CATEGORIZED | 2013, January/February

On US land, rigs have made great strides; safety must follow

Posted on 30 January 2013

BHP Billiton works with contractors to improve HSE standards as it kicks operations into high gear across North American unconventionals

By Linda Hsieh, managing editor

web_Cardno_Derick_208Derek Cardno is vice president of drilling for BHP Billiton Petroleum, responsible for the company’s global drilling and completion activities.

Since the 2011 acquisition of Petrohawk, BHP has significantly stepped up its onshore operations in US unconventional plays, with the Eagle Ford, Permian, Haynesville and Fayetteville being focus areas. What are the main challenges you are addressing in the shales?

For us, it’s improving personal and process safety across our North American shale business up to the same standards as in our offshore business.

In our fiscal year 2013 (1 July to 30 June), we expect to drill more than 400 wells on US land with 45 rigs on contract, and we see that safety performance overall lags our offshore business significantly. On land, we see a greater tolerance for risk and taking chances rather than following a structured way of working.

How are you approaching making improvements on this front with your contractors?

Certainly we at BHP have to raise the standards and expectations required of our company supervision as well, and that will flow all the way down to drilling contractor senior supervisors and crews and service companies.

We see a real commitment from the contractors we’re partnering with to raise the standards of how they work because we’re actually supporting them to do things right. In most cases, the contractors have the procedures and processes in place. Where they don’t, we’re working with them to develop them.

Besides getting the right procedures and processes in place, does the land industry have the equipment and technologies to support them in improving safety?

We see great strides in equipment. We have features on our land rigs that we don’t have on our fifth-generation deepwater rigs. This shows some great willingness from drilling contractors to develop equipment that will improve our well efficiency. I would like to see more of this mindset in our offshore drilling contractors, too, to design the rigs with full thought of the whole well construction process. For example, there are no deepwater rigs that have sufficient racking capacity to do everything we want to do, which is a real shame.

We also recently contracted a sixth-generation deepwater drillship with two subsea BOP stacks. That will be a requirement for us going forward. It’s now taking 10 to 21 days to service and maintain a subsea BOP stack in the US Gulf of Mexico, which means dead time during which we’re not moving the well forward. We know we have to do that level of servicing and testing between wells. How do we do it more efficiently? How do we adapt the equipment so we handle it more efficiently? How do we make the process more routine, more repeatable, more predictable?

We’re not going to compromise integrity for efficiency, but we’re always looking for more efficient ways to do it.

Going back to the land business, with the hundreds of wells you’re planning to drill in the US shales this year and the dozens of rigs on contract, I’m sure that one of your challenges is reducing the time from spud to spud. How are you approaching that?

One of our biggest challenges is getting our rig moves consistent. All of our rigs are capable of being moved efficiently, say in 2.5 days, but we don’t see it happening consistently across our fleet.

Some of it is just not having a good detailed plan. If a particular rig type was moved in 2.5 days in the Eagle Ford this week, then why isn’t an identical rig
5 miles down the road being moved in the same amount of time? Are we doing it exactly the same way as the one that just did it really efficiently? We’re applying that same mindset to every aspect of the well construction process, i.e., there is only one best way to do something, so let’s find it and quickly apply it across our entire operation.

We have now begun breaking down the well construction process into its phases and measuring our performance in each phase to find where we need to improve.

BHP expects to drill more than 400 wells on US land in fiscal year 2013, with 45 rigs on contract, all AC-power units. New-generation land rigs provide the ability to automate drilling parameters with surface equipment even beyond what offshore rigs can do, said BHP VP of drilling Derek Cardno.

BHP expects to drill more than 400 wells on US land in fiscal year 2013, with 45 rigs on contract, all AC-power units. New-generation land rigs provide the ability to automate drilling parameters with surface equipment even beyond what offshore rigs can do, said BHP VP of drilling Derek Cardno.

How does drilling automation factor into what you’re doing in the shales?

The AC-power rigs are huge assets for us; all 45 of our rigs are AC, and 41 of those will be newbuilds. We’re also putting together an operations support center to monitor our wells 24/7. We believe that will really help us reduce trouble time and continuously optimize our drilling practices.

We now have the ability to automate our drilling parameters with surface equipment – we can’t do that on our offshore rigs, at least not to the same extent as we can on our land rigs.

Is that because the offshore environment is more complicated?

No, the features just haven’t been designed into the rigs like they have on land. There’s much more of a mentality with the onshore drilling contractors of building rigs to make hole than there is with deepwater rigs. Deepwater rigs are built more to cope with the high loads and the bigger capacities required for big wells, but there’s not as much thought going into how we’re going to make hole, like there has been on land rigs.

How can offshore contractors change, perhaps in their mentality if not equipment, to help operators in the process of making hole?

When I started in this business 29 years ago, drilling contractors were a lot more interested in our wells than they are now. They were more interested in what equipment we’re using, what bits we’re using, what BHAs we’re using, what parameters we’re running.

They were much more concerned about how we drilled our wells than they are now, and that’s something we’ve been pushing with our drilling contractors since Macondo. We’d like to see them take an interest in our well design and take an interest in how we’re actually executing the well because it’s healthy for both of us. We want the drilling contractor pushback. We want the challenge on, “Hey, why are you doing this? Timeout, we don’t like it. Let’s talk about it.” That’s healthy for our business.

That’s not a perspective I hear very often. Usually it’s more of a “You stay out of my business, and I’ll stay out of yours.” So when is this contractor input most appropriate? Just during the drilling operation phase or even before it begins?

Yes, during the planning stage as well. Come and be involved in the planning stage and speak up. Drilling contractors used to have drilling engineering capability, but most of them don’t really anymore. They have rig engineering capability but not drilling engineering capability.

Other than drilling contractors, how are you working with equipment suppliers and service partners to improve equipment uptime and reliability?

Equipment reliability is still a big challenge in our onshore business, particularly with directional drilling tools. We see poor reliability across the board with motors and MWD tools – reliability levels that we’re not used to seeing in our offshore business.

Yes, compared with deepwater, US land is a tougher environment because we’re building short-radius wells so there are higher doglegs, plus there’s more vibration, generally harder rock and higher temperatures like in the Eagle Ford and Haynesville, but also we don’t see the same level of maintenance or effort put into improving quality.

What kind of improvements would you need to see in the reliability of rotary steerable tools before you will use them in your US land wells?

We use them a little but not nearly as much as we’d like to. We see that as a real potential to make a step-change in performance, but right now, the pricing and reliability are not making it attractive.

If I look forward to how industry will drill shale wells five years from now, I would love to think that we will be drilling them with rotary steerables. But with current pricing, we need to be able to drill a lateral section in less than two days to make them cost effective, and we’re not close to that level of performance on average yet.

So even using the rotary steerable doesn’t make that much of a difference in the time to drill the well?

No, it can. We’ve seen it in the Fayetteville where, if used properly, it does make a difference, but then the tool comes out destroyed and we end up buying the tool.

Right now, we’re using them only when we’re unable to slide in the lateral. We have 30 rigs running in the Eagle Ford, but only one at any one time is typically running a rotary steerable. I’d love to see them on all 30 rigs.

On the completions side, it seems industry can drill very impressive wells, but sometimes our completion capabilities still lag behind our drilling capabilities. What challenges do you see on completion side of your operations?

We’re definitely still learning. Our recovery factors in the shales are still single-figure percentages, so there’s a huge potential to extract more hydrocarbons out of the rock. Completion technologies will have to continue to evolve, so that’s an area where we’re putting a lot of focus.

At BHP, we’re forming a shale technology group to study all aspects of shales but with a heavy focus on completion technology. We want to be smarter about how we complete the well.

The same way that we’ve contracted a small number of drilling contractors to help improve our drilling operations, we’ve contracted a small number of frac companies so that we can work closely together to drive standards and performance on our frac operations. We’re working hard to eliminate steps in the completion process where possible, eliminating the need for preps and drill-outs.

We’re also looking at whether we’re treating the sweetest spot, whether we’re being selective about the placement of our fracs, using the best proppant type for productivity and longevity. We have a lot more work to do.

Another challenge we see is the lack of innovation in workover rigs. Some of our worst accidents have been on workover rigs, and it’s partly because there’s no room for people to get out of the way on a very small rig floor. Right now, we’re working with a contractor to test a new workover rig design that eliminates the need for people to be on the rig floor while we’re tripping. The only time you’ll need to be on the rig floor is for handling BHAs. It’s all mechanized.

We’re actively trying to reduce the requirement for crews to be on the rig floor on our workover rigs.

When and where do you expect to start using this new-design workover rig?

We’ve already completed a couple of wells with it in the Fayetteville, and we’re working with the contractor to make improvements that we’ve identified.

What are the biggest completion challenges on the offshore side?

In the deepwater Gulf of Mexico, getting the sand face completion right is critical for delivering the best producing wells. We’ve been very successful at that with our production wells in deepwater, but we’re finding that our water injectors are far less tolerant to any completion debris, and we’re working hard to fix that.

Getting smart completions to be reliable at the depths we work at will be huge. Right now, we avoid smart completions wherever possible because we just don’t see the reliability where it needs to be. When it costs $50 million to intervene on a well and fix a non-functional downhole valve, that is clearly not good business.

The Transocean GSF C.R. Luigs, operating in the Gulf of Mexico, is contracted to BHP Billiton into 2014. BHP says that it will likely require dual subsea BOP stacks for all of its deepwater rigs going forward. Further, they would like to see future offshore rigs designed with more thought of the full well construction process.

The Transocean GSF C.R. Luigs, operating in the Gulf of Mexico, is contracted to BHP Billiton into 2014. BHP says that it will likely require dual subsea BOP stacks for all of its deepwater rigs going forward. Further, they would like to see future offshore rigs designed with more thought of the full well construction process.

Have there been any new or emerging technologies that you’ve seen that could be breakthroughs in your operations?

There are a couple on land. One is wet shoe technology, where it eliminates the need to prep the well with a coiled-tubing spread before we start the frac, so you can move the frac spread on immediately after the big rig leaves. This eliminates a step in the process. We’re also close to trialing sleeve technology that eliminates the need to run perforating guns.

There are other technologies that service companies are working on that will help to reduce cycle time on our land wells.

For offshore, I think there’s still a big challenge for BOP manufacturers, and I know they’re working on it, to improve the capability of their shear rams. The ability to shear anything and everything that we put in the well, including heavier-wall drill pipe and tooljoints, is something we need as an industry.

With the deepwater Gulf of Mexico and Australia being your focus areas in 2013 and likely beyond, what technologies and equipment are on the top of your priority list for the efficient development of those areas?

In Australia, the rig fleet has typically been populated with old rigs in variable condition. It would be nice to have a long enough continuous program that justifies mobilization of more modern iron.

For the Gulf of Mexico, it’s all about the rig technologies. The new drillship we’ve contracted has 2.5 million-lb load path and two seven-ram BOP stacks. They are the two critical reasons we upgraded.

Our CEO made a commitment that he was going to give us the best iron that we can get so that we can be the most successful we can be, and that applies to both our offshore fleet and our land fleet.

In the Gulf, we recently finished drilling a 34,000-ft exploration well, and we had to match our well design to the capability of the rig. This means we had to run a liner and tie it back to our intermediate casing, which added a lot of complexity and cost to the well.

With our new drillship, we would’ve run that casing string in one piece because we would’ve had the load path capability to do it.

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