That it has minimal risk or exposure is very difficult for the public to understand because the average person will basically take the view that zero risk is the right answer. Because we’re in their backyard and we’re doing activities they don’t understand, they think risk should be zero.

Industry must continue to provide a steady stream of information and transparency on the issues. Because of the breadth of operations being undertaken and how readily any mistake can be multiplied in the public arena to taint the reputation of the entire industry, every operator, service company and drilling contractor must fully appreciate that we have a public responsibility not to just operate safely but to inform and be as open about our operations as possible.

So you’re saying that industry needs to recognize that the hydraulic fracturing debate is not rooted in science, therefore we need to put in even more effort to improve operations and performance, rather than simply attempt to win by logic.

It’s very easy these days to quickly broadcast information that may not be completely factual or be misunderstood. We do have to recognize that visibility and the need to have a very high standard in everybody to work to that high standard.

You mentioned that transparency is very important in maintaining industry’s license to operate. Do you think industry is providing enough of that transparency?

I think the industry has done a lot. The proximity to populations and the problems if we’re not transparent have actually influenced companies to make their chemicals public on websites and take people out to the rig site to explain what’s going on. I also see efforts in government and community relations, with a majority of operators making extra efforts to be open and transparent. They recognize how fragile this industry can be if you get it wrong or if you get a poor showing in the public arena.

Industry is setting records with very high numbers of frac stages in the shale plays, but what improvements are still needed around how we’re fracturing these wells?

I would say that the understanding of optimizing fracturing is in its early stages. We are just starting to come back around with enough experience and data that we can begin to put more analysis into the rock properties, the fluid flow fundamentals, etc.

On top of that, if you think about the shortage of experienced people we have nowadays, I would say that the industry’s need for completion engineers and stimulation professionals is very critical. The impact of drilling to wells these days is often secondary to completions and/or fracturing. From a drilling professional standpoint, many experienced drilling managers have very limited experience in completions and stimulation, and that’s definitely an area the industry’s very scarce in.

I would offer that completion or subsea professionals are probably the biggest chronic area where we lack technical professionals.

Is that affecting industry’s ability to get its wells completed?

We get them completed, but the question is, is it the most cost effective and efficient completion? Truly, there are wells in the deepwater environments, in high pressures and high temperatures, where the completion techniques and equipment are not fully ready yet. There are some wells we can drill but not complete.

Onshore, it’s the understanding of what we’re doing, what are the optimal frac lengths and the optimal stages. There’s just now starting to be a variety of things we can do in each of the frac jobs in terms of the fluids and frac sands and other types of things that people are beginning to understand or try to fully understand.

You recently had a new operation start up in Poland with shale drilling activity. We’ve read in news reports over the past year about protests that some oil and gas companies have faced while trying to drill shale wells in that country. What have been some of the challenges you’ve faced in your Polish operations?

We’ve done three vertical pilot wells. Currently our present plans call for going back to the most prospective location of the three, drilling a horizontal well and doing a frac spread on that well in late 2013.

The challenge companies have faced here have been on two fronts. Poland has had an active but state-run oil and gas sector for some time. I think some operators have run into problems not recognizing the restrictions that were required on well plans or approvals of not just the well plans but also field operations. We worked with a Polish drilling contractor that knew the system, and we then worked with them on how we wanted things to work from a safety standpoint.

The second challenge is that there are a lot of expectations from the communities, often from areas that historically haven’t had drilling. You must have community relations programs and make sure you have good relationships with local services and local communities and the landowners. We were fortunate to have some Polish speakers on our team so it made these efforts a lot easier.

Most of the industry continues to feel the squeeze on the people side, with experienced and competent personnel still in real shortage. How do you think that’s affecting operations?

It presents challenges in terms of quality control. People who normally have time to do the right thing may not have time to do the right thing. And we have lots of technology; it’s just not as well utilized or applied as they could be, and that is a combination of the pace of activity and having enough people to take the time to put it in place.

The longer-term answer to this is to bring more people into the industry and develop them as fast as possible. The medium-term answer is to utilize people better and utilize their talents better. For example, an engineer probably spends 50% to 60% of their day not doing engineering tasks, on average. They might be in meetings or doing other things that are not what you would call core activities.

H&P Rig 459 operates in the Eagle Ford for Talisman Energy.

H&P Rig 459 operates in the Eagle Ford for Talisman Energy.

What about in the short term? Is there a short-term answer?

In the short term, I think everybody’s just trying to hire from each other, and I can tell you it’s not working. Everybody loses because we have such a tremendous turnover. It’s a zero-sum game.

How are you using remote operations centers to leverage the experienced personnel that you do have?

We have one real-time operations center in Calgary, Canada, that runs 24/7, and we use it in three ways. As you said, it clearly allows us to leverage scarce talent in terms of planning, monitoring and executing our wells, allowing us to tie into people in multiple locations. For some of these complex wells we drill, I wouldn’t do my job without it, whether it’s our internal center or a third-party service center.

Secondly, these centers also provide  a tremendous basis for training and developing engineers. We have people who sit in our Calgary center who now get to see an offshore well get drilled at the right stage in their career. Or rather than be an engineer who just sits in one business unit, they can actually see wells drilled in Canada, in the United States, in Southeast Asia, etc. It does very much accelerate the development of the engineers.

Lastly, to me, it’s definitely a piece of the safety and the well control monitoring part that’s necessary these days.

What types of well monitoring do you perform at your Calgary center?

We have different levels of coverage depending on how complex a well is. It could be 24/7. It could be periodic monitoring of a particular well segment. In some very simple wells we keep track of all the operating statistics or the parameters in the background, and should there be a problem, we can then pull it up.

However, primarily the engineers in the real-time center use that data to provide performance analysis so we’re able to consult and give recommendations back to the team in what I would call a passive monitoring mode.

How has your approach toward process safety changed or in the way you address process safety with your drilling contractors since Macondo? Are you working with them more proactively to encourage more focus on this area?

Let me start by saying that it is the fundamental responsibility of the operator to take responsibility for well control, and then to work closely with the drilling contractors and service companies relative to their parts. There have been a number of improvements, granted some of them are still in draft form, but moving toward industry standards, particularly for deepwater. We’re also making the well plans and safety management systems more a centerpiece of the conversation among the drilling contractors, operators and service companies. These are all very good steps, but still very much in the infancy.

It is still back to each person doing their part well. There should be enough internal verification being done that the other party can be comfortable that it’s done. For example, I don’t think the drilling contractor is in a great position often to adequately test or verify what the operator is doing, or vice versa. It’s not a displacement or replacement of the fundamental accountabilities, but it’s a higher level of verification and transparency of that verification which is needed, particularly in the deeper waters.

Is there any one area that you think industry should place its focus in order to avoid similar process safety-related incidents in the future?

Our view at Talisman is that the primary effort needs to be on maintaining and verifying barriers to flow. Our efforts have been largely internal to make sure that our well designs and well operations not only maintain barriers but maintain a redundancy and verification of those barriers. That’s 90% of the risk exposure that we need to make sure we’re on top of.

The second part of that is where the contractors and service companies come in, either with the placement of those barriers or with the surveillance or verification of those barriers. Ultimately they respond to a non-routine situation that might be a flow.

At a recent industry conference I attended, I was very encouraged by some statistics that Transocean showed about encouraging their crews to shut in the well, not think or try to analyze or wait. It is a critical issue to get across to the service companies and drilling contractors that, when they suspect a problem, you do have to stop work, shut the well in and understand what’s wrong. They showed statistics on well kicks and their intensity, and you could see the improving trends because they’re getting that message across and saying that’s absolutely critical. That was very encouraging.

We’ve also set up a program in the Eagle Ford, where we’ve had as many as 12 rigs running and have nine rigs running right now. Due to the number of new rigs and the inexperience of some of the crews, we had concerns about how well process safety and well control issues were being managed. So we created a program with independent inspection of well control equipment. We also independently assess the crews’ well control capabilities, and we may actually do training on site.

We roll all that into a single program where one company can assess the equipment, assess the crews and/or train use of the equipment or train crews in the basics. The operator and drilling contractor have to cooperate on this. Nobody can say, “That’s your problem.”

The Nafta Pila Rig #2 operates for Talisman Poland. The company has drilled three vertical pilot wells in Poland and plans to drill a horizontal well and do a frac spread in the most prospective location in late 2013. Whether in Poland or in the US, industry must continue to provide a steady stream of information and transparency, especially on issues around hydraulic fracturing.

The Nafta Pila Rig #2 operates for Talisman Poland. The company has drilled three vertical pilot wells in Poland and plans to drill a horizontal well and do a frac spread in the most prospective location in late 2013. Whether in Poland or in the US, industry must continue to provide a steady stream of information and transparency, especially on issues around hydraulic fracturing.

When it comes to process safety, do you believe industry should do more to bring in models or learnings from the chemical or refining side of the oil and gas business?

I would say the upstream companies have been trying to learn from those segments over the last 10 years. Commonly when people say process safety, it translates into either well control or well integrity – maintaining isolation between hydrocarbons and aquifers, between the surface and subsurface, over the life of the well.

Because well control has historically been such a key issue, we already have many of the things that good process safety requires. However, there are subtle things we need to be aware of. For example, we’re very experienced on the personal safety side about learning from incidents and applying those learnings to improve our practices. But in process safety, you actually have an absence of incidents. You have to constantly look for what could go wrong and constantly think, “What am I going to do to keep it from happening? How can I be absolutely certain that it’s in place?”

Things also have to be done in such a manner that a human error, while it may trigger an event, the mitigations, processes and redundancies have to be adequate so that it doesn’t escalate or get out of control.

On one side, industry is undertaking a broad range of initiatives to take both personal and process safety to the highest possible levels. On the other side, we know that easy oil is gone and drilling complexity is increasing even as global energy demands continue to ratchet up. How do you balance the need in your organization for operational integrity against the need to effectively manage project costs and time?

Since the inception of the business, there’s always been a pressure on cost and schedule, and that will always be there. The challenges that today’s drilling professional faces is twofold. These cost and time pressures have become very large – we are talking about million-dollar a day spreads on wells and billion-dollar projects. While the pressure’s always been there, it does seem to be mounting.

In addition to that, wells have become more complex, so you end up with a riskier environment. It can be sometimes difficult for drilling professionals to quantify these risks, which can be very subjective, and then translate those risks in a way that it is apparent how to offset those pressures. The math of course is very simple – it is absolutely clear it’s a million dollars a day.

When you start talking about some of these very subjective risks and a very, very rare event, it can be difficult for drilling professionals or business managers to make those things make sense. Both business leaders and drilling professionals need to recognize that there is immense pressure on the drilling community because of these costs and consequences, and for the drilling community to recognize that there are major business consequences for either failing to manage the risk or communicate the risk.

Moreover, some of the traditional tools don’t lend themselves that well to doing this, so this is back to the whole concept of process safety. Sometimes managing risk is very subjective, so you have to be able to identify those risks and identify how you’re going to manage the risks and keep on top of them in a very dynamic environment.

As our operations move into people’s backyards, as the consequences of failure keep growing, as the business stakes keep growing, communicating these risks at the senior drilling manager’s level probably is becoming equal to the technical aspects of the job.

The drilling industry has invested significantly in a large number of advanced-technology newbuild rigs in recent years, whether it’s drillships and semis for deepwater drilling or highly mobile, AC-power, high-horsepower rigs for horizontal drilling in the shales. How do you feel these new rigs have helped operators to improve drilling efficiency and what further improvements would you like to see on the rigs of tomorrow?

Rig equipment improvements for onshore have been going for easily 10 yeas or longer, and we’re seeing good results. Investments in new rigs and new rig capabilities have largely been successful and well adopted by most operators. If it’s a higher dayrate, they can generally equalize the performance into it.

Offshore rigs have addressed problems related to efficiency and reliability in deeper water depths and challenging operating conditions. The next level of changes on the rigs, on the deepwater side, are around improving the BOP system reliability, and I think there’s still room for getting the most out of dual-activity systems.

Of course there’s also a lot of work going on right now with dual-gradient systems and managed pressure drilling. We had a very positive experience recently with managed pressure drilling on our first deepwater well. The system was outfitted on an older rig, the Transocean GSF Explorer, but it was very robust and it worked very well once hooked up, and it enabled us to drill a very difficult well offshore Indonesia.

Talisman Offshore drilled its second deepwater well, offshore Sierra Leone, with the Stena DrillMax. The well came in at single-digit NPT and was a first-quartile well.

Talisman Offshore drilled its second deepwater well, offshore Sierra Leone, with the Stena DrillMax. The well came in at single-digit NPT and was a first-quartile well.

What role do you see MPD play in the future of deepwater?

I think a system, much like the one that we utilized that doesn’t require major rig modifications, will be the next step. The concept of managed pressure drilling, a closed system, is an exceptional technology, particularly for offshore. We used it both from a well control and a drilling capability standpoint.

What other deepwater drilling plans do you have?

The Indonesia well was finished in November 2011, and we’re now finishing up our second deepwater well offshore Sierra Leone.

How are the challenges drilling offshore Africa different from drilling in deepwater Southeast Asia?

The subsurface environment offshore Indonesia was much more challenging. It was predicted to have a very narrow pore pressure margin, which turned out even lower than we expected. Without managed pressure drilling, we wouldn’t have been able to drill the well. It was also anticipated to drill into carbonate, which might have lost all returns, so the managed pressure system would enable us to manage that problem.

Overall the subsurface environment was less challenging in West Africa, where the challenges were more logistical and getting the operations set up. The subsurface environment for the deepwater well was probably as simple as it gets.

Over the past couple of years, we’ve seen a growing trend of deepwater rigs with two subsea BOP stacks. Where do you stand on the value of having a backup stack on the rig?

This is an area where I might find myself not necessarily in the mainstream as other operators. That trend was partly driven by the higher downtime on control systems and the BOP systems themselves, and I would have preferred to solve that problem by making the current systems and stacks more reliable. If you think about a BOP’s primary purpose, reliability is the fundamental goal.

There is definitely a business case for a second stack when you talk about not taking downtime, having more time to do maintenance and making sure the maintenance isn’t done under pressure, but I still would have preferred the industry focus more on system reliability first.

The same thing with the proliferation of capping stacks. If you look at the amount of resources that were put into a dozen capping stacks – and I really hope I don’t live in a world where there are two or more in use at any one time – I wish that amount of resources had been poured into fundamental well control training. Talisman does subscribe to a system, and definitely every operator that takes on a deepwater well should have that capability and access, but probably half a dozen would’ve been adequate.

I just think training would’ve been a better use of those scarce resources.

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