Safer, faster, more efficient, more productive, more cost-effective and simpler interfaces top the technology wish lists of many in the offshore oil & gas sector over the next decade, as Jennifer Pallanich reveals in part two of this month's special survey.
Solving some of the offshore challenges of the future will require innovation, says Paul Jukes, president of MCS Kenny. 'We're talking about novel ideas, actual thinking.'
Simon Seaton, senior director of Halliburton's Deepwater Solutions, says, 'I think there's a perception that deepwater is all about bleeding edge technology . . . but the reality is with the high operating costs, this isn't a place to be testing things or to be learning lessons. Operators want to know that what we say is going to work. That it's going to be reliable, that it's going to be safe.'
Jay Cotaya, Exmar director of marketing, believes more technologies will be created or stretched to help the industry go deeper without getting bigger. 'If you keep making things bigger, bigger, bigger to go deeper, deeper, deeper, it's just going to get more and more expensive,' he says about working in increasingly deeper water.
Horst Moll, VP for subsea products at Aker Solutions, doesn't see water depths getting much deeper, at least in the Gulf of Mexico where the deepest spot likely to see the drill bit is 12,400ft of water. 'We might get to 12,500ft, but from a technical point of view, that's pretty easy to achieve,' Moll says.
Much of what the offshore oil & gas industry does is 'more difficult than going to the moon' and yet the engineers 'make it look like it's easy when in fact it is not at all easy', says Steve Roll, VP and general manager, Atlantic for McDermott.
Roll says the company believes offshore spending globally in the next several years will be divided roughly evenly between conventional shallow water and deepwater. Most of the challenge is posed by the deeper water, harsh environments and remote locations, he says.
'When you go deeper, you get obviously more pressure. When you go in more remote locations . . . you have logistics and logistical issues,' Roll says. 'Remote, deep, harsh, all mean more management, more challenges. The equipment of the industry has to keep up with those technical challenges.' But it will do so in a measured manner, he believes. The industry, he says, 'will learn and know its limits. When we're technically ready, then we will proceed.'
The challenges are causing the industry to improve and stretch technologies, which is keeping the industry competitive in nearly every niche. 'I think that bodes well for the industry because competition makes you strong. Having a good "sparring partner" is a good thing. Competition makes you strong and helps keep you focused and competitive. It stretches you,' Roll says.
A small stretch can be applied to any technology, Roll notes. For example, he says: 'Welding is an old technology, yet there are constantly evolving improvements in that technology. That's an example of how you balance creativity with (established) technology. We can always improve incrementally.'
Even if an innovation results in a 1% improvement on the process, it's still an improvement, he says.
'Cameron spends a lot of time and effort developing new technology in our research and development centers around the world, but it is not only about technology, it is about delivering value to our customers,' Ed Will, VP of marketing and strategy for Cameron, says
Ensco, which has the second largest drilling fleet – as well as the youngest ultra-deepwater drilling fleet – following its acquisition of Pride in 2011, is also excited about new opportunities in the shallow water market, particularly in the central North Sea. In early October, the drilling company ordered from Keppel Fels a third HP/HT harsh-environment jackup suited for 400ft water depth and able to drill to 40,000ft. Ensco investor relations VP Sean O'Neill says the decision to order the rig was 'predicated on some fairly visible demand' in the region. Last November, Ensco announced a contract with Nexen for the first of its three rigs in the ENSCO 120 series.
With the latest jackup order, Ensco has in its fleet 11 KFels jackups – three under construction and eight in the field – as part of an overall fleet of 76 offshore drilling rigs.
'On the deepwater side, there is a growing need for drillship capabilities. You're going even further out, you're drilling in even deeper waters. Drillships are better suited for that,' O'Neill says, noting strong demand will still remain for DP semis. He says he's observed an 'interesting trend' of customers not needing the water depth capabilities of some of the new ultra-deepwater semis but needing the hoisting capacity, BOP capacity and mud pump capacity of these rigs, 'so you're seeing ultra-deepwater rigs being contracted in what would traditionally be considered midwater.'
And keeping those clients happy in other ways is important, too, he notes. That comes down to safety – which is 'priority one, two and three for operators,' O'Neill says – and limited downtime for the rig. 'It's not just the day rate that they're paying. They may have other costs, for example, if we experience unproductive downtime,' he says. For the five active ENSCO 8500 series semis, O'Neill says, they experienced 99% utilization rates in 2Q 2011, or 'virtually no downtime.'
Jørn Madsen, COO of Maersk Drilling, says Maersk is focused on a service delivery model aiming to improve performance. It may be counter-intuitive, he says, since drilling contractors work on a day rate. Maersk's 'whole drive technologically is that together with our suppliers of equipment, like the NOVs and Akers of this world, our focus is on finding equipment that will run faster than traditional equipment. That means that we will invest more money in a riser package because it has clip connectors and can be deployed faster than those we have to bolt together,' he says.
Eric H Namtvedt, president of FloaTEC, the Keppel Fels/McDermott joint venture company, also sees the need for optimized drilling operations, controlling platform motions, and solving the riser connection as the chief three concerns going forward. 'Just the mere weight of stacking, pre-stacking drillpipes to meet those depths' is something the industry must consider, he says. As Namtvedt puts it, it's 'not so much the platform itself but the things that are driving the platform sizes.'
The platforms, Namtvedt notes, must be sturdier and bigger with more payload carrying capacity and the ability to handle higher air gaps and metocean forces. This is particularly true in deeper waters, with deeper reservoirs, larger drilling units, and with heavier risers needed to meet higher pressures and temperatures at depth. 'What we are seeing is the reservoir requirements for both risers and drilling are pushing the boundaries.'
He suggests the possibility of platforms that 'can be kinder to the riser systems in terms of motions' so it's not necessary to add extra fatigue thickness and thereby drive up the weight, which drives the payload, which drives the buoyancy requirements. 'There is a circle of design that is very demanding,' Namtvedt says.
Guy Feasey, the global business development manager for Weatherford's drilling optimization services, says drilling more quickly offshore is a continuing focus of the company's development effort. For example, he says, offshore Brazil, where thousands of wells will be required to develop the pre-salt, wells have hit a price tag of $200 million. 'I've been working on some technologies that should help,' he says, with a goal of turning these wells into a factory drilling approach. 'The highest cost of the well is the rig. The problem with the rigs for 2000m of water is . . . you need the bigger vessel to carry more riser and to carry more mud . . . [along with] lots of other gadgetry, mechanization, and so forth, that makes it more expensive.'
One possibility to save money is to drill the first several intervals with a smaller rig, to temporarily abandon the well and bring in the more expensive rig with its riser, lower marine riser package and other equipment, and allow that rig to complete the drilling activities, Feasey says.
A subsea drilling with casing system is one technology that Feasey believes will see greater uptake to optimize well designs by mitigating shallow hazards and enable surface casing seats to be pushed deeper. The subsea drilling with casing system is pre-BOP, hence will work riserless. Operators in Brazil and the Gulf of Mexico are planning wells using this technology to drill up to 3000ft intervals of surface casing in deepwater, Feasey says.
The next technology to consider, he asks? 'Riserless drilling, that's new. That's never been done before in this respect,' Feasey says.
Feasey also expects future drilling time improvements to come from the bottom part of the wellbore by closing the loop and using techniques like managed pressure drilling.
Weatherford's Brian Grayson, global product service line manager for secure drilling services, says a closed loop drilling system is one way drilling operations can improve. He calls Weatherford's offering a 'novel' application that offers both efficiency gains and safety benefits, although 'those two don't usually go together. [It's often thought that] you get more safety at the cost of efficiency or more efficiency at the cost of safety.'
But, Grayson adds: 'There are a lot of ways you can gain safety and efficiency without distracting from either one.'
He cites a Weatherford product that uses corriolis flow meters to detect kicks, losses and other deownhole events. These events can often be identified at gallons compared to the longer time it takes before the results of a kick or loss are conventionally evident at the surface, he says. 'Once these events are identified, you can react to them more quickly. And with this increased downhole visibility, you can start to process out a substantially smaller kick quicker, you can also take steps to start optimizing your drilling program.'
There have certainly been changes in the industry over the years: the industry is now knocking on the door of operating pressures of 20,000psi when once the limit was 5000psi.
'15,000psi has been the norm but we will see equipment go to 20,000psi,' Maersk's Madsen says.
'Equipment has gotten bigger, heavier' to deal with the increasing water depths, temperatures and pressure, according to Aker's Moll. And at least on the HP/ HT side, the challenge will likely remain, he says. Most HP/HT equipment now can handle 15,000psi and 250°F or 300°F, he says, but moving to – or beyond – 20,000psi and over 300°F is technically challenging, he says, 'requiring significant investment to development that kind of technology.'
The focus may turn to making smaller and lighter equipment destined for frontier environments that may not have the larger vessels needed to accommodate the heavier kit, Moll says. 'For those frontiers, it's going to be important to make the equipment lighter, more compact, easier to install,' he says. 'In my opinion the next few years won't go so much in ever higher pressure/ temperature, but into lighter, more compact, more reliable equipment.' Some of that, Moll notes, will come from higher strength material and more and better analysis of design.
Halliburton is working to increase its abilities for increasingly challenging HP/HT conditions, Seaton says. 'It's about taking pressure and temperature capability to reservoirs of temperatures over 400°F and pressures of 30,000psi.' The tools Halliburton is working to develop are for logging and ormation evaluation, drilling and coring tools, and drilling fluids. With most, Seaton says, Halliburton is 'looking at a step change in technology, a completely new tool'.
Materials suited for the increased pressures and temperatures are one part of it, he says. 'We're talking innovative tool design as well . . . it's more than simply changing the material.' Seaton declines to provide more details about the tools for now, but says the first should become commercially available in 2012.
As Cameron's Will points out, the industry has been focused on 'deeper, higher pressure, more integrity, more cost effective, easier to intervene, easier to integrate with other systems, and I would add to that the smart technologies'.
The next step will involve 20,000psi and 25,000psi BOPs, and Cameron has one of each that will be installed in the beginning of 2012. 'You cannot push the envelope of production until you push the envelope of drilling,' Will explains, noting the company offers technology solutions in both areas.
On the drilling side, he believes shearing will be a focus: 'The requirements for shearing are going to be a lot more robust than before [Macondo]'. On the production side, Will says the technology will focus on the plumbing as well as sealing and increased pressure and depth. He maintains the real value will be integrated technologies 'so advances on the drilling side can marry with advances on the production area.'
'Several key technologies are going to be key for us moving forward,' says Doug Peart, general manager of SURF projects and technology for Shell's upstream major projects in the Americas. 'One is subsea processing/boosting. Another is dealing with higher pressure and higher temperatures than we've seen before. That presents problems for hardware and risers in particular. The functional requirements driven by more complex reservoirs presents a huge challenge.'
Shell, of course, is no stranger to subsea processing and boosting, having installed subsea separation and pumping through a subsea caisson separation system for both BC-10 offshore Brazil and Perdido in the deepwater Gulf of Mexico.
'I think we'll continue to look for opportunities to deploy technology built on what we know. This will incorporate learnings from our experience in subsea caissons. It may take a little bit of a different shape or form depending on the specific requirements,' Peart says.
Other technologies of interest, he says, include multiphase pumps on the seabed and pumping systems inside the wellbore. 'The floating drilling piece drives a lot of the cost in what we do, so technologies that enable that to happen more costeffectively would have a positive impact,' Peart says.
The industry is facing challenges that it hasn't in the past. For instance, Wood Group engineering division director Mike Straughen says, when it comes to the Perdido development in 8000ft of water, the distance from seabed to surface is greater than from seabed to reservoir. 'That really, for me, highlighted the challenges,' Straughen says. At Perdido, the oil is pumped further through the water than from the reservoir to seabed, he says, and that is just one place where seabed separation and processing – an area where many are spending 'lots of money' – makes sense.
Subsea separation and processing will be even more necessary, Straughen notes, with the increasing frequency of heavy oil discoveries. 'There are challenges with water depth, let alone managing the reservoir.'
Recalling the mechanical challenges the industry had to meet as it moved into deeper waters, Mike Robinson, FMC Technologies' sales and marketing manager for Australia and New Zealand, says the next challenge is 'putting the factory on the seabed'.
Carrying out processing and boosting on the seabed is becoming increasingly complex. 'It's not just as simple as what we did a few years ago where we just added pumps,' Robinson says. Now, it's a matter of making the fluids more 'pumpable' and 'boostable'.
'Anything we can do with gas-liquid separation, boosting, pumping, can have a major impact on some of those greenfields moving forward,' Robinson says. He cites Shell's Perdido deepwater development in the Gulf of Mexico as an example of needing to pump because of water depth and low-pressure wells that produced associated gas. Ultimately, Shell opted to use gas-liquid separation technology at the seabed in combination with pumps. 'Arguably the greenfield Perdido [project] couldn't have been done without taking some of the factory onto the seabed and doing gas-liquid separation,' he says.
A brownfield development saw gasliquid and liquid-liquid and solids removal separation equipment installed in early November 2011. Petrobras' Marlim field offshore Brazil in 900m of water, is producing ±67% water. The new in-line separation system will remove the water from the oil without pumping the water up to the surface. According to Robinson, it will take so much oil out of the water that it's clean enough to go directly back into the production reservoir and be used for water flood. The result is only hydrocarbons flow to the surface, enabling increased recovery, he says. The one-well Marlim subsea separation and water injection system was scheduled for start-up by the end of 2011.
One of the changes Cameron's Will says he has noticed in the Gulf of Mexico is 'solutions that are . . . different from just the platform-based processing that we've had to this point'. Specifically, he adds, 'We'll be looking at different subsea to shore solutions than what we were looking at in the prior five or 10 years.'
The core of that technology will be the 'subsea plumbing' – or the tree and the control system. 'What we see changing there is again the requirement to make all these things as value-added as they possibly can be, as smart as they possibly can be,' Will says.
Cameron believes the answer lies in electric solutions. The company's subsea all-electric technology has evolved over the years. The all-electric effort first became public in 2002 with the unveiling of the CameronDC All-Electric Subsea System prototype. In 2008, the first CameronDC system was installed in the North Sea. According to Will, the all-electric technology was developed in response to requests to make equipment more reliable and reduce costs compared to hydraulically-operated equipment.
'To the extent you have all-electric components, you can actuate a choke faster . . . you can say "I want to move it just this much". You can move it more precisely electronically than hydraulically.' Now 'we're making [all-electric technology] part of a bigger puzzle', he adds, noting that the technology is applicable, for instance, in subsea processing.
Matt Corbin, GE's regional general manager Americas for drilling & production, also sees seabed separation and processing as a key for maximum recovery. 'As much as we can do as close as possible to the source of hydrocarbons obviously saves money,' he says, adding that making seabed processing a normal piece of the subsea hardware scope would go far to improving recovery.
'Within GE we believe we have the components of a subsea processing system, but we need to marinize some of it,' Corbin says.
Knut Eriksen, Oceaneering's SVP for subsea products, points that the industry has been saying 'since 1985 that [subsea processing] is five years in the future'. He notes the tremendous amount of technology the industry has developed over the years in addition to several test seafloor separation systems, mostly on the Norwegian continental shelf, plus a subsea processing system at Total's newly commissioned Pazflor development offshore Angola. 'We're doing a lot more today than we were doing then. And we are probably much closer. But still, it's a complex field. But the reliability of what you put on the seafloor has to be the reliability of a Boeing 787. The long-term operational reliability will in our minds be based on the ability to service the installations via ROVs. Every reservoir is different so tailoring that to each reservoir is a big thing. Maybe some aren't as suitable for producing from the seafloor.'
And while subsea separation is something many mention as being a technology focus over the next few years, others seek underground separation in the hopes of initiating the separation before the hydrocarbons even reach the seabed.
'Nobody's cracked it yet, but they're looking at various things . . . where oxygen is injected into the ground and effectively ignited, heating the oil and separating it from the sand, and the theory is you can extract the oil in an easier manner,' explains Wood Group's Straughen. Underground separation 'would be a real potential game changer', he says, but adds that there are obviously issues with this approach, for example how to extinguish the burning oxygen and whether the ground might settle or sink after the oil leaves the reservoir. Shell's Peart says he sees 'deeper, more complex reservoirs . . . reservoir fluids becoming not as simple to deal with', on the landscape ahead. As such, he expects sensing to be big, particularly in-wellbore sensing for the subsurface to observe the changing circumstances in the reservoir.
Craig Anderson, general manager of Parker Hannifin's energy products division, believes one area of focus in the offshore arena will be how to get various components to better talk to each other. For example, he says, 'if a mooring line has been stressed or damaged, how do we design our system so it alerts the operator of the current condition? In other words, a call for help.'
Increasing production is key. As Oceaneering's Eriksen observes, operators in the Gulf of Mexico have tested various methods of producing ultra-deepwater reservoirs, sometimes via subsea completions. 'It's not simple,' he says.
'In the North Sea, we say we will get 50%-60% of the reservoir out of a platform well and approximately 30% out of a subsea well. In the Gulf of Mexico, the numbers are probably smaller than that,' Eriksen says. The output differential comes down to ease and frequency of workovers and interventions with dry trees. 'Generally the subsea wells won't be worked over as much as the platform wells due to the cost. That's an area that the industry over time can do better with more inexpensive specialized vessels.'
FloaTEC's Namtvedt also sees the industry evaluating the dry tree approach to provide 'more control of your own destiny on the platform over the life of your field'. Deepwater dry tree options include the spar, TLP and semi. Another road Namtvedt believes the Gulf of Mexico industry may move toward is notnormally- manned offshore installations. 'Our clients are asking us to look at that,' he says. To make it work, he says, 'You really have to believe you can make them not normally manned.'
The technology R&D group at MCS Kenny has 'homed in on ultra-deepwater, pipe temperature, the arctic,' according to Paul Jukes, president of the company's Houston operation. Working safely in the arctic means anticipating the challenges that the industry will need to overcome, he says. 'Then we can begin to develop internally analysis design tools to allow us to design pipelines and risers for extremely harsh environments.'
Jukes says his company is looking at a method that would allow it to create optimized depth designs rather than stress-based designs for pipelines and risers in ultra-deepwater and deepwater. 'We've been looking at design methods to allow us to handle the large water depths.' That effort calls for not just advanced finite element analysis, he explains, but also lighter materials, for example composites for lighter risers; ways to work in temperatures up to 350°F, nearly double the current design temperatures of 200°F, and means to handle high pressures, which create extremely large loads on the pipelines.
The advanced FEA has helped MCS Kenny 'to come up with new ways to optimize the demands and minimize these high axial loads. We call this thermal buckle management', Jukes says.
Enabling long step-outs is a focus at GE, Corbin notes. The ability to go from shore to fields up to 200km away is important for the industry, he says, especially in harsh conditions. GE developed a long step out subsea control system for Statoil's Snøhvit project in the Barents Sea as well as for Chevron's Gorgon/ Jansz project offshore Western Australia.
Super spans – which refers to a pipeline crossing over an escarpment or cliff face with about 200m of the line unsupported – are another focus at MCS Kenny.
'Definitely proven technology, designwise,' says Jukes, is a patented method that allows the pipeline to be non-compliant to the seabed using buoyancy to lift the pipeline and strategic anchors at touchdown points.
Another technology in the works for subsea transport of fluids is cryogenic pipelines. Designing subsea pipelines for LNG transport has been 'a design challenge, but we've been able to progress that,' reports Jukes, noting that it is possible, for example, to use pipe-inpipe- in-pipe, or 'a triple wall design that allows us to have subsea loading lines, effectively'. According to Jukes, the LNG design is 'absolutely viable' but needs a project where it can be deployed. The solution calls on exotic materials to provide a low coefficient of expansion. The third wall, he adds, is an additional barrier so 'leakage should never happen'.OE