Technology is key to mitigating drilling hazards
Critical D&C issues with Carel Hoyer, Weatherford International
By Linda Hsieh, assistant managing editor
Carel Hoyer is Weatherford group vice president – drilling hazard mitigation and pressure pumping.
DC: Technology-wise, what do you see as some of the most critical issues facing the drilling & completion industry today?
Hoyer: For the vast majority of wells drilled today, the limitations don’t lie in the technology; they lie in the finding, accelerated training and retaining of technically competent personnel to exploit those technologies that have already been developed during the past decade.
DC: Are you seeing companies less willing to try new technologies because of the softening market?
Hoyer: Whenever there is a downturn that is as sudden and severe as what we have seen lately, the tendency is always to become more conservative. In addition, for a lot of the smaller companies, it is a matter of survival and, as such, they will not be able to push the technical boundaries as much as they might have liked. Historically, these companies, as they need to differentiate themselves more, have been very supportive of trying out newer techniques earlier in their evolution. That said, technology will ultimately lower well costs, and thus we are still spending more on R&D to meet the industry’s needs in its more challenging environments.
DC: Will the weakening market affect industry’s ability to recruit and train?
Hoyer: Most employees prefer careers with stability and personal growth. Look at how the price of oil has dropped by two-thirds over the last four months. You have to have a special kind of employee who is willing to put up with those kinds of swings – to endure the kind of feast/famine we have in this industry, plus put up with “call-off” work, being away extended periods from home usually in high-risk places, etc. Having said that, I know of no better job out there if you like a challenge and some diversity.
DC: Have we learned lessons from previous cycles so we don’t repeat our mistakes?
Hoyer: Personally, I think the more we learn about the cycles, the faster we all react and amplify the problem. It wasn’t too long ago when $50 oil generated great earnings for most. But now, those who are too leveraged have to shut down. Even national operators are slowing down some activities and programs a lot earlier in this cycle than in the past.
DC: What can service companies do in the face of companies unwilling to try new technologies?
Hoyer: My title highlights some of the new technologies we’re working on – those that address drilling hazard mitigation. With the average well, over 30% of the final costs are related to nonproductive time or unanticipated events. We’ve been working on finding novel solutions to help the client optimize and ultimately reduce overall drilling costs and time on location. Some examples are controlled pressure drilling, solid expandable systems and drilling with casing.
DC: How are you using these technologies as solutions for “drilling hazards”?
Hoyer: For example, if a client wants to get to Point X in a well, but 200 feet from Point X, they encounter hole issues – perhaps lost circulation. Historically, they might pump cement plugs or mud/chemical pills. Then they’d continue drilling and 5 feet lower, might encounter losses again and start the whole process over.
What we’d potentially recommend, if you’re only 200 feet from bottom and the drilling is not too hard, why not pull out of the hole with the drillstring, put a drill shoe on the casing, run down, and for the last 200 feet, drill with the casing?
We’ve seen numerous instances where drilling with casing helps cure lost circulation because the drilled cuttings are ground up more than in conventional drilling, and they have a tendency to pack off and create their own filter cake. Even if it doesn’t totally cure lost circulation, you already have the casing down there.
DC: You’d have to be pretty specific to show clients the benefits of these niche solutions.
Hoyer: Yes, and we’ve been going through a huge educational campaign, both internal and external. Most people like widgets, but the ultimate challenge is to find the right tools/techniques – in other words, solution – for the circumstance. Thus, people have to have a more well-rounded background and training to recognize and package the best solution from all the products and techniques already out there.
DC: Is taking baby steps one way for new technologies to gain a foothold in a market where people would like to minimize risks?
Hoyer: It is usually beneficial if we learn to crawl before we run. It lets people get more comfortable with all the issues. As an example, install a solid expandable casing patch first and then maybe attempt an open-hole patch before installing a 3,000-foot open-hole liner through a window in a sour environment and cementing before expanding.
DC: What are some technological breakthroughs or advances Weatherford has made in the past year?
Hoyer: We’ve commercialized a whole MPD portfolio of products and will introduce more in 2009. The MetalSkin monobore open-hole clad liners and monobore well projects have been commercialized. Certain clients have supported riserless drilling of the subsea conductor verses pile-driving or circulating it to depth. We believe that operators will be able to potentially set the conductor a lot deeper and reduce one or two strings, giving them more risk insurance later in their well profile, plus saving some costs.
DC: What are the advances involved there and what are the benefits?
Hoyer: Drilling with casing traditionally has been intermediate hole or through the reservoir. Onshore it’s been done from surface, but usually smaller hole. Conductors are usually circulated or pile-driven into the seabed. Clients are finding, especially in deepwater, that they would like to set their conductors deeper. That would allow them to potentially save one or two casing strings. This means that either they can start off with smaller casing and therefore save on drilling costs, or they could have more remedial options later in the wellbore if something goes wrong. One operator recently abandoned an offshore well where they’d spent more than $150 million drilling because they ran out of casing string ID required.
DC: How much deeper can the conductor be set?
Hoyer: Potentially up to thousands of feet deeper. It all depends on geology and the casing drill bit that is selected.
We already drill with casing, and we drill in liners. The only difference is, we’re going to hang it off of, say, 3,000 feet of drill pipe and have no riser to surface. So we will have to take into account things like ocean currents. This is taking existing technologies, packaging them in a different way and allowing the rig to do something it has never contemplated doing before.
DC: What’s another such example of using existing technology to do something new?
Hoyer: Solid expandables is letting us extend the reach of wellbores while maintaining hole ID. With monobores, initially the idea was to drill a hole from surface to bottom all with one ID. In a perfect world, maybe. The question then becomes, is that really what is required or just a great technical feat? The technology presently is moving towards using it to solve drilling or workover challenges. In a previous example I gave of drilling and being 200 feet short of TD, instead of drilling with casing, another solution may be to set casing 200 feet high with an expanded shoe, and set a monobore over the remaining 200 feet once drilled, thus not losing one hole size.
DC: Do you believe the industry already has all the technologies it needs to address nonproductive time and drilling challenges?
Hoyer: We have a lot of technologies. Do we have all of them? No. The oilfield is an evolutionary business, versus revolutionary. By working with clients, we can often package various technologies into something unique that will address their problems in a cost-effective manner.
DC: Do you think operators can see the value of these higher-cost technologies even when oil prices are falling as they are?
Hoyer: We just drilled a well in the Middle East that was previously “undrillable.” The client had tried numerous times before and never got to the producing zone. So we worked with them on a managed pressure drilling campaign, and we got to the zone of interest and had a very prolific well. In that case, there was no option – they couldn’t drill the well using conventional technologies no matter how much money they spent. They had to step outside their comfort factor, and now they want to exploit that technology across a wider footprint.
MPD is not new technology – it’s been around since the ’80s, and this goes back to your first question. Only in certain extended-reach, highly complex or extremely high-temperature wells are there present technology limitations. But there’s a lot of technology out there that we, as an industry, are not exploiting.
DC: Is economics keeping companies from exploiting these technologies?
Hoyer: Unfortunately, any new technology, because of its reduced utilization, is inherently more expensive initially until utilization picks up. Service companies live and die by utilization. Until we get to a critical mass and have the technology debugged, costs will be higher.
DC: How long might it be until we see technologies like solid expandables, drilling with casing and controlled pressure drilling reach critical mass?
Hoyer: Those technologies are in different parts of their technology evolution curve. MPD is further along, while solid expandables and drilling with casing are almost at the beginning of the curve. Every day we’re seeing new applications for each of these services.
DC: Do you think that works to help service companies to expand their own product lines too?
Hoyer: Yes and no. The challenge is that service companies would love to go after the juicy part of the technology and get critical mass and volume, then start looking at the one-offs in remote parts of the world. Every solid expandable, for example, presently takes a lot of engineering horsepower. To date, we have spent more money on research within solid expandables than we have made in revenue.
DC: Operators face the challenge of increasing net recovery rates from their fields. How can service companies help them?
Hoyer: In the Middle East, we revitalized a large number of existing wells in a couple of fields whose performance had declined. Some of those wells had been producing at as much as 10,000 bbl/day but presently were not producing at nearly that rate. The campaign was to revitalize these wells by drilling horizontal laterals from vertical wells, resulting in moving the field’s recovery rate closer to 50%. This involved re-entry and horizontal drilling, and we used solid expandables to maintain hole ID and integrity and to keep production high. Now we’re accessing the bypassed reserves that were behind the vertical wellbore.
Ultimately, the client would like to get recovery up to 75%.
DC: Will that be possible?
Hoyer: Not everywhere. In certain situations, yes. Some people say there is more oil lost behind existing casing than new oil to be found. To tap that oil, it will require a whole family of products, from better logs, to directional or horizontal technology, to better completion technologies and the people to exploit them.
DC: Going back to MPD, there seems to be many interpretations of managed pressure drilling. How do you define MPD and how it should be used?
Hoyer: There are four variations of MPD, and each form addresses specific drilling hazards. Some people have confused MPD with UBD – perhaps in part because both technologies use some of the same equipment, like rotating heads.
The IADC UBO & MPD Committee recently clarified the definition of the two. UBD focuses on improving the productivity of the completed well by inviting reservoir fluids to surface during the drilling process. The basic concept is that no foreign fluids touch the reservoir while drilling. MPD focuses on the drillability of the well by drilling overbalanced more precisely than achievable with conventional methods and means.
Relative to benefits and risks, compared with conventional drilling, both UBD and MPD have established a commercial track record onshore and offshore of providing significant measurable benefits to drilling programs by reducing or eliminating a litany of drilling-related risks. Moreover, drilling a closed mud system offers an inherently smaller HSE risk than drilling with a conventional system that is open to atmosphere immediately under the rig floor.
DC: Do you see many companies still confused by the different variations?
Hoyer: There’s still an educational process going on about which of the systems available makes the most sense for their well.
DC: Moving on to rotoary steerables – several “low-cost” versions of these systems have been introduced. How do you think they are working out?
Hoyer: To date, low-cost rotary steerable systems haven’t worked very well. When they do work, they don’t replace the standard rotary steerable with respect to build rate; mean time between failure; or the ability to attach additional services to the bottomhole assembly.
DC: Are you saying these low-cost versions have a way to go before becoming reliable?
Hoyer: Well, that’s the problem. The more features you incorporate, the higher the initial cost usually is.
DC: Weatherford doesn’t have a low-cost rotary steerable system yet?
Hoyer: We are working on various iterations that should result in a simplified, more cost-effective system.
DC: Something economic for land drilling?
Hoyer: That is one of the requirements, but it’s not the sole purpose. The challenge with rotary steerables is you’re asking it to do an awful lot of things. It’s actually quite an engineering marvel. Without going into technical details, low-cost systems are like a gravity mechanism. In other words, you have a weighted anchor that swivels to the low side to give you the offset to drill in another direction. In a perfect world, it might work; problem is, we’re never in a perfect world.
DC: Overall, do you see rotary steerables, low-cost or regular, continue to grow in market presence?
Hoyer: Because most of the world’s thousands of wells drilled each year are shallow, vertical wells, the percentage of total wells drilled that use rotary steerables is low – probably under 10%. It’s different if you talk about horizontal wells. Horizontal wells are about 35% of all wells drilled. Based on our assessment of the market, we see that of all directional wells now drilled, which is about a $9.5 billion market, fully 25% are drilled using rotary steerable technology. That means the rotary steerable market is now a $2.5 billion business, whereas just eight years ago it was just under $400 million. So it’s had a huge uptake.
DC: With LWD/MWD/SWD, what are the remaining obstacles so that we can truly see ahead of the bit?
Hoyer: There are both technical and economic challenges. The only present true physical measurement that can possibly see ahead of the bit is acoustic. There are a few commercial VSP (vertical seismic profile) systems out there, but the technology has not yet caught on.
SWD, seismic while drilling, has been explored hard for nearly 20 years now, with no great success. Timing with a downhole clock is one hurdle, which may be close to being solved with accurate clocks and/or wired pipe. SWD for vertical wells using a surface source has shown practicality but can be expensive, especially if a boat is required to move a source. Not much progress has been shown at all in horizontal wells with either a surface or a downhole source for horizontal geosteering.
Currently LWD downhole seismic receivers can detect acoustic reflectors beyond the borehole, but the utilization of these systems is low because of their expense and complexity. Also, they’re not suited to thinly bedded reservoirs or poor reflectors such pressure transition zones. Electromagnetic methods are being explored but face challenges such as low signal-to-noise ratios, interference from steel drillstrings, and the need to process the raw data through complex conversion routines before providing meaningful information to the user.
Finally, there are inevitable conflicts of drilling with geoscience when it comes to placing specialized formation evaluation sensors close to the bit. Drillers usually are reluctant to compromise flexibility in configuring the BHA for optimal drilling performance and integrating sophisticated formation evaluation tools into near-bit components, such as rotary steerable tools or mud motors.
One technology that only a couple of clients are exploiting is geosteering using underbalanced drilling.
We are also using seismic effectively in non-drilling environments. We provide wireline borehole seismic imaging and fracture mapping services. This technology is well established and can provide benefits in exploration and production environments. We have also successfully installed several permanent optical seismic systems in producer, injector and monitor well completions for time-lapse imaging and passive monitoring. This technology is relatively new, but it has already demonstrated the ability to provide ongoing high-resolution images and useful information about the reservoir to help optimize recovery.
DC: Can you explain in more detail geosteering using UBD?
Hoyer: When you’re underbalanced drilling, you’re flowing the well. That’s like doing a drill stem test continuously. It’s true geosteering, not a deduction from electronic sensor readings. You drill a foot, you see its incremental production. You drill another foot, you see its production. You see the onset of water coning, the onset of gas influx, faults, etc.
DC: And only a couple of clients are looking into this?
Hoyer: Only a couple of clients have exploited this technology to its potential. It’s a lot more technical and expensive, but if you have a very complex reservoir, there’s nothing like true, hard data to correlate with your LWD info to show you how your reservoir is actually behaving.
DC: Is this technique something we will see more of in the coming couple of years?
Hoyer: With this kind of technology, the caliber of people you have on location must be a lot higher than it traditionally is. The costs and footprint are also a lot higher. Plus there is the challenge of equipment reliability because there is no traditional filter cake when we drill underbalanced. If the equipment goes down or an operational mistake is made and we go overbalanced, we do a lot more damage to the reservoir than using traditional drilling methods.
DC: So the risks are higher?
Hoyer: The risks are higher, and the caliber of people needed are a lot greater, but so is the potential payout. Weatherford is taking the approach that we should learn how to crawl and walk before running. Geosteering underbalanced is sprinting. A lot of clients still are not exploiting rotating control heads and why they would be beneficial for most of their drilling activity.
As clients get more comfortable with MPD, it will be so much easier to expand into the more technical iterations such as UBD.
DC: What trends and challenges do you see in the advancement of mono-diameter wells?
Hoyer: Again, we’re focusing here on learning to crawl, then walk. The concept of monobores was drilling from top to bottom maintaining one ID. As we do this more and more, it becomes apparent that that is maybe not the most cost-effective solution, and that you only need the monobore concept for certain portions of the wellbore that are tough to drill, or for modern requirements like ultra-extended reach.
DC: What about the technical barriers of monobore?
Hoyer: The technology is growing at a very high rate, though we’re still in the infancy of this technology. We’re basically asking steel to do something it doesn’t like doing. And steel isn’t even the main concern – it’s the threads between each joint that’s the major challenge, besides the running tools. Oil companies prefer metal-to-metal seals. We’re expanding that metal-to-metal connection up to 30% and expecting it to be still gas-tight. That’s asking a lot.
With mono-diameter wells, that concept is basically for new-drills. But people are finding that solid expandables can also be used for workovers. Earlier I mentioned the example from the Middle East where we drilled a window out of an old well and went horizontal, and used a solid expandable across the build section into the reservoir to hold open the curve and not reduce ID except for the wall thickness of the steel.
We’ve also used it to clad wellbores – in other words, create an internal skin that you could later run through with another expandable. One good example – a 50-year-old well that has severely corroded casing. Assuming that the environmental approvals, land rights and surface facilities are all there, we could run a piece of casing and expand it out so that it’s touching the old casing from bottom to top or just across perforations that can’t be squeezed. Now you basically have a new wellbore without all the traditional new well costs and hassles.
DC: One speaker at IADC’s Annual Meeting in November 2008 mentioned a movement towards simpler and therefore more reliable completion systems. Is Weatherford working on such simpler, completion systems? What does this trend mean for systems like intelligent completions?
Hoyer: We’re always working towards simpler and more cost-effective solutions. It doesn’t mean that intelligent completions are going away. We’re still spending a lot of time and money on artificial-lift techniques, optical sensing systems and multilaterals. There’s horses for courses. In other words, sometimes you need a plow horse and other times you need a thoroughbred. At Weatherford, we normally want the whole family to allow us to look at the optimal solution for each and every case.
DC: A couple of years ago, one operator interviewed for Drilling Contractor said expandable completions was a good idea but at that point still “pie in the sky.” Where does expandable completions stand now?
Hoyer: It’s no longer pie in the sky. There are a lot of clients wanting to work with us and our competitors to develop this technology faster than we can presently do due to engineering limitations. At this stage, each application has to be designed individually and local personnel trained, so it’s a huge drain on both R&D and operational engineering resources. But make no mistake, Weatherford has more than 500 expandable sand screen ESS systems installed worldwide today, and more and more new clients are showing interest.
For example, last year we repaired one of the top five operators’ most prolific gas well that had a hole in its casing. They had tried various other solutions and ended up using a solid expandable system to get the well under control. We didn’t have a system for it – we designed it, tested and proved it over a three-month period, working in conjunction with the client and their experts to come up with a solution.
DC: What technologies will be critical in order for the industry to tap important unconventional resources like tight gas or heavy oil?
Hoyer: It’s usually an evolutionary process in the oil patch. Very seldom is it revolutionary. Look at directional drilling: It is still below 50%, but the percentage grows slowly each year as knowledge picks up and costs come down. As mentioned above, we like working with operators jointly to develop fit-for-purpose technologies, and unconventionals is no different. For example, with tight gas, the fracturing industry is continually evolving and coming up with new techniques and procedures or new fluids to optimize the result. If you don’t keep evolving and optimizing, you will become obsolete.
Anything to do with well placement and stimulation will be important as well. And technologies that help reduce reservoir uncertainties are particularly relevant because that can dramatically impact a go/no-go decision for certain projects. Critical to that is an integrated formation evaluation and reservoir characterization competency (logs, cores, sampling, testing, etc), and we are actively applying these skill sets to unconventional plays.