Repsol looks to managed pressure drilling to drill safer, more efficiently from floaters in West Africa, Brazil
By Linda Hsieh, managing editor
Repsol has an ambitious strategic plan, announced in 2012, to grow production by 3-4% per year to 2014 and higher to 2019. What types of innovations in terms of drilling/completions will be critical tools to help you achieve this growth?
In my opinion, managed pressure drilling (MPD) is probably the single biggest technology out there that I would call a game changer, in the same way that horizontal drilling has been for the resource plays. When you get offshore and you’re spending at least $1 million a day or more, you need something that gives you a technical edge that will help you get to where you need to go. I believe managed pressure drilling is the technology that will provide that edge.
I think in five or 10 years even the offshore industry will be using MPD technology to do things faster and better than what we are now.
Will industry be using MPD in routine, everyday operations?
I think so. It’s like horizontal wells. Twenty years ago the industry thought a 500-ft horizontal well was an accomplishment. Now we are drilling more than 10,000 ft horizontally. We are successfully completing multistage frac jobs and making much more prolific wells than they did 20 years ago.
So, yes, I think in roughly 10 years, managed pressure drilling will be everywhere, especially in deepwater.
The biggest issue with using managed pressure drilling offshore is getting the correct tools built into the rig and the riser system. Repsol recently contracted two deepwater drillships, the Ocean Rig Mylos and the Rowan Renaissance.
The Rowan Renaissance, which is a newbuild that will be going to West Africa in February 2014, has all the managed pressure drilling equipment completely built in. For the Ocean Rig Mylos, which will be going to Brazil in the third quarter of 2013, we are having to do some work to fit it out to use managed pressure drilling. The wells in Brazil are very challenging, and we feel like managed pressure drilling is necessary to get the wells drilled cost-effectively.
Rowan had already decided to outfit the Renaissance drillship with MPD equipment before it was contracted to Repsol. Did that factor into your decision to contract the rig?
Yes, that was part of our evaluation matrix when we evaluated the rig tenders.
The primary contract term is for three years. Do you expect to use the MPD equipment on the rig for all three years?
There might be one or two projects that are more applicable and one that’s less applicable for MPD, but the beauty of it is, with the equipment already there, it will be ready to go and it won’t be a big cost implication if we use it or don’t use it.
We’re still early in the process because we won’t be spudding for a year and a half, but, yes, we’re planning to use managed pressure drilling to drill these prospects, both in West Africa and Brazil.
Even though the Ocean Rig Mylos will not come equipped for MPD, Repsol has decided to retrofit it. How will the added equipment improve the Mylos’ drilling program in Brazil?
In Brazil there’s a zone with very significant lost-circulation issues. We have to lighten the mud up to where we can have returns and still monitor the pressure at the surface. MPD allows you to drill within very narrow windows of pore pressure and frac gradient. MPD is a tool that allows you to do that, and it’s getting a proven track record all over the world. We just need to get more MPD experience on floating rigs.
Currently, there are still not very many floating rigs with MPD equipment.
Do you believe industry will start to see a trend toward floating rigs being equipped for MPD in the shipyard as they’re constructed, as the Rowan Renaissance was?
Yes, we are already starting to see more rigs coming out with MPD. I think this will continue because the incremental cost to install MPD equipment is relatively small when you do it in the shipyard. If we look at contracting another floating rig, MPD equipment would be something we would look for.
Would you pick a rig that comes standard with MPD equipment even if it came with a higher dayrate?
We would have to look at the economics. When we evaluated the tender for the Renaissance, we looked at how much it cost with MPD equipment and compared it to other rigs that did not have MPD equipment. We then had to estimate the amount of time and cost involved with adding MPD equipment to a rig that was not planning to have it installed in the shipyard.
I think MPD will give contractors a competitive edge. In five or 10 years, depending on the market condition, if I had a choice of two rigs with similar dayrate, I would pick the one with MPD, because it gives me a technical edge. Going forward, I believe the majority of newbuild rigs will have some type of MPD equipment.
Earlier you mentioned that you believe MPD will become prevalent, especially in deepwater. Why deepwater?
A lot of my experience has been in the Gulf of Mexico. I’ve seen projects where you couldn’t get casing seats as deep as you’d like, but with MPD I think you might be able to push these casing seats deeper. MPD would allow you to put a larger-size casing across productive zones by allowing for higher flow rates and higher return on your investment. MPD should also reduce nonproductive time.
Lost circulation below salt is a major issue in Brazil. I believe MPD will help us manage the very small frac gradient and pore pressure window. I know the technology is applicable in the Gulf of Mexico and Brazil, and I think it will be applicable in Angola as well.
Do you think industry will run into challenges as far as convincing regulators in different parts of the world that MPD is a safe, or possibly even safer, way to conduct drilling operations?
I expect the industry will need to demonstrate the safety of MPD technology to all of the different countries where it is used. The operators will need to provide our formal hazard identification and risk assessments to the different regulatory bodies to demonstrate that we understand the risks and can safely manage them.
It’s the operators’ job to demonstrate to the government that MPD is a safe technology. I personally believe that if you manage it correctly, it’s a good and safe technology.
In order to manage this technology correctly, it seems like a key factor will be ensuring proper training of the crews so they understand how to drill at balance rather than drilling conventionally, right?
Absolutely, because although the equipment and systems are sophisticated, with a lot of computer sensors, the most important element is the human factor. Everything relies on the skill and training of the operators. It is essential to invest in comprehensive training programs for the crews.
In Brazil’s Campos Basin, Repsol announced a major discovery in 2012 with the Pão de Açúcar well, which had two of the thickest accumulations discovered in Brazil to date. What are some of the biggest challenges you’ve encountered drilling in the pre-salt blocks?
Loss of circulation below the salt is a big technical problem. You basically have high-pressure salt that’s open and a lower-pressure formation below the salt that is also open. You have the potential to lose tens of thousands of barrels of fluids. Like I said, managed pressure drilling can help us manage those losses and get the right-size casing across the pay interval.
MPD is very important for our delineation program in Brazil. It’s the only high-level technology I can think of right now that can significantly change the game.
Quality control for drilling tools is also a major issue in Brazil. Every operator needs a robust QA/QC program in place to ensure that their rigs are not shut down due to tool failures.
At the IADC World Drilling 2012 Conference, Repsol executive director of exploration and production Luis Cabra Dueñas gave a keynote address where he strongly urged industry to work on improving its social image. How do you think industry is doing on that front and how do you think we should approach this task?
The industry needs to eliminate Macondo-type events. We all know the PR challenges that the oil and gas industry faces. Whenever a major environmental and/or safety event happens, it sets the industry social image back 20 years. The best way to improve our image is to eliminate safety and environmental incidents.
How can industry try to prevent such events? By improving our operational integrity?
Most operating companies, big or small, are enhancing their internal processes to help ensure that another major environmental-type event does not happen.
Repsol formed the Global Drilling and Completion Group two years ago. Our No. 1 priority is to ensure wellbore integrity is maintained during the entire well construction process. We work with our different business units to ensure that our wells have been designed properly and that the well designs meet our internal wellbore integrity standards. We set up our Global Drilling and Completion Group to ensure that we are doing the proper things from a well construction standpoint and to ensure that we have good well integrity and that robust procedures and processes are in place. We are also re-emphasizing training to ensure all business units are following the processes correctly.
Three years ago a lot of companies didn’t have the robust internal reviews and policies that they have today. I think you see most medium and large operators now have a more structured and formal wellbore integrity review process to prevent significant safety and environmental events.
Industrywide, from your experiences in the industry, do you personally see a widespread change in how people are approaching well control?
There’s not a company I know of that has not asked themselves, “Are we addressing well control the right way? Do we need to rethink this?” The entire industry looks at well control differently than they did three years ago.
When we know the need to maintain operational integrity is so high, how do you aim for that level of integrity across your global operations while simultaneously managing project budgets and schedules?
The cost structure in Brazil and Angola are staggering; it’s hard to comprehend. When you start combining all of the country costs onto one well or one project, your spread rates are well over a million dollars a day, all in.
The only way drillers can decrease the well cost is to take fewer days to drill it. At the same time, we will not rush things because we can’t tolerate any mistakes. So, you need mature, strong teams. People are the key to success, so you must ensure that they are highly trained, and you must have robust processes in place and ensure the wells are properly designed.
It sounds like you view people as the key factor to success. How is Repsol investing in people?
Repsol is relatively new to the deepwater environment. One of my jobs over the last five years has been to help build a core team of experienced engineers, superintendents and technical staff.
About seven years ago Repsol established a masters program in Madrid. We hire a lot of mining engineers, mechanical engineers and industrial engineers from Latin America, Europe, the US and send them to Madrid for a nine-month program. They’re actually on staff when they’re going through this internal masters program.
They spend nine months learning geology, geophysics, petroleum engineering, drilling engineering, production engineering – it’s a very interdisciplinary curriculum. They’ll also spend a month at Heriot-Watt University in Scotland. Then they’ll go to the field in Oklahoma. The students work through an entire field development on a large field that Repsol has an interest in. They use actual geologic, geophysics, drilling, production and reservoir information as they go through the development scenario.
Our masters program gives young engineers and geoscientists the opportunity to work together and understand the interdependencies between the different disciplines, which is a unique and advantageous training program.
We’re graduating about 50 students a year, and now that the program has been going on for about seven years, we’re starting to receive some meaningful returns. We have a lot of sharp young engineers and geoscientist in our personnel pipeline.
A big challenge to having a great group of young professionals is that you have to retain them. Repsol works hard to keep our compensation competitive and our staff technically and professionally challenged.
There’s been an increased focus on process safety in the drilling industry in the past couple of years. From your perspective at Repsol, what improvements would you like to see your drilling contractors make in this regard?
For some drilling contractors, I see that they manage process safety differently depending on what part of the world they are working in. There are opportunities to take the rigor that can be found in the Gulf of Mexico, as well as UK/Norway, and apply that to other countries.
Operators should also work to integrate the drilling contractors earlier on the safety management systems, especially in remote locations. This is difficult to do when you pick up a rig from an operator for a single well. Managing process safety with a drilling contractor is much easier when a long-term contract is involved.
Do you believe that process should be driven by operators?
The operators hold the exploration and production license. We’re the ones that are ultimately responsible for all HSE issues on a block. The operators have to work within the drilling contractor’s safety management system. Repsol is not going to go to a drilling contractor and change their safety management system; we have to integrate with them. Our job is to get in there early and identify the gaps between the contractors safety management system and our own. We then have to work together to properly bridge the gaps.
Drilling contractors have invested significantly in recent years on newbuild rigs. In the offshore space, both the floating rig fleet and the jackup fleet have been renewed with new-generation, advanced-technology units. How do you think these rigs have helped operators to improve their drilling operations?
The “multi-activity” capabilities on rigs is helpful. If you can build casing stands and have them ready while you’re drilling ahead, that’s a huge advantage when your spread rate is over $1 million a day. We have to work very closely with the drilling contractor to exploit the rigs’ capabilities, whether offshore or onshore. Although onshore drilling has a lower daily spread cost, rig efficiency onshore can impact the economics of a project as much as the more expensive offshore rigs.
Another example is the dual BOPs. The Rowan Renaissance will come equipped with two BOPs. The Ocean Rig Mylos will come with one BOP, but we’ve elected to install a second BOP prior to the rig starting work in Brazil.
BOP testing and inspection requirements are different in the Gulf of Mexico versus the North Sea versus West Africa versus Brazil. The value of the second BOP varies depending on where you’re operating.
Although the value of a second BOP will vary depending on where you are operating in the world, Repsol has made the decision that we want dual BOPs on both of our new drillships.
Is saving downtime the biggest value you see in having the backup stack?
Yes, but you must ensure in your contract that when you have two BOPs that both of them are up and 100% functioning and that the drilling contractor has adequate staff onboard to manage two BOPs. BOPs are very complex pieces of equipment, and if you don’t have the adequate staff to manage two BOPs, then you’re losing the advantage of having the second stack.
Understanding the methodology for the control systems for the two BOPs is important. There are differences in the way contractors set up the second BOP, so a lot of homework needs to be done to ensure there is clarity between the contractor and operator.