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Bringing you the latest innovations in exploration, production and refining Issue 40
December 2015
BETTER WITH BIO
We look at Cosun’s Betafib® viscosifier Page 16
MERCURY FALLING
Johnson Matthey’s PURASPECJM technology for mercury removal
Page 24
SEISMIC SHIFT
Prof. Maarten de Hoop on how deep learning could revolutionise seismology Page 18
C I MIDE S I ENT INS S /EME 23 G L N I PP s 9 U LIAL S ge L I R EC Pa P D S
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December 2015
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Inside Contacts: Media Director Ryan Stevenson ryans@newsbase.com
Super-frack solution
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DRILLING/SEISMIC 9
Media Sales Manager Riley Samuda RileyS@InnovOil.co.uk
When the going gets tough 10 Cameron International’s Darrin Yenzer explains how the company is innovating to stay competitive in a tough market
Editor Andrew Dykes andrewd@newsbase.com
Drilling technologies
InnovOil and Lux Research take a look at innovators and start-ups
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Safer and cheaper drilling 14 Centrica and Island Offshore have a revolutionary application for shallow gas extraction in the North Sea
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Bio-powered Betafib®
16
Deeper learning
18
Cosun Biobased Products explains what makes Betafib® MCF one of the highest performing and sustainable viscosifiers
Design: Michael Gill michael@michaelgill.co.uk www.michaelgill.eu
Maarten de Hoop, Mathematician and Earth Scientist, discusses his groundbreaking work in the field of seismology
Cover photo: Jeff Fitlow/Rice University
Distributed Seismic Source 22
™ NEWSBASE
ations Bringing you the latest innov
5
Schlumberger has struck a deal with Energy Recovery to use its new VorTeq hydraulic pumping system
Media Sales Manager Charles Villiers Email: charlesv@newsbase.com
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A note from the Editor
in exploration, production
GPUSA’s upgrade eliminates source ghost reflections from seismic operations
and refining December 2015
Issue 40
BETTER WITH BIO
Page 16
MERCURY FALLING
Johnson Matthey’s PURASPECJM technology for mercury removal
Page 24
Prof. Maarten how deep learning could revolutionise seismology Page 18
24
An inspector calls
27
News in brief
28
Johnson Matthey’s simple and effective way to remove mercury from hydrocarbon gas and liquid processing
We look at® Cosun’s Betafib viscosifier
IFT SEISMIC SH de Hoop on
Managing mercury
Cyberhawk Innovations continues to push the envelope of ROAV operations IC ME ENITSINSID S G/EME 23 INUPPL s 9ILPELCIAL SPage R D S
Contacts 37 NEWSBASE
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December 2015
InnovOil
page 5
A note from the Editor It has been a tough year for drillers and seismic firms. With exploration slowing, both sectors have shown noticeable strain, from parked rigs to closing companies. But for that very reason, it is more important than ever to shine a light on the new technologies which can help – especially during the toughest of times. With that in mind, Cameron International’s VP of product management, Darrin Yenzer, discusses how innovation is assisting the company to deliver during tough times. This “stiff upper lip” also means continuing to keep an eye on the next horizon – whether that is equipment for 20,000-psi applications, or complying with new subsea regulations. Yenzer also outlines how an open-door policy on innovation can lead to novel ideas, from the drilling floor to the boardroom. Meanwhile, Cosun Biobased Products highlights Betafib® MCF – a natural cellulosic microfibre biopolymer used as a viscosifier for drilling fluids and cementing. We explore how its unique rheology offers operators maximum suspension efficacy from an easily pumpable fluid. Yet new technologies are always in development; now more than ever companies need equipment which can shave costs and increase uptime. Lux Research examines some of the innovative companies and start-ups with ideas which could shake up the drilling and seismic market. In our seismic supplement, we also talk extensively with Professor Maarten
de Hoop, Rice University’s Simons Chair in Computational and Applied Mathematics and Earth Science. De Hoop and his research partners are using a combination of big data and deep learning to resolve seismic equations more accurately and use less information. The application of machine learning to the seismic field is, in de Hoop’s words, “extremely hot,” and in future could enable tremendous advances in how the industry acquires and processes seismic data. In addition, we catch up with GPUSA’s James Andersen for an update on the firm’s Distributed Seismic Source technology. Last featured in InnovOil in our August edition, the company has now released its newest, patent-pending MV-24 marine vibrator – with four times the active surface area of the earlier MV-12 transducer. Andersen explains more inside. Fire safety firm Tyco also expands its portfolio via a new licensing agreement with Aberdeen’s RigDeluge®, while Johnson Matthey shows how its PURASPECJM technology can aid mercury removal in hydrocarbons processing. While that almost draws our year to a close, next month we will be publishing our 2015 Annual, featuring a look back at some of our favourite innovations from this year as well as a look ahead to the trends, projects and predictions for 2016. If there is anything you would like to see again – or perhaps something you think we missed – please get in touch. The team and I are pleased to bring you the December edition of InnovOil.
Andrew Dykes Editor
NEWSBASE
page 6
InnovOil
December 2015
COMMENTARY
Schlumberger’s super-frack solution Schlumberger has struck a deal with Energy Recovery to use its new VorTeq hydraulic pumping system, which will make “super-fracks” cheaper and more efficient, writes Jeremy Bowden
W
Schlumberger will pay US$75 million ith hydraulic fracturing up front for the technology, which it still at a relatively early stage will use in its North American fracking of development, there are operations. Under the terms of the considerable opportunities contract, it will then make milestone for companies to cut costs and streamline payments in 2016 valued at US$50 processes through innovation. This trend million, and annual royalties during the has been accelerated by the increased duration of the contract. Schlumberger pressure to save cash in the depressed oil will retain exclusive rights to the VorTeq price environment. system, which is “the first Collaboration is one hydraulic fracturing manifold way that companies can built to isolate hydraulic create efficiencies and fracturing pumps from cut costs, with a deal abrasive proppants that struck by Schlumberger in cause pump failure,” Energy October showing what can Recovery said. be achieved. The oilfield The product has been services giant entered into tested over a six-month a 15-year agreement with period with Liberty Oilfield US specialist equipment Services on unconventional manufacturer Energy wells in the Bakken, but has Recovery, which gives not yet been commercially the former access to the deployed. By using company’s new VorTeq “The savings Schlumberger’s leading hydraulic pumping system. could add up to infrastructure and fleet, the The technology could save as much as technology could now be up to US$5 per barrel in production costs, according US$5 per barrel” deployed rapidly. Energy Recovery’s to Energy Recovery, by cutting pump abrasion from Joel Gay, president and president and CEO, Joel proppant sand. The deal CEO of Energy Recovery Gay, said the system could significantly reduce the is particularly timely given number of pumps that are the increased use of high required, cutting what has become a proppant volumes in fracking, known as major cost in fracking operations. “From super-fracks. an economic standpoint, we and our Under the US$125 million deal, NEWSBASE
partner Schlumberger believe that we can materially reduce the cost per barrel to frack a well by virtue of going from the existing pump model to the new pump model,” Gay told Reuters, adding that he believed the savings could add up to as much as US$5 per barrel. “The VorTeq product represents a paradigm shift for the hydraulic fracturing industry, as it significantly reduces maintenance costs associated with pumping downtimes and provides considerable redundancy efficiencies.” More efficient and cheaper The technology works by allowing pressure pumpers to avoid running fracking slurry (the thick mixture of sand, water and chemicals used in hydraulic fracturing) through their pumps. This is done by using an ultra-efficient energy exchange to re-route the fracking fluid away from centrifugal pumps. With a single moving part made of tungsten carbide, the system has been engineered to withstand tremendous pressure and harsh conditions, and transfers up to 95% of the hydraulic energy from one fluid to the next.
December 2015
InnovOil
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COMMENTARY Truck-mounted VorTeq system
The result will reduce wear and tear on Schlumberger equipment, lowering the need for replacement and maintenance, thereby making fracking more efficient and cheaper. The system claims to offer a life expectancy of roughly 50,000 hours, compared to traditional pumps used for fracking that feature a 6,000- to 8,000hour life expectancy before maintenance is needed. “Harnessing pressure energy the way we have in our other technologies, our solution ratchets frack fluid up to the required treating pressure, as high as 15,000 psi, without requiring the highpressure water pumps to handle sand. This prevents the regular occurrence of pump failure, and has several immediate and profound impacts for operations, not the least of which is a dramatic reduction in maintenance,” said Gay. Super solution The application of the technology is critical, given the growing use of high volumes of abrasive proppant sand, as low oil prices leave drillers struggling to increase the productivity of their
wells. Super-fracks use two to three times as much proppant as typical wells, generating higher levels of abrasion. The super-frack trend has been in the making for several years as proppant volumes have steadily risen, and the associated increase in abrasion has been so damaging that there has even been talk in the industry of fracking service companies moving to a pricing model based on sand concentration. Schlumberger refused to comment to InnovOil on the deal or technology directly. But in an earlier statement, it said: “We are looking beyond just the benefits provided by VorTeq system. The incorporation of the VorTeq system, along with other proprietary technologies, in Schlumberger’s nextgeneration surface delivery systems, will help reduce fracturing pump wear and increase wellsite equipment reliability and efficiency.” Schlumberger said the technology provided immediate cost savings from lower wear and tear. The company added: “In the medium term [it] delivers capital efficiency, since it eliminates redundant NEWSBASE
onsite equipment. These are savings that Schlumberger can share with its customers, ensuring that its crews stay busy during the downturn.” The principle behind the technology has been tried and tested in other industries and is based on Silicon Valley-based Energy Recovery’s Pressure Exchanger application. It is the leading pressure energy recovery device in desalination, with over 16,000 units deployed around the world. If the claims of US$5 per barrel cost reductions prove to be true, the technology represents a substantial saving, amounting to perhaps 20% of total costs of unconventional US wells in some cases. A few more dramatic technological advances of this sort and American shale oil plays might get closer in terms of production costs to conventional fields. Such technological advances are one of a number of factors that are drawing many oil majors away from expensive conventional projects, such as deepwater plays, towards lower risk and shorter lead time investment in onshore shale. n
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Drilling/Seismic
December 2015
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Special supplement Pages 9-23
Stiff upper lip
Cameron International is innovating to stay competitive Page 10
Back to the source
The latest on GPUSA’s Distributed Seismic Source Page 22
In the shallows
Island Offshore and Centrica pioneer a new CTD technique in shallow waters Page 14
NEWSBASE
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InnovOil
December 2015
Drilling/Seismic
When the going gets tough
Cameron International’s VP of product management, Darrin Yenzer, explains how the company is innovating to stay competitive in a tough market
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ike many firms with a focus on drilling, right now Cameron International is keeping a “stiff upper lip.” The past year has seen the company undergo its fair share of pressure, what with the announced proposed sale of its offshore jackup business to Keppel O&M and Schlumberger’s purchase of Cameron in August. Yet, speaking to InnovOil in late September, the company’s VP of product management, Darrin Yenzer, remained upbeat. “We have good customers and customer support and they’re sticking with us,” he said. A good backlog of work has also kept the company busy. Yenzer pointed to a recent success commissioning equipment on the first in a series of deepwater drillships, noting: “The customer took the time to send their appreciation for the job well done. That is not to say there have not been some changes. “There’s a little bit of a shift in Cameron’s product development focus,” Yenzer added. “We’re leaning more towards additional R&D work than we have in the past. I would say, with the focus being different because of the market today, we’re really working to get closer to our customers and really understand their specific needs.” This has involved a relatively handson, face-to-face process, with many of Yenzer’s team going out to meet with customers to understand exactly what they need, whether that is lowering costs, or improving up-time and availability. Most, he suggested, “are focused on keeping the rig available on contract as best they can, the reliability conversation is constant, [so] everything needs to be focused on preventing failures.” Availability is the Goal With that in mind, new innovations have become a vital tool in helping meet that goal. As has been seen across the industry, monitoring and predictive maintenance have become priorities and have in many cases grown, even despite the downturn, because of the long-term efficiency improvements on offer. Yenzer
takes a fairly pragmatic view on the by companies such as GE and Kongsberg. issue, commenting: “We can prevent Potentially integrating this technology most of the failures, you can develop into Cameron’s drilling business could things to improve the failure prevention, allow it to reduce dramatically the time but things will always have taken to replace equipment a limit, so there’s another in the event of failure. conversation stream going on Though he remained about availability and about tight-lipped on its full scope, how you counter inevitable he affirmed: “We’ve invested failure.” in that technology and Post-Macondo, he noted we’re now looking at it and that the retrievability and evaluating the best aspects backup of equipment, subsea on how to implement it, if we especially, had come under go forward with it.” increased scrutiny. Retrieving New regulations are and/or fixing equipment also fostering change. In in deepwater and ultraparticular, he pointed to the deepwater now can take days, “Some of the changing requirements of adding weeks to project time Bureau of Safety and best ideas come the and delaying production. Environmental Enforcement “People are very interested in from the far out (“BSEE”) rules, especially preventing parts from failing with regards to supporting places” in the first place, but also – if and powering subsea Darrin Yenzer, VP of it does fail – what do we do equipment. A mandated product management, with it? How can we make expansion of redundancy in Cameron International equipment such as blowout that time back faster?” he asked. preventers (“BOPs”) will One solution Yenzer drew attention to necessitate some innovation he noted, to lies in some technology recently acquired the extent that “We can see substantial by Cameron that is geared towards growth in sub-sea stacks based on the way developing modular technology – a the rule is currently worded.” concept which has been gaining wider Indeed, in July the American ground across the sector, including efforts Petroleum Institute (API) laid out many NEWSBASE
December 2015
InnovOil Drilling/Seismic Cameron BOP equipment stacked in Berwick, Louisiana
of its concerns with the new legislation in a letter to the BSEE. Specifically, it noted: “The additional required associated equipment (e.g., larger fluid reservoir, additional pumps, additional accumulator bottles, etc.) would be problematic in their demands for space and contribution to additional complexity of rig systems.” Yenzer echoed this, commenting on the “substantial increase in the amount of subsea energy required to perform all of the newly required functions, in a case where the rig is not connected anymore.” Because of that expansion, he continued, “The amount of energy required to operate is two, three or four times what it was before, which will require a tremendous amount of accumulator bottles or stored-energy vessels to operate. If the language of the rule is not changed there’s going to be a need to provide that capability and not increase the size of the rig or do a tremendous amount of very expensive and time-consuming changes to existing rigs.” That said, if the proposed regulations are enacted, new territory will be opened to innovative firms rushing to develop new, BSEE-compliant technology. Cameron appears sure to be one of them. 20,000 psi under the sea Yet, even in facing the challenges of developing new equipment, Yenzer remained buoyant. “There aren’t a lot of barriers other than funding,” he said “We’ve got a lot of areas that are challenging, such as the development of 20k [equipment to withstand 20,000 psi], and operators have pushed all of us to really focus on some new technology to handle such high pressure.” Moving with the industry’s growing demand for increased monitoring and predictive maintenance, he also highlighted a new Cameron-developed system called Cognition™. The system is a network of sensors, data recorders and communications installed along the subsea stack, enabling both realtime monitoring and aiding potential emergency contingencies. In the future, it will also include predictive capabilities.
“I think that’s really going to be one of the long-term beneficial technologies that we incorporate into our pressure control world, much like it’s been incorporated in other industries for a long time,” he said. “Fixed rotating equipment has used this approach for years, but it’s sticking it in 10,000 feet of water and running a twomile connection cable and running data up and down in that environment – that’s challenging.” The tougher market has also pushed the company into a more evaluationbased approach to technology. Yenzer talks of a system which involves “more preliminary analyses to really focus on the projects that are going to bring most value to the customers.” This can be a challenge in itself – engineers relish in designing things that are cool, but may not necessarily be practical – but a more diligent method of new product design (NPD) ensures that the good ideas are marketable and developed correctly – and the bad ideas are not. It also takes a very democratic approach to idea generation. “We solicit ideas internally through the company’s webpage,” Yenzer added. “Anybody that has an idea is free to write it down and send it in and it will get a look.” This often leads to interesting submissions from staff on the operational front line. “Some of the best ideas come from the far out places, a lot of service hands and folks like that have a lot of good ideas. They’re out there and they see things and they only have to fill in the blanks.” Perhaps most encouraging is that, despite the pressure, uncertainty and difficulty of the past year, that spirit of openness and innovation appears to be unwavering. “My goal for everybody here is to have more good development projects than we have resources to execute,” Yenzer said. “And that’s still the case.” Long may that continue. n Contact: Timothy Taylor
Marketing Communications Manager, Drilling Systems Tel: +1 281 901 3226 Email: tim.taylor@c-a-m.com
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December 2015
Drilling/Seismic
Drilling technologies on the grid Despite low prices, there are a number of intriguing technologies on the drilling market. InnovOil and Lux Research analyst Colleen Kennedy take a look at a few of them
A
S costs continue to be shed across the industry, drilling operations are a prime target. For some operators the solution may simply be to cancel well programmes and not drill at all, but for many others it will involve drilling smarter. Refracking is catching on in the US, new shale gas exploration is continuing in places like Argentina and Australia, and field development programmes are pushing on in Eastern Iraq and even in the North Sea. To meet that demand, small companies and innovative start-ups continue to bring products to market. But whereas in years past these firms may have focused their efforts on offering improved drilling accuracy or production, now more than ever the dialogue centres on reducing costs and increasing uptime. Colleen Kennedy, research analyst with Lux Research – and lead author of its report on ““Identifying Ways to Reduce Drilling Budgets in the Low Oil Price Environment,” – comments: “For the most part, the biggest trend this year has been on streamlining operations, cutting down drilling days and improving operations in the field as much as they can.”
In preparing the report, Kennedy says that her and her colleagues “chose technologies we had seen, which have potential or companies that are attempting to position themselves in that sense.” The result has been a number of interesting companies and start-ups assessed by qualities such as maturity, size and revenue, and then charted on the Lux Innovation Grid (pictured). The resulting score indicates their potential to disrupt, as well as their commerciality. Now trending “The major trend is for anything that reduces NPT time,” Kennedy states. This has naturally shifted the industry’s priorities away from other areas of interest, she continues, noting: “Downhole telemetry has been a major focus in the past, but some of the companies even that we ranked highly in this report have been a little slower to get their operations up to speed.” Start-ups which a few years ago would have found solid support from major firms are now having to work harder to gain a toehold. “With telemetry, the technology is particularly challenging. A lot of operators want to move away from mud pulse and
Technical Value
Lux Innovation Grid: Comparing drilling cost-optimising technologies
Business Execution
Source: Lux Research, Inc.
NEWSBASE
to something more advanced,” Kennedy says. She cites companies such as Cold Bore Technology and OPI Downhole Technologies. The former is working on a sonic telemetry tool which, it claims, can send data thousands of times faster than mud pulse and electromagnetic telemetries, while the latter’s iMEC™ technology aims to capture energy via magnetostrictive alloys, while downhole. However, both remain in very prototypical stages. “These innovations are great in theory,” Kennedy says. “But it’s very expensive to deploy these tools for testing, and they haven’t quite got their innovations proven in the field yet.” With few operators willing to devote time to such early stage equipment, these may remain in the development stage for the medium term. Conversely, Hungary and Texas-based ZerLux offer laser solutions which tap into greater needs, and more immediately. Featured in the June edition of InnovOil, the company can take on a range of oilfield tasks, including lateral drilling, scale removal and perforations, with small, highpowered lasers. The company’s position is that these can often perform these tasks faster and at a lower cost. “I could easily see a company like ZerLux catch on,” Kennedy posits, “Because their technology is twofold – both for perforation and for removing scale using lasers. I think a company like that is wellpositioned, especially as operators focus on corrosion and maintaining infrastructure.” Robot rocks From a more futuristic perspective, commercial robotic rigs appear to be well on their way to market. “Maybe not in 2016, but further down the road robotic drilling systems and some of the other automated drilling rigs are going to be taking over the landscape,” Kennedy assures. Norway’s Robotic Drilling Systems, an innovative start-up backed by Odfjell Drilling, brings equipment one might usually associate with manufacturing to the drilling floor. The kit consists of four separate machines
InnovOil
December 2015
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Drilling/Seismic Cold Bore Technology’s sonic telemetry tool
– the Drill-Floor Robot, Robotic Pipe Handler, Electric Roughneck and Multi-Size Elevator – which work in tandem to lift and move pipes into position while drilling. As a general trend, Kennedy says, this should be a revolutionary proposition to operators: “You’re removing people from the rig floor any time you have an automated system. Some also pick up on anomalies and reduce kicks and NPT, but ultimately a more robotic autonomous drilling system would be the way to reduce human error and increase safety.” Another firm charted on the grid is Dynamic Tubulars, a company using elastic recovery of high-strength steel pipe layers to line wells and create high-pressure seals, ideal for HP applications. Yet despite the appeal, the method does not appear proven enough to catch the wider eyes of the industry, especially given its “long history of funding and field tests,” she notes. But even those firms with a sound pedigree and case histories may find it difficult gain traction with their innovations. “Right now is really not a viable time for those companies,” Kennedy explains. “Deploying a completely new casing method is very expensive and timeintensive,” she adds, something which is unlikely to hold mass-market appeal in times such as these. Instead, she concludes, opportunists in the M&A market may mean that the technology is taken on by a larger company with a longer horizon: “I think there is
Robotic Drilling Systems’ Drill-floor Robot DFR-1500
definitely a future for those… I can see that technology easily being picked up by a major, especially in these low prices.” An awesome wave The seismic field has been hit particularly hard by the downturn, but, as this issue will hopefully illustrate, still shows promising signs of innovation. Waveseis, seen in the top left quadrant of the Innovation Grid, is formed of a two-person team using proprietary Revolutionary Imaging Technology (RIT) to provide high fidelity images using Reverse Time Migration (RTM), even under very challenging conditions. According to the firm, it is currently developing “a complete velocity estimation and imaging workflow based on the two-way wave-equation to solve imaging challenges,” in particular for use in sub-salt fields in the Gulf of Mexico and Brazil. CEO Mark Roberts experience with BP’s Advanced Seismic Imaging R&D Team suggests the company is well-placed to take advantage of the relatively undiminished interest in surveying these regions. Kennedy agrees, noting: “I think there’s high potential, they’re using some different techniques. When you look at the company overall, it’s two people using cloud computing to process data, so I think one of the only hurdles for them right now is getting data to test from potential clients.” Waveseis’ business model is also an indication that small-scale companies still have the potential to weather the proverbial NEWSBASE
market storm with good business and good ideas. “For start-ups,” Kennedy says, “companies on the smaller side which aren’t running high expenses will be able to weather it.” What has had a negative impact is the lack of support for trialling innovations in the field, either as a result of conservative outlook on production, or a lack of funds. “Maybe 70% of the companies we’ve talked to said that they might have been in discussions about field trials or potential technology partnerships and that once prices fell, they fell through. Many are now recovering from that and still trying to get a foot in the door,” Kennedy adds. With predictions appearing to converge on an outlook for 2016, at least the relative calm in the medium term should make for a stable market – if a somewhat depressed one. But what is perhaps most interesting about Lux’s findings is that that the greatest hurdle for start-ups right now may simply be the same hurdle they have always encountered – getting their innovation recognised and proven in the field. For those which can succeed in doing so, the future is likely to be as bright as ever. n Lux’s report “Identifying Ways to Reduce Drilling Budgets in the Low Oil Price Environment” is available here: portal.luxresearchinc.com/research/report_excerpt/20085
Contact: Carole Jacques Email: Carole.jacques@luxresearchinc.com
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December 2015
Drilling/Seismic
Centrica pioneers safer and cheaper drilling technique Centrica and Island Offshore have adapted road drilling technology into a revolutionary application for shallow gas extraction at the Butch field in the North Sea, writes Tim Skelton
C
entrica Energy Norway has used an innovative new technique to drill a pilot hole for shallow gas at its Butch field, north of Ekofisk in the Norwegian North Sea. Together with Island Offshore it combined traditional coiled tubing drilling (CTD) and downhole equipment from Baker Hughes, in combination with a mobile well intervention vessel. Centrica says this method, tested for the first time in the oil and gas industry, is significantly cheaper and safer than using a fixed rig for the same task. The work was carried out by Island Offshore’s Mobile Offshore Unit Island Constructor, which drilled a pilot hole down to 360 metres below the seabed. The aim was to determine, before full production drilling began, whether or not there were pockets of shallow gas present in the formations. If found, these hidden gas pockets could cause a potential blowout in an early drilling phase. Instead of using a marine riser, the coil tube is kept in tension between the vessel and the subsea injector by means of a second on-board injector. The tube itself does not rotate, but pressurised fluid inside activates a hydraulic motor, causing the bit to rotate. The subsea injector moves the tube in and out of the well. “On a normal semi-submersible rig there will be only one surface injector, and you need to run a rigid riser between the rig and the seabed to support the coil, so that it doesn’t bend out to the side. The fact that we have the coil tubing in open sea saves a lot of time, and a riser is also an expensive piece of equipment,” Island Offshore’s Top Hole Drilling Manager Per Buset explains. The operation was planned to last seven days, but was finished in four. And on this occasion, no shallow gas was found, allowing the hole to be plugged
Subsea injector with power from ROV
with cement, and a fixed rig to be moved in to start drilling the production wells in safety. Road test The technology was developed several years ago by Island Offshore, but had not been put to the test until last year. It was then that the Norwegian Public Roads Administration needed someone to drill for core samples under the seabed, as part of their Rogfast undersea road tunnel project, outside Stavanger. Centrica personnel heard about this project and visited the drilling vessel during the operation. “That confirmed our belief that it might be possible to use the same method for the drilling of pilot holes in the oil and gas business, to check NEWSBASE
for the presence of shallow gas,” David Robertson, Centrica Norway’s Senior Drilling Engineer told InnovOil. The Butch pilot hole was drilled using the same equipment, but far greater planning and preparation had to go into ensuring the safety of the vessel and its crew, in the event that there might be a release of gas at the seabed. Also, a greater focus had to be put on the more challenging conditions at the drilling location, in order to minimise the risk of getting the equipment stuck. “The operation fell under the jurisdiction of the Petroleum Safety Authority (PSA), which requires far more stringent levels of risk mitigation, contingency planning and crew training for oil and gas operations conducted in Norwegian waters,” Robertson explains. “Some modifications to the existing equipment had to be made to comply with these requirements.” Coiled tubing drilling within the oil and gas sector has traditionally been done from fixed platforms on wells that have already been partially or fully completed. This marks the first time that the openwater approach has been attempted. “For the Butch pilot hole operation some of the equipment that is normally used at surface was placed on the seabed,” Robertson says. “In effect the equipment was modified to make it waterproof. This is unique and allows coiled tubing drilling to be used at locations where there is no existing infrastructure.” Great success The operation experienced no major difficulties and was judged a great success. “A vessel will move more than a semisubmersible rig due to waves and wind, but we had good weather during the operation and had no problem with this,” Per Buset says. In fact, as David Robertson explains,
December 2015
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Drilling/Seismic
Xxxxxx Islands Offshore’s Mobile Offshore Unit - the Island Constructor the method even helped solve one of the potential difficulties of using a traditional rig in waters that are only 66 metres deep. “Anchoring a semi-submersible rig in waters of this depth can be a challenge,” he says. “The more modern semisubmersibles have dynamic positional capabilities, but these are at the top end of the cost scale. Jack-up rigs are often used in shallow waters, but it isn’t considered good practice to use them for drilling shallow gas pilot holes, as they cannot be moved off location if a blowout is experienced, thus increasing the risk to personnel and equipment.” On the other hand, an open-water vessel can move quickly away from the drilling site in the event of a blowout. Moreover, because a flexible coiled tube is used, the vessel can also maintain contact with the well, allowing it to keep pumping mud down into it to stop a blowout, while at the same time moving to a more secure area. This results in substantially safer operations. “The greater mobility and independence offered by using a Light Well Intervention vessel also resulted in a much shorter operation as the vessel was able to travel to, and from, the location much more quickly than a drilling rig,” Robertson adds.
The collaboration with Island Offshore resulted in significant cost savings. Even allowing for the variability of rig rates, Centrica estimates that the new techniques allowed it to complete drilling at around half the cost of using a traditional rig. The need for logistic support is also reduced. Centrica has no plans to drill another pilot hole in the immediate future. But in the meantime, Island Offshore has been contacted by several major oil companies to enquire about using the same method to drill pilot holes for their own projects. “Given the cost savings we experienced, it would be surprising if at least one of these operators did not go ahead with a similar operation in the near future,” David Robertson says. “Nothing is signed yet, but we are in dialogue with clients both in Norway and in UK for potential work next year,” Per Buset confirms. While the technique is currently limited to the drilling of shallow holes in the formations closest to the seabed, Robertson believes the natural next step is to further develop the equipment to allow similar coiled tubing operations to be carried out on existing, live, subsea wells where pressure control is required. “Currently it is only possible to carry NEWSBASE
out intervention operations from a Light Well Intervention (LWI) vessel using wireline equipment. This equipment has limitations to what can be achieved in the well,” he explains. Using coiled tubing, he says, would allow a greater number of operations to be carried out without the need to bring in an expensive drilling, or intervention, rig. “Operations such as scale milling, sand fill removal and plug and abandonment work, for example, could be performed from the back of an LWI vessel, effectively allowing it to act as a ‘Heavy’ Well Intervention vessel. This would be of great benefit to operators who wish to perform maintenance on wells to increase production, but at a reduced cost,” he adds. With regards to future development, Robertson says Island Offshore is actively planning the idea to perform intervention work on live, subsea wells. “The option to form a partnership with an operating company, to advance the development of this concept, is something they may well be interested in,” he says. “It may not be long before the industry sees its first successful intervention, or drilling, operation using the same subsea coiled tubing method.” n
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Drilling/Seismic
Betafib viscosifiers with Cosun ®
Francesco Staps of Cosun Biobased Products explains what makes Betafib® MCF one of the highest performing and sustainable viscosifiers for drilling muds
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ot many things connect fishing rods to downhole chemicals. As such, the story behind the development of Betafib® MCF, the latest oil and gas-focused biopolymer from Cosun Biobased Products, is perhaps one of the more unusual. Betafib® is a natural cellulosic microfibre biopolymer derived from vegetable products, and is used as a viscosifier in drilling muds – though this was not always the case. Business development manager Francesco Staps explains: “Originally, someone picked up an idea to use natural microfibres for fibre reinforcement in fishing rods. That idea then turned to fibre reinforcement in engineering plastics.” However, this was not as straightforward as they had originally hoped. “This process was very troublesome because the plastics became very viscous,” he continues. But with one avenue closed off, another opened. The viscous nature of the fibres alerted the team to the possibility of using the biopolymer as a dedicated viscosifier, suitable for use in detergents, construction and, of course, oil and gas. In its new form, Betafib® aims to offer users maximum suspension efficacy whilst remaining an easily pumpable fluid. As we have discussed in previous issues of InnovOil, a sizable proportion of efficiency increases and production gains over recent years have been enabled by various chemical agents, especially the US shale boom. The evolution of better tracers, polymers, surfactants, anti-scalants, biocides and more have, in
many cases, enabled operators and service providers to raise, control and even restart wells, while new chemistries have enabled further innovations up and down the supply chain. As such, more novel chemical innovations are coming to market, and Cosun Biobased Products – an innovation-focused subsidiary of the Dutch agro-industrial cooperative Royal Cosun – is joining the movement. Overseeing the products and innovations which fall outside the group’s regular business gives it a fairly broad perspective and reach, in terms of commercial applications. No contest Upon lifting the focus from using the polymer to engineer plastics, the team turned its attention to rheological applications. Comparing Betafib® to other solutions on the market suggested very favourable characteristics, Staps says. “That’s when the real benefits came to light … We found out that if we compare ourselves to materials like Xanthan [gum], then to some extent we do the same thing – but with one major difference. Xanthan NEWSBASE
dissolves into a liquid, while our Betafib® does not. It builds a physical network in the liquid.” This physical network allows Betafib® to carry significantly higher amounts of solids in suspension than a substance like Xanthan that dissolves. It makes for an ideal product for use in drilling muds to pump debris and sand back to surface, and in surfactants for use in enhanced oil recovery (EOR). It also means that high performance can be achieved at low dosages. “This physical network can carry all kinds of stuff – not up to steel bearings, but we can carry nylon bearings,” Staps notes. Lab tests (pictured) have shown that 3/16” (4.76-mm) nylon bearings remained suspended at the same height after 48 hours in fluid viscosified to 1,000 centipoise (cP) with Betafib®. Both Xanthan and carboxy methyl cellulose (CMC) deposited the bearing within 45 minutes. Staying stable The structuring strength of Betafib® is balanced with shear thinning properties, meaning drilling fluids can be formulated
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Drilling/Seismic Nylon bearings remained suspended at the same height after 48 hours in fluid viscosified with Betafib®, but not with Xanthan and carboxy methyl cellulose (CMC)
Betafib® rheology under a microscope
Betafib® rheological profile 6
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B: CMC R: Guar Gum Y: Xanthan G: Betafib
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Viscosity (cP)
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This delta represents a significantly higher capacity to suspend solids
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and pumped with maximum ease, before doing its job under low- and no-shear conditions downhole. Perhaps more importantly, Betafib® is also highly stable, maintaining these properties under a variety of challenging well conditions. With increased well alkalinity and a move towards more highpressure/high temperature wells (HPHT), operators are in need of more robust and versatile fluids to cope with these >150°C and >10,000psi conditions. This stability is a result of the fact that Betafib® is derived from natural, chemically unmodified fibres. “It’s mainly cellulose. As a chemical component, cellulose is very inert, so more extreme pH levels do not hinder Betafib® ’s functionality … it will not degenerate, it will not collapse.” Betafib® remains stable at temperatures up to temperatures of 180°C (356°F), and is relatively unaffected by pH levels from 1-14. “This stability holds even under the presence of various electrolytes,” Staps adds. At electrolyte concentrations summed up to a level of 30%, Betafib® remained compatible with both sodium and calcium chloride, sodium and
magnesium sulphate, sodium carbonate and sodium metasilicate. “Those properties are the result of our processing,” Staps says. “We have a very robust processing system, meaning that the material that leaves our facility isn’t influenced by temperature swings, pH swings or pressure pulses – and it can withstand them all.” Potential partners For an industry that is increasingly concerned with sustainability, the use of renewable and biodegradable drilling fluids is also a positive opportunity, he points out. “This is one of our own side streams, since Betafib® is derived from sugar beet pulp. There’s a large abundance and we have direct access to the raw materials. This makes us backwardintegrated. And price stability is one of the advantages that comes with this security of supply.” Although direct feedback from operators and third parties is limited – chemical formulations remain notoriously secretive – Staps has been pleased with the news from clients so far. “What we hear is that the particle-carrying properties NEWSBASE
are exceptional, especially under harsh conditions – even in HPHT, this material can still do the job,” he concludes. With Betafib® now patented, Cosun is looking for new partners interested in formulating advanced applications. “We tend to work in tandem with partners. If a product is not good enough yet, we solicit the input of the market to improve it and to meet their needs.” What next? Cosun is in the process of commissioning the Betafib® production facility. It is expected to come on line in the first half of 2016. With the knowledge that Betafib® can structure drilling muds, the company believes the technology can be extended out across a range of oil and gas applications. The biobased structurant can help companies make the most of a reservoir, not only in drilling fluids but also when being used in fracking and/or cementing applications. n Contact: Francesco Staps Tel: +31 6 4619 8729 Email: francesco.staps@cosun.com Web: www.cosunbiobased.com
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December 2015
Drilling/Seismic
Deep learning – the next seismic event?
We sat down with Maarten de Hoop, Rice University’s Simons Chair in Computational and Applied Mathematics and Earth Science, to discuss deep learning, big data and his groundbreaking work in the field of seismology
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rofessor Maarten de Hoop is making a model of the earth using seismic energy as a probe. It may take some time. “What I really want to do – and I’m working hard on it – is reconstruct the entire complex interior of our planet and develop a complete understanding of the interaction of the many physical processes operating through an extreme range of scales,” he enthuses. Such a monumental task is in actual fact typical of the kind of work he does – solving seemingly impossible problems via a variety of novel mathematical and computational techniques. Earlier this year, InnovOil sat down with de Hoop at Rice University in Houston. He had only recently moved to the energy capital from Purdue University, Indiana, to take up a newly created Simons Chair position. The move was made possible via a Simons Math + X grant, a programme which creates joint chairs, shared equally between a mathematics department and a partner department. In this case, de Hoop’s chair is in Computational and Applied Mathematics with Earth Science. More specifically, it recognises his ground-breaking work in seismology and seismic inverse problems. “I work in a particular branch of mathematics called microlocal analysis, applied harmonic analysis and inverse problems,” he explains. “Seismology, both controlledsource exploration and earthquake global, is an exploratory field for this type of mathematics. There is virtually no better application you can dream of than seismology.” As a result, he is also no stranger to the energy industry. A significant part of his work has been funded by or adopted by industry, and his professional life
includes a decade of work with major firms, including Royal Dutch Shell, and a position as a senior research scientist and programme leader with the Schlumberger Gould Research Center, formerly Schlumberger Cambridge Research. As such, his recent move to Houston will enable closer co-operation between his research group and the energy sector. His efforts, however, are not directed towards developing the latest commercial products, but instead breaking fundamentally new ground. “I’m not so much doing what other consortia do… filling in the blanks in existing technology or making it incrementally better. I’m working on what we could do next.” In basic terms, this involves using massive computer power and architecture, complex algorithms and, most recently, deep learning to exploit seismic data in ways which have never been attempted before. The inverse is true In more complex terms, your head may begin to spin. De Hoop starts slow: “My main interest is in ‘inverse problems.’” The field is socalled because one begins with the results – in this case seismic data – before positing and calculating the meaning and causes of each constituent or component in the data. “As well as proving that something can be done, uniqueness and stability, I like to work from explicit reconstruction algorithms.” That data can come from multiple sources. Where the industry uses active sources for marine and land acquisition, the global earth field uses ambient noise, tremors and earthquakes. Now, however, as de Hoop says, “We’re looking NEWSBASE
Xxxxx
at resolving multi-scale structures with material properties that we haven’t been able to resolve before.” Rice University has a pedigree in attempting to solve these problems, having been the home of the Rice Inversion Project, an industry-academic consortium launched by mathematician Bill Symes, since the early 1990s. The proximity to Symes and other departments – including the Ken Kennedy Institute for Information Technology and the Computational and Applied Mathematics and Earth Science departments – will allow even greater collaboration in the fields of inverse problems, imaging and geodynamics research. Naturally, doing so is not necessarily straightforward. The problems de Hoop and his colleagues deal with are very large. As a consequence, we are involved in “extreme-scale computing,” and even with present day supercomputers, there are fundamental bottlenecks. The issue is less
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Drilling/Seismic
“What I really want to do – and I’m working hard on it – is reconstruct the entire complex interior of our planet”
Photo: Jeff Fitlow/Rice University
Xxxxxx
that we lack processing power, de Hoop says, but more that we require faster ways of communication between processors and cores. As a result, he concludes that “We cannot just say we will try to be ‘smarter’ – what we need to do is do it fundamentally differently.” “Controlled accuracy computation, in concert with the limited accuracy of the data, and randomisation are key ingredients in the development of fast algorithms with low storage acting on big data,” he explains. “This said, we know mathematically that current data acquisition is intrinsically redundant; in our research programme we use machine learning to identify information content, while opening the way of discovery with data we have not associated with models yet.” One of the first tasks is to streamline the computing process with an algorithm that knows what to compute and what
to ignore, while preserving the accuracy of the result. “From a mathematics point of view the question is therefore: where is the information? If you know where the information is you can obviously do a major reduction in acquisition cost,” he explains. “This involves modern numerical linear algebra on top of the analysis of non-linear inverse problems, and that’s where you break fundamental barriers.” Big data for big problems The work of De Hoop and his collaborators is revolutionary largely because few – if any – have combined and connected the fields of deep learning and inverse problems. This territory is, he says, “largely unexplored in the seismic industry.” This is where the field of machine learning comes into play. The technology has made headlines this month with Google’s announcement of a “smart-reply” system: a new version of its email app NEWSBASE
which analyses an email and offers users a selection of context-sensitive replies. For de Hoop’s purposes, it is a little more complex. The seismic data are mapped, nonlinearly, into another domain, a highdimensional feature space in which an unsupervised learning stage is initiated. In the feature space, the data can be represented on a very low-dimensional digital structure. “Once you have this structure then the beauty is you have a notion of distance. You find out where the information is and then look where the data are alike, what we call classification. It’s like image recognition,” he continues. Though counterintuitive, seismic data are no longer treated as the solution to a wave equation, but as a series of patterns and relationships. “If you follow the classical differential equation approach using wave fields, you use sampling theorems. For example, I go back to the
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December 2015
Photo: Jeff Fitlow/Rice University
Drilling/Seismic
signal analysis and put so many sensors out to make sure I recover enough of the wiggles and oscillations without losing anything. Learning theory tells you something totally different – it’s not a matter of wiggles, it’s a matter of patterns.” The implications of this logic are profound. The computer can recognise tiny patterns, illusive or undetectable to the eyes of humans, and can establish those patterns faster, with less computational time and from a vastly reduced sample. “Once I know that, I don’t have to follow classical sampling, I can look at information content. I just need enough points to recover this manifold.” This is the stage that De Hoop’s research has reached, with algorithms which allow the computer to recognise persistent data constituents. “We’ve succeeded in getting a distance function and a sort of a grammar of seismic data that doesn’t come out of a differential equation any more; it comes out of big data. That, roughly speaking, is where we are. It is an intriguing field of research with a lack of proofs and a significant gap between mathematical inverse theory and deep learning, though we have plenty of conjectures. The area is extremely hot.” Seismic drones? While the findings and the mechanics of this are ground-breaking, its implications
for the industry and for geoscience are also significant. One can imagine a seismic data-gathering system with which one learns from current data where one should optimally acquire more data. This is what can be done with drones in principle, though sensors would intermittently have to be on the ground. Inverse problems theory and deep learning could also transform the depth of our understanding of geological and sedimentary processes through information gleaned from seismic data. De Hoop and his collaborators think in terms of “textures.” “Textures” are the result of physical and chemical processes which, with the correct interpretation and analysis, can be understood and predicted. “Strong scale coupling seems to play a critical role. Transforming the reconstructions to feature spaces and invoking techniques from machine learning allow us to capture the subsurface viewed in terms of textures, mixtures and geometry in a stochastic sense,” de Hoop explains. “As a realisation of a random process, we can thus infer information through classification across scales well beyond standard limitations on resolution. In comparison, ‘traditional’ seismic imaging technology is based on a simple separation of two scales.” Theories, algorithms and procedures NEWSBASE
which follow the mentioned framework, as he and his colleagues are working on, “enable one to find a data model for the earth.” It is this Herculean task, on planetary scale, which De Hoop is just beginning to realise. “Physical processes in Earth’s interior are controlled by rather few parameters, and this is encoded in the data”, he says. “The art is to capture that in one way or another, in a data driven fashion, on the one hand while revealing the coupling of the many processes on the other hand.” As we have alluded to, solving these problems is likely to take some time, though he remains encouragingly optimistic and ambitious about its prospects. “We’re working extremely hard, and we’ve built a new reference model of the earth. You need to set the bar high!” he exclaims. De Hoop’s research may not be a silverbullet technology for the industry in the short or even the medium term. Likewise, the entrenched present understanding of seismology, especially in a conservative industry and a low-price market, means we are still likely to rely on trucks and air guns for the foreseeable future. But the models made by de Hoop and his colleagues now may well be the first wave of new, complex and detailed pictures of the earth, and may even set the technological standard for the next fifty years of geological exploration. n
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ADROKGROUP.COM
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InnovOil
December 2015
Drilling/Seismic
Distributed Seismic Source™ – Eliminating the Ghost of Sources Past? GPUSA has upgraded its Distributed Seismic Source™ for marine applications, which can eliminate source ghost reflections from seismic operations
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n the August issue of InnovOil we reported on GPUSA, a Californiabased company that had recently developed a new line of seismic sources. We recently spoke to the company’s CEO, Jim Andersen, who told InnovOil that interest in the applications from oil majors and leading oilfield service companies had taken off. GPUSA has subsequently improved the technology so its products provide solutions to problems that are frequently identified as being disruptive by the industry. Latest model In October GPUSA unveiled its newest patent pending MV24 marine vibrator (with four times the active surface area of the earlier MV-12 transducer) at the 2015 Annual Meeting of the Society of Exploration Geophysicists (SEG) in New Orleans. Working in conjunction with Lenze America’s factory automation team, GPUSA engineers added the
The MV-24 Marine Vibrator has 24 inch diameter opposed piston transducers sealed to a rugged high performance flexible tire bead for long life
NEWSBASE
capability to adjust precisely the volume displacement of the MV-24 source as well as the frequency using the existing Lenze Programmable Logic Controller (PLC) touch screen. This feature allows the operator to maintain a relatively constant sound pressure level (SPL) as the source is swept across its standard 5 to 100 Hz operating band. But with the new MV-24 transducer faceplate now displacing approximately 1.5 inches at low frequency and about 1/16 of an inch at high frequency, a rugged, flexible, watertight seal had to be developed. An additional key feature of the upgrade is GPUSA’s steel-belted radial tire housing. With flexible sidewalls designed for 100M+ cycles and a bead ring tire seal similar to that proven on some of the world’s toughest off road vehicles, GPUSA believes it will stand up to rigours of oilfield use. Another step forward is that the marine vibrator’s design should be able to eliminate the source ghost reflection and its associated ghost notch, the most undesirable phenomena associated with existing marine seismic sources. Traditional seismic sources, such as air guns, cannot operate at the water’s surface because they require some amount of water column above them for proper operation. This means that when the source goes off, energy reflected from the surface
InnovOil
December 2015
page 23
Drilling/Seismic Right: IP65 Enclosure provides protection from dust, oil and water wash down. Electronics meets UL-508C standards for Industrial Control Equipment. The system is completely controlled via an easy to use touch screen and can also be controlled remotely via the Internet.
(delayed by the travel time to the surface and back) combines with the downward pulse, leading to destructive interference (ghost notch). Typically, source and receiver depth are selected to keep the ghost notch out of the desired frequency band, rather than being selected for optimal acoustic performance. Given that GPUSA’s marine
vibrator can operate at the surface, there is no ghost reflection. GPUSA’s marine vibrator sources can be mounted on the underside of specially designed surface craft and used for streamer, OBC or transition zone applications. Providing solutions to problems such as ghost reflection and ghost notch
demonstrates the strength of GPUSA’s enhanced applications and meets the industry’s need for improved seismic sources.. n Contact:
James Andersen, President & CEO Email: sales@gpusa-ca.com Web: www.gpusa-ca.com
Saltel Expandable Steel Patch An enhanced Oil Recovery Solution Innovative setting process with high pressure inflatable packer contrasts with traditional cone setting Saltel Industries has developed, tested and successfully trialed the use of an expandable stainless steel Patch (steel tube + outer skin with a profiled sealing system) for perforation shut-off. Run on tubing or e-CTU, it is expanded downhole using an inflatable packer to create a high pressure inner lining inside the casing. Applications include water and gas shut-off, modifying injection profiles, and repairing short lengths of damaged or corroded casing.
Benefits • A proven technology ( + 500 patches set worldwide since 2010 ) • 97 % Success ratio • Small run-in diameter, simple setting process • Minimum reduction in ID, Large through passage • A reactive skilled operations team available worldwide • Fast feasibility study, job evaluation and proposal • Patch availability : short lead times & fast setting www.saltel-industries.com/io1
www.saltel-industries.com/io1
NEWSBASE
InnovOil
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September 2015
Managing mercury Johnson Matthey’s fixed bed technology PURASPEC JM TM is a simple and effective way to remove mercury from hydrocarbon gas and liquid processing
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ercury is a naturally occurring trace element found in fossil fuels (see table 1). It is cycled and recycled constantly in the environment and is present due to natural and anthropogenic activities. As reliance on hydrocarbons has increased, the amount of mercury emitted into the environment has also risen. Mercury is highly toxic to humans and animals, so ensuring the element does not contaminate the environment and enter the food chain is a key concern. As the industry becomes more socially responsible, companies are increasingly looking for effective technologies to remove mercury from water. Mercury removal: current practice In oil and gas processing, mercury is removed from hydrocarbon streams to protect equipment from corrosion, minimise emissions to the environment,
meet product specifications, prevent mercury poisoning of precious metal catalysts, and reduce difficulties in the handling and disposal of contaminated metal. The prevailing species in these streams is elemental mercury. Johnson Matthey, a UK-based leader in speciality chemicals and sustainable technologies, provides industry-proven PURASPECJM for the removal of elemental mercury from hydrocarbon gases and liquids. It is a fixed bed technology that uses highly porous metal sulphide granules. PURASPECJM completely removes elemental mercury to prevent distribution through the plant and emissions to the environment. The technology is in the granule. Elemental mercury chemically reacts with the active metal sulphide bound within the granule so that it is trapped in a stable form, this makes PURASPEC JM
Table 1: Mercury Levels and Species in Fossil Fuels Fossil Fuel Coal Oil Natural Gas
Mercury Compounds present Pyrites Elemental and organomercury Elemental
effective in both gas and liquid applications. The problem In oil and gas processing, mercury partitions to different streams largely depending on the solubility of species in given fluids (see table 2). The predominant species of mercury in produced water are ionic and colloidal. For offshore operators produced water is treated to meet discharge specifications or is reinjected. For onshore plants, produced or process water is treated to meet discharge specifications or sent to a downstream effluent treatment process. Water is a non-saleable product and with limited downstream equipment to
Table 2: Approx solubility of mercury compounds in liquids at 25°C Amount 10 – 100+ ppb 10 – 30 000 ppb Trace up to 4000 πg/m3
NEWSBASE
Species Elemental (Hg0) Ionic (e.g. HgCl2) Colloidal (e.g. HgS)
Water (ppm) 0.05 70000 0.01
Oil (ppm) 2 >10 <0.01
December 2015
InnovOil
monitor, report and remove mercury from produced water.
protect, there is not a significant driver for operators to remove mercury from a process perspective. For mercury being discharged overboard, there are environmental regulations in place in areas with high mercury concentrations, such as the Gulf of Thailand. Here, there is a maximum level of 10 ppb of mercury for overboard discharge. But globally there are few enforced restrictions for operators to
The solution Existing methods for removing mercury from water can be chemical and process intensive, requiring large footprints. These processes require the dosing of chemicals and additives for the flocculation of mercury, which then needs to be separated and disposed of. The large footprints make installation difficult for existing or new facilities where space is limited. Johnson Matthey has received an increasing number of enquiries for the removal of mercury from water, with outlet specifications ranging from 1 â&#x20AC;&#x201C; 10 ppb w/w Hg. Using expertise in fixed bed technologies, Johnson Matthey has developed a new sorbent for the removal of ionic mercury, such as dissolved HgCl2. The technology is a stabilised thiol-modified support with high mercury affinity. Mercury chemically binds to the active thiol sites so that it is permanently removed from the produced water in a stable form. The patented material offers the benefits of low capital cost and no utility requirements. A manufacturing route has NEWSBASE
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been established, and the material can be supplied for customer trials and at full scale. With the concept having been proven in lab tests, the PURASPECJM technology has been optimised to improve performance. Mercury removal rate limitations have been investigated and this work has resulted in an optimised granule size to enhance kinetics, whilst maintaining operational practicality. Integrated technology In collaboration with leading filtration company PECOFacetTM, a CLARCOR company, Johnson Matthey has incorporated the sorbent into an integrated technology for the complete removal of mercury from produced water streams. Using specialist equipment and a scaled-down version of the technology, the system has been developed and optimised in laboratory trials. With on-site testing and analytical capability, Johnson Matthey and PECOFacet are able to work with operators to develop bespoke onshore and offshore solutions to remove mercury from process water streams. n Contact: Heather Whittenbury Tel: +44 (0)1642 522 741 Email: Heather.Whittenbury@matthey.com Web: www.jmprotech.com/puraspec
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December 2015
InnovOil
An inspector calls
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Cyberhawk Innovations continues to push the envelope of ROAV operations, having conducted the world’s first drone cargo tank inspection with Maersk
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nnovOil – amongst other industry observers – has charted the progress of trailblazers Cyberhawk Innovations for the past few years. This month brought the news that it had undertaken another pioneering operation, succeeding in inspecting a cargo oil tank on an operational floating production storage and offloading (FPSO) vessel, using a remotely operated aerial vehicle (ROAV). The Scotland-based aerial inspection and surveying company has been surveying infrastructure since 2009 and has used the technology offshore since early 2012. Since then, many of the jobs previously undertaken by rope access technicians have been replaced by these airborne drones, with the aim of saving time and money, and reducing the safety risk to workers. The trend now appears to be continuing with tank inspection, replacing workers who would otherwise manually inspect high-stress areas within cargo tanks, such as stiffeners, brackets, bracing, webs and stringers. It builds on a wider movement to increase the efficiency and automation of tank inspection. For instance, a similar approach is being investigated by Teledyne Seabotix, using its tracked, little benthic crawler (LBC) vehicle. Currently used to inspect ship hulls, Teledyne believes it may be possible to employ a similar modified vehicle to inspect fuel tanks with cargo still inside (see InnovOil Issue 30 from February 2015). With tanks In the case of the most recent operation, Cyberhawk’s two-man ROAV team – consisting of an ROAV pilot and inspection engineer – were dispatched to Maersk Oil’s Gryphon Alpha FPSO to inspect one of its twelve tanks. The vessel itself has a total storage capacity of 525,000 barrels, across 12 gas-blanketed cargo tanks. The inspection of the critical components of the tank was completed within a day, although this speed is likely to improve significantly, it is already much faster than the 3-4 days needed for
a similar rope-access inspection project. In cases where action is needed or closer manual inspection is necessary, the operator can use the data gathered by the drone to inform and plan accordingly, allowing for lower-cost and ideally more effective maintenance. The Cyberhawk UAV itself can be equipped with a variety of tools, from a digital single-lens reflex (DSLR) or compact camera, to a thermal camera or gas sensors. The system is flown by a pilot, working on a line-of-sight basis, with an inspection engineer in attendance. Each flight is 15 minutes, but multiple batteries are used to ensure the inspection is continuous all day. Working in confined conditions, however, brings added challenges. Cyberhawk founder and CTO Malcolm Connolly, who was part of the team offshore on the FPSO for the duration of the project, explained to InnovOil: “The tank environment is very different from what we normally fly in for our other inspections projects. It’s dirty, dark, noisy, and there is restricted space with no GPS signal. This environment presented a whole host of obvious and NEWSBASE
non-obvious technical challenges that we had to overcome in order to fly a ROAV. Maersk set us a difficult task requiring a lot of testing and modification to our equipment prior to mobilisation. We had to make changes to our hardware, software and procedures in order to produce the desired results. It’s been worth all the effort, though; this is a significant step forwards for inspection in confined spaces. Our next big challenge is to be able to carry out the inspection remotely without having to put people in the tank at all ” he added. Phillip Buchan, Cyberhawk’s commercial director, added that Maersk had been early adopters and strong supporters of the technology, and that this relationship had led to co-operation on this new service. “We’ve worked with Maersk a lot over the past few years, they’re really happy with the work that we’ve done so there has been quite a bit of trust built up there,” he said in a phone interview. “We have completed many projects with Maersk Oil since first working together in 2013. Both parties were keen to develop an effective ROAV inspection method for FPSO cargo oil tanks, and the successful completion of this project has demonstrated that this is now possible,” Crucially, the proven system established by Maersk and Cyberhawk means that the inspection technique can now be applied to a whole range of areas. “It’s now a new service that we can offer. We’ve proven the concept and it’s something that we can now confidently do. There are applications in lots of different areas from FPSOs, bulk carriers and tankers, even onshore in places like power station boilers and oil storage tanks,” Buchan enthused. “We’ve had great feedback,” he concluded. “It’s a significant step forward in this sector.” n Contact:
Philip Buchan, Commercial Directors Tel: +44 (0)1506 592 187 Email: info@thecyberhawk.com Web: www.thecyberhawk.com
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News in brief
Wintershall teams up with ADNOC for chemical EOR
Wintershall has signed an agreement with Abu Dhabi National Oil Co. (ADNOC) to co-operate on research and development (R&D) for chemical enhanced oil recovery (cEOR) technologies tailored to raise recovery rates at the emirate’s fields. The state-owned oil firm has experimented with various advanced recovery techniques at its maturing and most-complex fields and has followed an industry trend in signing up international oil company (IOC) partners to assist in developing bespoke solutions. Globally, chemical injection is the leastused of the three main EOR techniques but has been gaining ground, with Oman the regional pioneer and a pilot project under way in Abu Dhabi outside ADNOC’s purview. Meanwhile, German firm Wintershall has a stated goal of making Abu Dhabi the focus of its planned regional expansion and the firm cites ownership by the world’s largest chemicals company, BASF, as offering particular advantages in the new ADNOC partnership. The firm’s proprietary schizophyllan bio-polymer, which has been field-tested at Wintershall’s Bockstedt facility in Germany, is likely to be part of the latest deal. The memorandum of understanding (MoU) signed on the sidelines of the ADIPEC conference on November 10 and commits Wintershall and ADNOC to developing chemical recovery technologies customised to meet the conditions of high temperatures and high salinity found in the carbonate reservoirs of local oil fields. Laboratory trials are envisaged as leading to a pilot project, but the fields to be focussed
on remain unspecified. Wintershall’s existing presence in the emirate comprises an agreement signed in 2012 in partnership with Austria’s OMV to carry out appraisal on the shallow-water Shuweihat sour gas and condensate field – a vital project as the emirate seeks to urgently raise increasingly stretched domestic gas production through the technicallychallenging and costly development of sour gas reserves. The first appraisal well was spudded in late 2014 with promising results reported. The company was also said to be among those originally invited to bid to become one of ADNOC’s new foreign partners in the reconstituted Abu Dhabi Company for Onshore Petroleum Operations (ADCO) concession on the basis of its EOR expertise, which the government has deemed a key factor in its selection – although the German firm has not recently been linked with the ongoing negotiations over the remaining stakes. ADNOC has signed a series of R&D agreements with IOCs over the past year in the service of the broad three-fold goal of improving recovery rates to around 70% from around 50%, of maintaining output levels at older fields, and of developing new fields previously considered too technically challenging and thus costly to develop. Super-major BP, which openly remains in the running for an ADCO stake, signed a deal in late 2014 to work on adapting a new water-flooding EOR technology for local purposes while France’s Total signed a deal in January – shortly before becoming the first of the state firm’s new ADCO partners – to assist in the mapping of the emirate’s NEWSBASE
deep carbonate reservoirs to determine their suitability for various EOR extraction techniques. A more wide-ranging agreement entailing investment estimated at US$500 million was signed in February with US firm Occidental Petroleum (Oxy) to carry out studies and exploration at the Ghasha and Hail fields – both had previously been passed over for development. ADNOC is also working in parallel to develop local expertise in order to gain more lasting returns from the particular technology partnerships, announcing the planned establishment of a new research centre at its Petroleum Institute last month – with funding assistance from BP, Royal Dutch Shell, Total and Japan Oil Development Co. (JODCO). The state oil company has begun experimental deployment of EOR technologies, with a pilot carbon dioxide (CO2) injection project at the onshore Rumiatha field and some advanced waterbased technologies being trialled at the offshore Lower Zakum asset. Testing of polymer and surfactant injection was begun by Total in 2013 at the offshore Abu Al-Bukhoosh field – a mature field in production for more than 40 years – which it operates in partnership with Japan’s Inpex. More so than with thermal and gas-based EOR, chemical injection projects require reservoir-specific solutions, hence their general paucity compared to the alternatives. However, technological progress achieved during the sustained period of high oil prices before last year’s slump – when many projects previously considered too costly became economically viable – led to improved efficiency of the chemical injection process and lower costs while Middle Eastern producers have been forced to confront declines at their older fields only reversible by resorting to more technologicallydemanding, higher-cost extraction methods. Oman has been the pioneer in this regard, with the region’s first full-scale polymerflooding EOR project brought on stream in 2010 by the government/Shell joint venture Petroleum Development Oman (PDO) at the Marmul field – arresting decline and reversing output losses. This article was sourced from the NewsBase Middle East Oil & Gas Monitor (MEOG). For more information or to request a free trial, contact: news@newsbase.com
December 2015
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News in brief
CPECC sets up joint venture in Mozambique China Petroleum Engineering and Construction Corp. (CPECC) has established a joint venture with ENH Logistics to work engineering, procurement and construction (EPC) contracts in Mozambique. The venture will prioritise engineering and construction jobs covering natural gas liquefaction, oil and gas ground facilities, pipeline and storage as well as refining projects in Mozambique. CPECC is a unit of state-owned China National Petroleum Corp. (CNPC) while ENH Logistics is controlled by Mozambique’s stateowned Empresa Nacional de Hidrocarbonetos (ENH). CNPC said on its website that the joint venture, which has a registered capital of US$800,000, will aim to introduce oil and gas know-how, technology and management from China to Mozambique. CPECC and ENH Logistics each have a 50% stake in the new company, Mozambique-China Petroleum. Sources have said the joint venture has already been assured of the engineering and construction services for the Integrated Logistics Centre to support the oil and gas industry in Cabo Delgado. The infrastructure of the Integrated Logistics Centre will be ready by the third quarter of 2016. The first phase of the project will cost US$186 million. Mozambique President Filipe Nyusi, who was elected in October, is from Cabo Delgado. His election has been seen as
representing a shift in the East African country, with more power being held by northern interests. CPECC established its Mozambique outfit in 2013, the same year CNPC bought a 28.57% stake in Eni East Africa, owner of a 70% stake in the offshore Area 4 gas block in Mozambique, with an investment of US$4.2 billion. The block is located in Mozambique’s Rovuma Basin and is estimated to hold 85 trillion cubic feet (2.4 trillion cubic metres) of gas in place. In exchange, CNPC agreed to allow Eni to conduct a joint study on the Rongchang shale gas block in Sichuan Province in southwestern China. But Eni is understood to have backed out from the study owing to the block’s limited prospectivity. Edited by Ed Reed edreed@newsbase.com
HDPE pipeline protection Growing urbanisation and industrialisation are increasing the risks for existing and future pipelines, as concrete slabs – long used as the primary method of protection – are encountering more and more limitations. Yannick Joubeaux, CEO of French firm Overpipe commented that: “This is why Overpipe developed a totally innovative solution: a 15-mm thick high-density polyethylene (HDPE) plate, which can resist the assault of a 32-tonne excavator.” Overpipe was asked by its main client, Gaz de France, to develop new concepts for mechanical protections against thirdparty risks. Interference comes mainly from excavators, and counts for about 50% of all accidents on oil and gas transportation lines worldwide. Overpipe HDPE plates were immediately seen as an adequate solution to protect existing lines close to inhabited areas. “They are very resistant, very light, easy to transport, easy to install (can be installed by two unskilled workers without any special tools), easy to store with the security of industrial checked production, easy to remove for inspection or repair of the pipe and a lot cheaper solution,” Joubeaux added. Over the past five years, Overpipe plates has been installed to protect buried pipelines and network by France’s main pipe owners including Gaz de France, Total and Air Liquide. OVERPIPE
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December 2015
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News in brief
Petronas awards jack-up contract to UMW Malaysian offshore services firm UMW Oil & Gas has been awarded a contract by Petronas’ upstream subsidiary Carigali to deploy a jack-up rig in a domestic shallowwater project. Bursa Malaysia-listed UMW said it would drill seven wells over seven months and has an option for more. The firm did not say how much the contract was worth but a stock filing said it would contribute substantially to earnings this year and next. The location of the contract, which began in mid-October, was not identified. Carigali, the upstream arm of national oil company (NOC) Petronas, is engaged in a several active developments off the Sarawak and Sabah coasts of eastern Malaysia. Carigali has recently been working on extending the life of the mature D18 oilfield off Sarawak through Petronas’ enhanced oil recovery programmes (EOR). The contract announcement pushed up UMW’s share price by more than 5% in a sign of confidence in a beleaguered sector. Malaysia has one of Southeast Asia’s biggest offshore services sectors with more than 30 main operators and dozens of support businesses. Fast track data demonstrates Many of them are dependent on work from Petronas which this year cut 20% basement
off its US$16.5 billion capital expenditure programme for 2015. UMW’s rig contract is likely to be on a daily charter rate of at least US$110,000, the Malaysian Insider quoted Alliance DBS Research as saying. Alliance noted that UMW has four other jack-up rigs unemployed, one of which is new. “These will continue to weigh on earnings in the near to medium term as demand for jack-up drilling rigs continues to be very weak,” Alliance said. Before the global oil price collapse Petronas was seeking to revive declining domestic oil production by hiring Malaysian offshore service firms to work on EOR schemes in mature fields and via risk service contracts (RSCs) to work in small marginal fields. Edited by Andrew Kemp andrew.kemp@newsbase.com
Polarcus completes major seismic shoot
which was undertaken with DownUnder GeoSolutions, was the largest ever-seismic survey conducted offshore Australia. The acquisition took 11 months, according to Polarcus, and included the Beagle and Bedout sub-basins. It also took in the Phoenix South oil discovery, in permit WA-435-P offshore Western Australia. Quadrant Energy operates the licence with a 40% stake, while JX Nippon, Finder Exploration and Carnarvon Petroleum each hold 20% interests. “The discovery well opens up the potential for a new oil province across an area historically only considered prospective for gas,” Polarcus said, referring to Phoenix South-1, which was spudded on May 25, 2014. Several prospects and leads have been identified for drilling programmes to be carried out over the next two years. It will start with the Quadrant-led consortium’s planned Roc-1 well in WA-437-P this month, Polarcus said. Roc-1, which lies in around 80 metres of water, will be drilled using a jack-up at an estimated cost of A$45 million (US$32 million). In the Beagle sub-basin, leads were identified with more than 1 billion barrels of oil potential, Polarcus said. Meanwhile, in the Bedout sub-basin, Roc-1 is targeting 100 million barrels of oil potential. “This is a milestone achievement for Polarcus completing its first multi-client the Tertiary survey in Australia, to withPrecambrian high prefunding supported by eight oil companies,” Polarcus’
Australia Northern Carnarvon - Roebuck Basin Offshore geophysical firm Polarcus has
Capreolus 3D Multi-Clientcompleted Survey, North West a major new basin-wide 3-DShelf seismic programme offshore Australia’s North West Shelf (NWS), in one of the shelf’s few remaining underexplored parts. superior seismic imaging The Dubai-headquartered firm claimsfrom that the Capreolus 3-D multi-client project,
Beagle Sub-Basin
W
Large Jurassic tilted fault blocks
Thouin Graben
Large Triassic tilted fault blocks
Post Callovian updip pinchout
Aptian Callovian
Nr Base Jurassic
Jurassic Source
Triassic Source
Permian
Lwr Triassic Source
Fast track PSTM
Fast track data demonstrates superior seismic imaging from the Tertiary to Precambrian basement NEWSBASE
Rowley Sub-Basin
E
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multi-client senior vice president, Stephen Doyle, said. “The resulting high fold broadband 3-D data has delivered a step change in data quality and has the potential to help the industry find many more large oil discoveries in this underexplored frontier.” The data are currently being processed and final data products are anticipated to be delivered in the first half of 2016, Polarcus said. The NWS, in the Pilbara region off the coast of Western Australia, contains extensive oil and gas resources. The giant NWS Venture, which supplies domestic and international markets, currently accounts for more than one third of Australia’s oil and gas production. Perth-based Woodside Petroleum has been operating the NWS Venture since 1984. The project is split between a total of six partners comprising Chevron, BP, BHP Billiton, Japan Australia LNG and Royal Dutch Shell, which each hold a one-sixth share in the project, alongside Woodside. Edited by Andrew Kemp andrew.kemp@newsbase.com
Lianhe Energy signs tech deal for new CTG plant
from CTG projects in China’s far west to its southern coast. The 130 billion yuan (US$20.5 billion) pipeline will run 8,400 km from the northwestern region of Xinjiang to Guangdong Province and carry up to 30 billion cubic metres per year of gas. Sinopec said it could also eventually be used to transport conventional gas, shale gas and coalbed methane (CBM). In 2014, the major said that it would push ahead with controversial plans to build China’s biggest CTG plant – an 8 bcm per year facility in Xinjiang. CTG plants have been criticised by environmental groups, partly because of the huge volumes of water used in the gasification process – a significant issue in arid regions such as Xinjiang. They also produce large amounts of carbon dioxide (CO2). Many plants built so far have also been beset by massive cost overruns. China’s National Energy Administration (NEA) said in July that new projects would only be approved in regions with enough water supply. Edited by Andrew Kemp andrew.kemp@newsbase.com
Subsea 7 secures major Premier Oil deal SUBSEA 7 racked up yet another major deal last week that could help it to recover from the significant dip in revenues that it endured in the three months to September 30. The contractor signed an agreement with Premier Oil to provide concept engineering, front-end engineering design (FEED), subsea umbilical risers flowlines (SURF) project execution and field of life operations for Premier’s activities in the UK, Norway and the Falkland Islands. The five-year partnership frame agreement includes extension options and will also enable Subsea 7 to participate in relevant decommissioning work by Premier. Subsea 7 is already supporting the execution of Premier’s Catcher development in the North Sea. The Premier deal comes hot on the heels of another contract coup for Subsea 7 – a long-term deal it signed last month with the UK’s Centrica. The five-year agreement – which will see Baotou City, Inner Mongolia
INNER Mongolia Lianhe Energy has signed a deal with Johnson Matthey Process Technologies for methanation technology plus engineering, catalysts and technical services for a new coal-to-gas (CTG) plant in China. The plant, which will be located in Baotou in China’s Inner Mongolia Autonomous Region, will produce synthetic gas (syngas) from coal and then turn it into LNG. Slated to enter operations in 2017, the plant will employ Johnson Matthey’s proprietary methanation process technology, which converts carbon oxides and hydrogen to methane. The methane can then be exported via pipeline as substitute natural gas (SNG) or shipped in tankers as LNG. Johnson Matthey technology has in the last few years been used in a number of similar plants in China, the first of which are already operational and supplying SNG to Chinese cities, including Beijing. The news comes less than a month after Beijing approved energy giant Sinopec’s plan to build a pipeline to transport syngas NEWSBASE
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Rigs lined up in the Cromarty Firth
Subsea 7 support Centrica on an exclusive basis throughout early phase concept engineering, FEED, SURF project execution and life of field operations – applies to Centrica’s portfolio on the Norwegian Continental Shelf (NCS). As with the Premier deal, Subsea 7 is charged here with offering development solutions that minimise complexity, cost and risk in order to help Centrica build viable business cases. Work on the contract was set to start immediately with the execution of a FEED study for Centrica’s Butch field development. Subsea remains bullish on the fundamental long-term outlook for deepwater subsea field developments, its CEO Jean Cahuzac said this week – possibly buoyed by its latest contract wins. In the third quarter, however, its revenue plunged US$702 million from a year earlier to US$1.2 billion, he revealed in the same presentation. During the quarter, its global vessel utilisation was also just 74%, reflecting a reduction in life of field work in the Northern Hemisphere and lower activity levels as certain projects completed their offshore phases. Subsea 7 now predicts revenue in 2016 to come in “significantly lower” than its forecast for 2015. Edited by Ryan Stevenson ryans@newsbase.com
GeoPartners announced cross-border survey success GeoPartners, in partnership with MAGE, Seabird Exploration and DownUnder GeoSolutions (DUG), reports completion
of the acquisition of a new Ireland/UK multiclient 2-D seismic survey. This is the first broadband long offset cross border survey of its kind, comprises a total of 5,124 line km and is located mostly in the Irish North Celtic Sea and St Georges Channel. This project will provide high quality regional data in an area of increasing industry interest following the 28th licensing round awards on the UK side of the median line and several new licence options on the Irish side. However, a considerable portion of this area currently remains unlicensed. Broadband processing and imaging will be carried out by DUG, utilising their deghosting solution, DUG Broad. Processing is ongoing and is due for completion early quarter two of 2016. The survey is well supported by industry funding and the data is now available for licensing at early participant terms until the end of 2015. GEOPARTNERS
North Sea decommissioning costs set to rise The cost of dismantling oil production facilities in the UK North Sea over the next decade will be higher than previously forecast as more fields are due to halt production, according to a group representing the British industry. Decommissioning costs will rise to £16.9 billion (US$25.7 billion) for the 10 years to 2024, compared with last year’s guidance of £14.6 billion, according to Oil & Gas UK. Plugging and abandoning wells makes up the biggest part of the decommissioning costs, at about 46%. Over the next decade, 79 platforms are forecast for removal, about 17% of the 470 installations that will need decommissioning NEWSBASE
over the next 30 to 40 years, it said. Crude has fallen more than 45% in the last year, making some projects uneconomic and forcing producers to accelerate the closure of fields. As many as 140 fields in the UK North Sea could close over the next five years, even if oil recovered to US$85 per barrel, consultants Wood Mackenzie said in September. Maersk Oil is seeking approval from the UK Oil & Gas Authority to stop production from its North Sea Janice installation next year, the explorer said in August. OIL & GAS UK
Russia plans liquefaction plant at Vysotsk Russia has decided to expand the Vysotsk seaport, in the northwestern Leningrad Oblast, and build an LNG production and transhipment terminal there, local media reported on November 13. The Russian government posted a directive calling for the expansion of the seaport by including land plots on the Ryuyevyalinniyemi Peninsula, where an LNG production and transhipment terminal with a capacity of 660,000 tonnes will be built. The project is backed by Kriogaz, which is owned by Gazprombank, the third largest bank in the Russian Federation. Gazprombank was founded by Russia’s state-controlled Gazprom. Construction on the project is scheduled to start in 2016. Plans also include construction of an offshoot of the Leningrad-Vyborg-State Border trunk gas pipeline. The Leningrad governor, Alexander Drozdenko, has held discussions with representatives of Gazprombank, which
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plans to invest about 50 billion rubles (US$765.8 million) in the project. Drozdenko noted the importance of the project to the region. “We are praising Gazprombank’s decision to support the project, and we are also ready to help convert land plots into industrial sites,” the governor said. He added that the terminal’s construction would create additional jobs in the region. Gazprombank’s first vice president, Yaroslav Golko, said the investor and the Leningrad administration were maintaining a constructive dialogue. “All project aspects and agreements are promptly co-ordinated. The project has not faced any problems to date,” he said. In addition to its liquefaction capacity, the terminal will have 11.6 million tonnes per year of oil product throughput capacity, with construction investment to date exceeding US$500 million. The terminal so far has been used exclusively for the transhipment of light and black oil, produced at the company‘s petroleum refineries. As of late 2014, the port’s freight turnover was up by 7.9% to 17.4 million tonnes. The move for small-scale
liquefaction is aligned with a number of similar plans around the world. While companies may be reticent about committing to megaproject LNG plans, more modest projects offer an opportunity to access resources or markets that may be otherwise stranded. Edited by Joe Murphy joem@newsbase.com
Honeywell wins Karbala refinery technology contract US-based Honeywell has been awarded the technology supply contract for the multibillion-dollar new refinery under construction in southern Iraq. The facility in Karbala is aimed at alleviating an acute fuel shortage that has contributed to recent protests in the city and elsewhere in the region about
the government’s apparent inability to provide basic services to the oil-rich region. Perhaps galvanised by the dangerously-rising discontent, statebacked refining projects in the south have accelerated over the past six months despite Baghdad’s mounting fiscal woes. A series of subcontract awards at Karbala have quieted rumours of delays since the main contractor’s appointment early last year and a company was selected last month to carry out the long-awaited upgrade of the dilapidated refinery at Basra – another hotbed of popular frustration. The Karbala refinery project calls for the construction of a 140,000 barrel-perday facility at the site, around 120 km south of Baghdad, comprising 20 units processing a range of products capable of meeting Euro V standards, including diesel, fuel oil, gasoline, jet fuel and LPG. A consortium of South Korean companies led by Hyundai Engineering & Construction (E&C) and including GS E&C and SK E&C was awarded the US$6 billion engineering, procurement and construction (EPC) contract in early 2014
Karbala has seen recent protests about the government’s apparent inability to provide basic services to the oil-rich region
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“Falling oil prices, shrinking government subsidies and a lack of technology, among other things, will hurt private companies’ chances to succeed in shale gas exploration.” Edited by Anna Kachkova annak@newsbase.com
Benthic awarded geotechnical site investigation contracts by the government’s State Company for Oil Projects (SCOP). The state-owned firm assumed client responsibility following the failure of attempts to attract private-sector investors to carry out the scheme. France’s Technip was awarded the project management consultancy (PMC) contract the previous year, having executed front-end engineering and design (FEED) in 2009/10. Honeywell subsidiary UOP will licence several process technologies – including those for isomerisation, fluid catalytic cracking, continuous catalyst regeneration and residue hydrotreating. Honeywell will also licence its automation and controls systems. Edited by Ian Simm ians@newsbase.com
China to miss shale 2015 output goal China looks set to fall short of its aim of producing 6.5 billion cubic metres of shale gas during 2015 owing to a number of factors, including the country’s challenging geology. Last week the president of Sinopec’s Research Institute of Petroleum Exploration and Development, Jin Zhijun, confirmed that the company had produced just under 2 bcm of shale gas during the first 10 months of 2015,
placing the company’s goal of producing 3.5 bcm over the course of the year under serious threat. As a result Beijing’s target is now highly unlikely to be met. Despite a concerted push by China’s government in recent years, shale exploration has seen interest wane further since the collapse in oil and gas prices. The economics of shale have come into question – in the US, the costs per shale well stand at US$10 million or less, compared to a figure of between US$60-$70 million per well in China, as cited in a recent report by Shanghai Securities News. At the same time, Beijing has cut subsidies for shale explorers over 2016-20, placing narrow margins for producers under even greater pressure. All this may have put the future of China’s third shale licensing round in doubt, but on November 16 a researcher at a government think-tank, Guo Jiaofeng, told the China Daily that the round was still likely to go ahead within the next two months. This round, he said, will most likely see a number of public firms enter the bidding as part of Beijing’s bid to broaden the industry away from its focus on staterun enterprises (SOEs). A Southwest Petroleum University professor, He Sha, went on to tell the newspaper that interest from the industry might well be slight owing to the current price environment. “It may not be the best time for private companies to bid for shale parcels,” he said. NEWSBASE
Benthic, a global geosciences company, has been awarded two contracts by Woodside to undertake offshore geotechnical site investigations for the proposed Browse floating liquefied natural gas (FLNG) Development and the Greater Enfield Development located off the coast of Western Australia. Benthic’s PROD3 (Portable Remotely Operated Drill) will execute the projects consecutively from the Jaya Vigilant. Benthic will begin operations in the 4th quarter of 2015 at the proposed Browse FLNG Development site. PROD3 will complete in-situ testing and sampling to identify the soil conditions and geotechnical properties of the soil. PROD will penetrate to depths of up to 35 meters below the mudline in maximum water depths of 620 meters. Following project completion, the Jaya Vigilant will transit to the Greater Enfield Development site to perform similar site investigation services. PROD has successfully executed multiple projects in the region, including the 2014 Browse FLNG investigation, providing Woodside with substantial experience and knowledge of the region’s seabed conditions. Following offshore operations, geotechnical data reports will be provided to Woodside. “PROD’s previous success working in the Browse Gas Field and its adjacent sectors provides confidence that the site investigations will be executed to Woodside’s full satisfaction,” stated Benthic CEO Steve Pywell. n BENTHIC
27 - 28 January 2016 Hilton & Dinner at JW Marriott Bogotรก, Colombia
LATIN AMERICA ASSEMBLY AND DINNER
www.oilandgascouncil.com/event/latam
The defining series of events for the global oil and gas, finance and investment communities comes to Latin America 2016 Speakers Erik Bethel Managing Director, Darby Private Equity
William (Bill) Schlesing Partner, KBC
Lead Partners
Gary Guidry CEO, Gran Tierra Energy
James Cunningham Managing Director, Denham Capital
December 2015
InnovOil
What next …?
To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections If you would like to learn more about the potential of Betafib® MCF, or are interested in formulating new chemical applications, contact Francesco Staps at Cosun Biobased Products on +31 6 4619 8729 or email francesco.staps@cosun.com For more details about any of the equipment mentioned by Darrin Yenzer at Cameron International, please contact Timothy Taylor on +1 (0)281 901 3226 or email tim.taylor@c-a-m.com If you are interested in enquiring about the latest update to GPUSA’s Distributed Seismic Source™ technology – in particular the MV-24 – please speak to the company’s president and CEO James Andersen via sales@gpusa-ca.com or visit www.gpusa-ca.com To learn more about Lux Research’s report “Identifying Ways to Reduce Drilling Budgets in the Low Oil Price Environment,” contact Carole.jacques@luxresearchinc.com or visit www.luxresearchinc.com To speak to one of Adrok’s team about how the Atomic Dielectric Resonance (ADR) scanner can make exploration projects greener, cheaper, faster, deeper and better, contact revolution@adrokgroup.com or visit www.adrokgroup.com If Cyberhawk’s new, cutting-edge tank inspection techniques could be of use to your business, please contact commercial director Philip Buchan on +44 (0)1506 592 187 or email info@thecyberhawk.com If PURASPECJM technology is the solution you need for mercury removal, contact Heather Whittenbury at Johnson Matthey on +44 (0)1642 522741 or email Heather.Whittenbury@matthey.com RigDeluge® can offer superior fire protection and safety performance on your offshore asset. To make an enquiry, speak to Tyco via +44 (0) 161 455 4400 or visit www.tyco.com/markets/oil-gas
NEWSBASE
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An asset to energy professionals
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InnovOil, from the NewsBase group, is a technology-driven, monthly magazine which aims Andy Hill, Group Marketing Manager to provide a platform for innovators and engineers to share to share their ideas and expertise. IPU Group Our publication remains a trusted, solicited information source for technology news across the complete spectrum of the upstream, midstream and downtream oil andwith gas the sectors. “We were pleased
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