InnovOil Issue 50 March 2017

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NEWSBASE

Bringing you the latest innovations in exploration, production and refining Issue 50

March 2017

LIFTED SPIRTS

Decom forecasts offer new opportunities Page 15

DECISIONS, DECISIONS

Motive Drilling’s brings automated decision-making to the drilling market Page 8

TRACKING FUGITIVES

Statoil trials methane leak monitoring Page 24

ITF launches Innovation Network to shine a light on SME Technology Development for the Oil & Gas Industry

The aim of the ITF Innovation Network is to provide an effective mechanism for technology developers to promote their technology development efforts to ITF members and the wider industry.

This will be an active and evolving community where we will encourage discussion and engagement on technology qualification, field trials, joint industry projects and new technologies that can be quickly implemented on projects.

Please register to join our community of Technology Developers, https://network.itfenergy.com or contact a member of our team at innovate@itfenergy.com for more information.

FACILITATE COLLABORATE INNOVATE

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InnovOil

March 2017

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Inside A note from the Editor

5

Electric ink

6

Good decisions

8

3D printed liquid sensors

Contacts: Media Director Ryan Stevenson ryans@newsbase.com

Motive Drilling on automated decision-making

On the radar

Media Sales

12

Charles Villiers Email: charlesv@newsbase.com

DECOMISSIONING 15

Kevin John kevinj@newsbase.com

Decom together

Editor Andrew Dykes andrewd@newsbase.com

Service consolidation changes the landscape

Challenge and opportunity 18

NewsBase Limited Centrum House, 108-114 Dundas Street Edinburgh EH3 5DQ

Decom spending shows market needs

Design: Michael Gill michael@michaelgill.co.uk www.michaelgill.eu

P&A progress

22

The fugitives

24

Pass the pre-salt

26

The right path

28

Go with the Flow

29

Get hydrated

30

Dry off

32

News in brief

34

Statoil tackles methane monitoring

Petrobras and Halliburton co-operate on new tech

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Seatooth and Photosynergy collaborate

and refining March 2017

LIFTED SPIRTSr

Issue 50

20

Interwell’s thermite method

www.newsbase.com www.innovoil.co.uk

ction ations in exploration, produ Bringing you the latest innov

Source code

Sea-Source on transforming Kilkeel

Phone: +44 (0)131 478 7000

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Decom forecasts offe new opportunities

Valves from Oxford spin-out

Page 15

Jilin University on methane hydrate progress

ExxonMobil and compact gas drying 32 S DECISIONated DECISIONS,’s brings autom

Motive Drilling drilling market decision-making to the Page 6

Contacts 41

TIVES TRACKING FUGI ne leak monitoring Statoil trials metha Page 24

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Wednesday 1st March, 2017 AECC, Aberdeen

The ITF Technology Showcase is a collaborative, innovation and technology focused exhibition and conference.

“Technology In Action” Opportunity to Adopt The 2017 ITF Technology Showcase is the industry event that innovators and operators alike can’t afford to miss. The conference and exhibition brings together some of the brightest minds from inside and outside of oil and gas to challenge current thinking and bring fresh focus on progressing new solutions.

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• All day, high quality networking with a targeted audience with a shared goal around progressing technology development.

• Credible, themed tech presentations facilitated by oil and gas operators with a keen interest on getting technology to market through the most effective and efficient routes possible.

To register now or book space in the Innovation Hall, please visit showcase.itfenergy.com

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March 2017

InnovOil

page 5

A note from the Editor EVEN in a stable market, it is fair to say that new technologies for decommissioning can often be overlooked – or at least underappreciated. Although the industry is more aware of the scale of the challenge now than it has been in the past, it remains cautious about the adoption of new techniques. This is perhaps even more true of the most important disciplines within the decom remit – plugging and abandonment (P&A) especially.

But as ever, this hesitance only goes to show the importance of investment and investigation into new and disruptive approaches to old problems. In the UKCS, operators are expected to spend almost GBP18 billion on decom by 2025, according to Oil & Gas UK, and around GBP10 billion in Norwegian waters – around GBP2 billion and GBP1 billion per year respectively. Any technologies that help to reduce that spend could have a tremendous effect on bottom lines.

Analysis from IHS Markit also suggests that Europe alone will absorb approximately 50% of global decommissioning spend in the next 5 years, presenting numerous opportunities for beleaguered services firms. Indeed, as IHS senior manager Bjorn Hem remarked, “The providers of decommissioning services are very fragmented – there are no dominant players, so this makes it even more difficult for offshore E&P (exploration and production) companies and offshore service companies to accurately predict decommissioning costs and risks.”

This month then, we settle on a short look at technologists and innovators who are entering

the space. For some, that innovation is structural, creating integrated hubs where decommissioning can be handled by the right personnel at the right cost. Others are tackling the largest problems head-on; in particular we revisit Interwell’s thermite P&A programme currently undergoing trials in wells in Alberta.

Outside of our focus topic, progress continues as well.

This month I spoke with Professor Daniel Therriault of Polytechnique Montréal, whose team has been devising a 3D-printable sensor which could be used to detect leaks, and/or monitor the presence of liquids in real-time – of particular interest to the pipelines industry, he hopes.

Emissions monitoring from shale wells is being addressed by Statoil in an innovative new fashion. It is trialling a new solar-powered, laser-based monitoring system developed by start-up Quanta3 which could replace laborious, expensive and inaccurate on-site inspections.

We also speak with MOTIVE Drilling about its proprietary Directional Drilling Bit Guidance System – an automated decision-making programme helping to make directional drilling as targeted and efficient as possible. Making computational calculations at rates far faster than any human, the system uses existing and projected data to drill wells faster and more accurately.

All this, as well as subsea lighting, new in-line gas drying technology, high-pressure valves and much more.

We are pleased to present the March issue of InnovOil.

Andrew Dykes Editor

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InnovOil

A new dimension in fluid detection

March 2017

Researchers at Polytechnique Montréal have devised a conductive, 3D-printable composite which can be used to detect and characterise liquids in real time

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Systems (CREPEC), the Canada Research T SEEMS that there have been few Chairs, the Natural Sciences and Engineering scientific advances proposed of late for which the solution has not been “carbon Research Council of Canada (NSERC), nanotubes.” As with wonder-material Mitacs and the Canada Foundation for graphene, the ubiquitous allotrope of carbon Innovation (CFI). InnovOil spoke with lead has a near-endless list of applications, in author Professor Daniel Therriault about his particular in reinforcing the strength of new involvement in the project, and where future and existing materials, or endowing them refinements of the technique could lead. with additional properties.

It is reassuring, then, that a new paper Fully comp from a team at Polytechnique Montréal has The benefits of composite materials have broken new ground with just such a process. been extolled for years, and although the oil More topical still, the researchers can enhance industry has been comparatively slow in its the advantages of nanotubes uptake, they are beginning to using another revolutionary gain traction. technique – 3D printing – to Professor Therriault has devise a polymer composite been in the composite field for with enough electrical years, working mostly in the conductivity to enable its use developing applications for the in real-time sensing and liquids aerospace industry – where detection. lightweight, strong and durable The outcome of the materials are of particular group’s most recent paper is importance and interest. “In essentially a porous cloth made investigating those composites, of 3D-printed, nanotubeI looked at their properties enhanced filament. When like thermal conductivity, exposed to a liquid, this and then I looked at electrical material will swell, altering “We believe that conductivity,” he explained, its conductivity. The extent of from his office in Montreal. with the right alteration can then be used to “We discovered that there was material and determine both the presence a very big gain in electrical and type of liquid in contact the appropriate conductivity by adding those with the material. The team calibration we fillers in the plastics. We tried to hopes that the innovation could push the boundaries and make could tailor the them as conductive as possible find significant applications in the aerospace, hydrocarbons sensors to detect so we developed a lot of and manufacturing industries. specific liquids” expertise on how to mix those The paper – “3D Printing particles in the plastic.” of Highly Conductive With a sound understanding Daniel Therriault, professor at the Nanocomposites for the of nanotube dispersal, and Mechanical Engineering the extent to which properties Functional Optimization Department of of Liquid Sensors” – was could be conferred to the Polytechnique Montréal polymers, Therriault and published in the journal SMALL in September 2016, the group set about devising and backed by the Research Centre for a method for constructing them into High-Performance Polymer and Composite something useful.

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The process begins a thermoplastic, which remains solid at room temperature.

This is dissolved in a solvent, and placed in a container with solid particles – in this case carbon nanotubes – supplied as a fine black powder. These are mixed together in the lab by machine in accordance with a specific “recipe” the team has developed – and patented – which ensures the nanotubes are optimally dispersed for the application.

By adjusting the viscosity of the liquid, this process can produce a 3D-printable ink which can be loaded into the print head of a 3D printer. “The special thing here is that our ink solidifies very rapidly,” Therriault added.

“When pushed through the high-precision nozzle, the solvent evaporates very rapidly and the ink becomes solid in a matter of seconds. It comes out as a wire or a filament and solidifies, and can be glued to a surface or onto other filaments, allowing them to achieve 3D geometries.”

By stacking up these layers, the system can be used to design 3D architectures which are optimised for sensing liquids. By connecting

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The porous nature of the thermoplastic allows for the addition of carbon nanotubes, making the material conductive

the material to an electrical connection and equipment for measuring resistance, liquid can be detected and characterised by immersion or simply by contact.

The material’s conductivity is approaching that of some metals, Therriault said. The paper describes the system achieving 2,0003,000 siemens per metre, “highly conductive for a polymer, but still several orders of magnitude away from the most conductive metal,” he explained. Nevertheless, it is still enough to characterise a number of liquids, and conductivity has reportedly been improved since the original publication.

Fluid model With the concept proven, more work has to be done on liquid characterisation. So far, the sensors have been used to identify liquids ready to hand in a laboratory – acetone, isopropanol and a few more – which have produced clear, but by no means extensive results. “Right now we’re focusing on just a few kinds of liquids, but we’ve seen that depending on the liquid, the response

changes. We believe that with the right material and the appropriate calibration we could tailor the sensors to detect specific liquids. We think it’s possible and it’s something we’d like to investigate further.”

However, the sensitivity reported in the initial results points to its suitability in applications where any ingress of liquid would be detrimental. Sensors could be calibrated to pick up minute amounts of fluid, sounding alarms before any damage is done to infrastructure or equipment.

The team envisions a few different commercial scenarios for the technology.

Therriault is already exploring the possibility of supplying the polymer itself as a conductive paste for microelectronics and other industries. Beyond that, the team has proposed a portable 3D printer concept, which could be used on live worksites and would allow users to 3D print the material directly where it is required. Monitoring points could then be custom-made to fit desired dimensions and locations.

Another scenario would be to integrate NEWSBASE

the sensor in a factory assembly. Customers could specify the size and shape of the sensor depending on the liquid in question, and the equipment could then be shipped, allowing customers to install as required.

In particular, both would be of use to the pipeline industry. “For the oil industry, detecting leakage is a big topic,” Therriault noted. A composite – calibrated according to the liquid being transported – could be laid down at the flanged connection points in pipelines. In the event of a leak, and liquid touching the sensors, operators could be given very precise, instant information on its location.

For now, the group is looking to improve the detecting properties of the ink. For that, Therriault said, industry input will be crucial in guiding how they develop new applications: “We’re interested in discussing with partners to understand the needs of industry and adapt what we’ve done. If we know the needs of partners they can guide the effort: for example, do we need to be more sensitive, do we need larger sensors, what porosity is required for that application? That would guide research in the future.”

With major US and Canadian projects such as Keystone XL now back on the political table, such sensor technology may be put to good use sooner rather than later. n Contact: Professor Daniel Therriault Tel: +1-514-340-4711 ext. 4419 Email: daniel.therriault@polymtl.ca Web: www.polymtl.ca/lm2

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A Motive for better drilling decisions

InnovOil

March 2017

Motive™ Drilling Technologies explains how its automated Directional Drilling Bit Guidance System can help make better decisions and improve performance

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NE of the most significant problems identified by oil and gas operators in unconventional plays is the inability to follow a prescribed well path consistently, and to hit and stay within the targets identified by geologists, geophysicists, and engineers. One key reason is that directional drilling technology lags behind other technical advances that have driven the tremendous growth in horizontal drilling.

To address this problem, Motive™ Drilling Technologies developed a Directional Drilling Bit Guidance System automating decisionmaking at the rig. Automated decisionmaking has been used for making medical decisions, for automatically piloting cars and planes, for manufacturing, shipping, missile guidance, and much more. Over the past five years, Motive has applied automated decisionmaking protocols to the development of its bit-guidance system, and subsequently to the drilling of over 2 million feet (600 km) of horizontal and extended reach wells for over a dozen oil and gas companies across North America.

Use of the system, the company says, has resulted in wells drilled with more consistency, in less time, with more accuracy, with more production potential, and in some cases, with fewer personnel.

“Drilling rates today are so fast that even

the best directional drillers simply do not have the time to perform all the necessary calculations required to make the absolute best directional drilling decisions. As a result, the performance of directional drillers is often quite variable, costing the industry billions of dollars each year due to slower drilling speed, increased tortuosity, and lost

NEWSBASE

production potential,” explained Motive’s VP for marketing and business development, Bill Chmela.

Intuition vs. Computation While drilling horizontal wells, directional drilling experts must make quick decisions determining when to rotate the entire drill string, and when to adjust the direction of the drill string by sliding. These decisions are based upon numerous inputs including bitwalk tendencies, motor yields, anti-collision guidelines, dogleg severity, and future production consequences related to deviation from the target path.

In real-time, the directional driller continuously analyses data including gamma ray logs, hook load, surface torque, pump pressures, flow rates, trajectory measurements, distance to nearby wells, and much more.

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With the Guidance System handling all of the heavy lifting, the expertise of the best directional drillers can be scaled across multiple rigs

Good directional drillers rely upon expertise developed over many years.

This results in an environment where most directional drilling decisions are made quickly, based on the individual’s experience and an acquired intuition. The best directional drillers also know when they must move beyond intuition and use more geometrical computations to make good decisions. However, this belief in intuition can often override practical decision-making in situations where computational analysis may offer better results. This unwillingness to adapt behaviour contributes to the variation in performance often seen while drilling horizontal wells.

The Bit Guidance System developed by Motive™ Drilling Technologies uses a highperformance computer to provide a more data-driven, automated decision-making process, delivering the necessary improvement

in directional drilling performance. As a foundation for better decisions, the system automatically performs standard directional drilling calculations previously done by the directional driller, but does so continuously and faster than a human can do.

In addition, the system provides a vast amount of additional analysis, automatically offering the driller step-by-step slide/rotate guidance based on both dynamic analysis and parameters set by the operator. This guidance is communicated to the driller with an intuitive simple display located on the rig floor. The machine can run calculations on millions of possibilities and permutations that a human cannot do, thereby making the best decision to maximise value. The system projects into the future – including calculations such as total drilling time, losttime risk, and future production potential based on well proximity to the initial target NEWSBASE

– a degree of analysis rarely considered by human directional drillers.

Additionally, tortuosity of the well bore is factored into each directional decision to reduce torque and drag, enable higher drilling rates, extend the maximum reach of laterals and reduce sumps in the lateral that can affect production efficiency.

Drilling parameters can also be set according to a particular region, meaning the operator can ensure that the decisions being made on-site are in line with the objectives of the asset manager – rather than at the discretion of each individual driller.

The system will continuously adjust the guidance based on driller’s actions and provides real-time feedback to enhance the driller’s performance. In turn, this automation consistently improves the driller’s ability to maximise value to the operator, independent of their level of experience.

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to perform other tasks. The system provides this transparency through 2D and 3D visualisation interfaces, available through both a browser and iPad app.

By providing complete directional drilling transparency to the entire team regardless of location, the system returns operational control back to the operator and provides better utilization of the best directional drillers. Just as decision-automation is helping doctors provide better treatments and cars to be safer, Motive’s technology has been proven to improve the performance and consistency of drilling horizontal wells in today’s tough environment. n Contact: Bill Chmela, VP Marketing and Business Development Tel: (+1) 469 729 6470 Email: info@motivedrilling.com Web: www.motivedrilling.com

Operational Efficiency Slower red wells NOT using Decision Automation

Measured depth

Total transparency The graph of Operational Efficiency below shows the results of a case study designed to test the system for a client drilling in the Eagle Ford basin. Two identical rigs were mobilised in the same area and drilled four wells each. One rig used Motive’s decisionautomation tool, while the other rig drilled without. All other parameters were the same including bit, BHA, and well paths. The rig using automation drilled 25% faster and with twice the accuracy.

The system does not completely automate every single task of the directional driller, but the computational power of the system combined with the experience and intuition of the directional driller provides oil and gas operators with the best opportunity for consistent performance at higher levels while mitigating risk.

The possibilities offered by these technologies have profound implications for how future drilling operations may work. With the introduction of decision automation, new roles may need to be defined, and an emphasis on change management and new technology acceptance within industry is critical.

Yet, the rewards are great. In addition to the performance gains on an individual well basis, the expertise of the best directional drillers can now be scaled. With the system performing all the heavy computational lifting, a single expert directional driller can now guide multiple wells at one time, all from a single location.

With this distributed system, the entire decision making team (on the rig and in the office) is continuously informed of past, current, and dynamically-planned future directional drilling activities using automated reporting, email, and text notifications, freeing the directional driller

Blue wells using Decision Automation Rig time

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March 2017

All computations and advisory guidance are provided in an intuitive display to guide the driller in real-time

Testimonial “Truthfully there was doubt on the part of some of our technical team during our early relationship with the Motive team. Over a short time though that scepticism gave way to confidence that the platform truly does improve the directional drilling process by navigating the optimal path and is therefore an important contributor to our improved performance. The graphical drillers’ panel interface conveys the state of operations and directional control in a way that speaks clearly to our team of drilling engineers, rig-site personnel and geoscientists to improve confidence that lateral sections are being steered within planned windows. We are pleased to have partnered with the Motive team in the early development of the product and have now adopted it as an integral part of our DD kit.”

Ken Topolinsky, Senior Vice President, Engineering & Applied Technology Hunt Oil Company

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On the radar

What caught our attention outside the world of oil and gas this month

Catch and release MIT researchers have designed and built transparent, gel-based robots which can be moved by pumping liquids around their structure. The technology could lead to near-invisible robots for use in subsea applications.

The robots are made of hydrogel, a rubber-like material composed largely of water. The robots are comprised of a number of linked, hollow hydrogel structures connected via tubes. When water is pumped around these structures via a syringe pump, the hollow spaces inflate, causing the muscle-like structures to stretch and contract.

This method allows the robots to be propelled, or to clasp objects. They have been influenced by the leptocephali, or “glass eels”, found in the natural world. They have even been used to catch fish using a “handlike robotic gripper” in which water could be pumped in and out of its “fingers”.

In experiments using several hydrogel robot designs, the team found the structures were able to withstand repeated use of up to 1,000 cycles without rupturing or tearing.

The group, led by Xuanhe Zhao, associate professor of mechanical engineering and civil and environmental engineering at MIT, and graduate student Hyunwoo Yuk, is currently looking to adapt hydrogel robots for medical applications.

“Hydrogels are soft, wet, biocompatible, and can form more friendly interfaces with human organs,” Zhao says. “We are actively collaborating with medical groups to translate this system into soft manipulators such as hydrogel ‘hands,’ which could potentially apply more gentle manipulations to tissues and organs in surgical operations.” n Photo: Hyunwoo Yuk/ MIT Soft Active Materials Lab NEWSBASE

March 2017

Print sun A project by University of Toronto researchers has made strides towards developing printable perovskite solar cells.

Whereas most solar cells are made from slices of crystalline silicon, perovskite cells use a layer of individual crystals. This allows them to be mixed into a suitable liquid and “printed” onto a surface.

However, the key to generating power from such cells is a conductive electron-selective layer, or ESL, which carries electrons to the electrode to generate current.

Researcher Dr. Hairen Tan explained: “The most effective materials for making ESLs start as a powder and have to be baked at high temperatures, above 500°C. You can’t put that on top of a sheet of flexible plastic or on a fully fabricated silicon cell — it will just melt.”

Tan and his colleagues developed a new chemical reaction that enables them to grow an ESL made of nanoparticles in solution, directly on top of the electrode. These are coated with a thin layer of chlorine atoms, which helps bind them to the crystals.

While heat is still required, the process always stays below 150°C, much lower than the melting point of many plastics – and more energy-efficient in terms of mass production.

In a paper recently published in the journal Science, Tan and his colleagues reported the efficiency of solar cells made using the new method at 20.1%.

Moreover, while many perovskite cells can experience a drop-off in performance – sometimes after just a few hours – these cells retain more than 90% efficiency even after 500 hours of use.

In addition to new applications in printable forms, the advance could help squeeze more solar efficiency out of existing architectures.

“With our low-temperature process, we could coat our perovskite cells directly on top of silicon without damaging the underlying material,” Tan said. “If a hybrid perovskitesilicon cell can push the efficiency up to 30% or higher, it makes solar power a much better economic proposition.” n

InnovOil

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No-contact order The US Air Force Research Laboratory Materials and Manufacturing Directorate (AFRL/RX) has signed a co-operative R&D agreement with Creare for the development of non-contact inspection methods for aircraft components.

“The Air Force currently requires 100% component inspection as aircraft parts are manufactured. Non-contact methods will allow inspectors to make the necessary measurements in less than half the time of previous methods and with greater accuracy,” commented AFRL/RX materials engineer Craig Neslen, who is managing the effort.

The equipment was originally developed by Creare as part of an Air Force Small Business Innovation Research effort to develop a non-contact inspection method that measures the distance between a drilled hole and the

edge of a part. That agreement ended with significant elements of the project (hardware and software) being transitioned to a non-contact hole measurement requirement for Air Force aircraft.

The new CRADA agreement allows the New Hampshire-based company to maintain physical ownership temporarily of the equipment and continue its research.

A CRADA is one type of technology transfer agreement that provides quick access to extensive government-funded research and development resources that can be leveraged to create powerful results while also providing intellectual property protection. CRADAs are facilitated by the Air Force Technology Transfer Program and its affiliated Office of Research and Technology Applications. An ORTA is embedded at many Air Force research locations. n

Studying the blade Siemens has concluded its first full-load engine trials with gas turbine blades produced entirely via additive manufacturing (3D printing) technology.

Multiple blades were built and installed and have been tested at 13,000rpm and temperatures beyond 1,250°C. The process also allowed for “completely revised and improved internal cooling geometry.”

The blades were installed in a Siemens SGT-400 industrial gas turbine with a capacity of 13 megawatts (MW). The turbine blades are made out of a powder of polycrystalline nickel superalloy, allowing them to endure high pressure, hot temperatures and the rotational forces of the turbine’s high speed operation.

At full load each of these turbine blades is travelling at over 1,600 km/h, carrying 11 tons or equivalent to a fully loaded London bus, is surrounded by gas at 1,250 °C and cooled by air at over 400°C. Blades were built at Materials Solutions, a newly acquired company in Worcester, UK, which specialises in high-performance parts for high-temperature applications in turbomachinery. Tests were conducted at the Siemens testing facility in the industrial gas turbine factory in Lincoln, UK. “This is a breakthrough success for the

use of Additive Manufacturing in the power generation field, which is one of the most challenging applications for this technology,” said Willi Meixner, CEO of the Siemens Power and Gas Division. “Additive Manufacturing is one of our main pillars in our digitalisation strategy.”

“This exciting technology is changing the way we manufacture by reducing the lead time NEWSBASE

for prototype development up to 90%,” said Meixner. “We can accelerate the development of new gas turbine designs with an increased efficiency and availability and can bring these advancements faster to our customers. This new flexibility in manufacturing also allows Siemens to develop closer to the customer’s requirements and also to provide spare parts on demand.” n

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DECOMMISSIONING

March 2017

SPECIAL SUPPLEMENT Pages 15-22

PART OF THE SERVICE? How industry consolidation will affect decommissioning Page 16

COST-CONSCIOUS Oil & Gas UK provides Decom Insight Page 18

BACK TO THE SOURCE Sea-Source unveils its plans for expansion at Kilkeel Page 20

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InnovOil

March 2017

DECOMMISSIONING

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HE decommissioning market is developing against a background of rapid change in the oil and gas offshore services and equipment sector (OFS).

After seeing revenue shrink by 30% per year for the last two years, a string of recent mergers means the sector is now consolidating. This is likely to produce ever more dominant big service players, although so far it has been mostly smaller and more locally based operations that have done most of the decommissioning. But as the end-of-life sector matures and grows the big companies are learning and developing techniques, making them more able to compete for work with both smaller and inhouse operations.

Currently the providers of decommissioning services are very fragmented. This means there are no dominant players, which makes it more difficult for offshore E&P companies accurately to predict decommissioning costs and risks.

However, the anticipated expansion of

decommissioning represents an opportunity for the bigger OFS firms to help rebuild their businesses after two years of layoffs and cost-cutting. This trend is likely to continue, despite the recent modest gains in the oil price.

Total decommissioning costs, on the other hand, are mounting – in the North Sea alone they are forecast to exceed US$58 billion by 2050 – representing a major potential market for the big OFS players.

M&A gets going The service market contraction has led to sharp falls in service revenues and margins, followed by a series of mergers and the prospect of more. In September GE proposed merging its oil and gas business with Baker Hughes, aimed at creating a large, listed player capable of competing with rivals such as Schlumberger.

If approved, the deal will go ahead later this year, with GE owning 62.5% of the new company, which will have combined estimated revenue of US$32 billion. The deal came soon after Technip’s US$14 billion

merger with FMC in May, which followed the acquisition of Cameron by Schlumberger.

Despite these big deals, consolidation activity in the service and equipment sector has actually been relatively low so far during the oil price slump. In 2015 total OFS M&A deals were valued at US$26 billion, compared with US$33 billion in 2014, while the total for the first half of 2016 was just US$2 billion excluding the Technip-FMC deal. A pick-up is anticipated as oil prices recover, but it may take time to play out.

All three of the big offshore service deals focus on integrating service and equipment offerings. This may alter their approach to decommissioning work, making them better positioned to build more dominant market positions. For example, Schlumberger’s life-of-field services will be integrated with Cameron’s portfolio of drilling, completion and production equipment in a joint venture that includes Helix, whose vessels provide well intervention and additional support services including abandonment, which is usually performed using drilling rigs.

This newly merged entity could tap

The consolidation of the offshore services industry could help to shape the future of decommissioning around the world

Decom together NEWSBASE

March 2017

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DECOMMISSIONING

into a substantial part of the subsea well decommissioning market, which – in the North Sea alone – is forecast to reach US$10.5 billion by 2050 – or around 18% of the total. Altogether, well plugging and abandonment costs are expected to represent 44% of total decommissioning costs in the North Sea up until 2050 – by far the biggest market segment. However, prior to the acquisition, the Schlumberger Integrated Well Abandonment (IWA) service already provided fully integrated services and products for well abandonment, so it is unclear if the merger will have an impact on its stand-alone offering.

The GE/Baker Hughes combination creates a smaller-scale portfolio similar to the Schlumberger/Cameron tie-up. It may be relatively easy for both to expand integrated life-of-field service and equipment offerings to include decommissioning provision, with operators keen to offload risk, if such service providers are prepared to take it on, provided safeguards are in place.

The Technip/FMC combination, on the other hand, is more focused on integrated

front-end engineering, equipment, and installation services for operators, in the early stage of the project lifecycle, and so is less expected to target more involvement in latelife or decommissioning work.

Wider implications This consolidation and changing company strategies could have far-reaching implications for smaller service companies and decommissioning specialists, as well as operator/supplier relationships. Some independent service and equipment specialists may be forced to adapt in submarkets like decommissioning. Engineering companies may be inclined to align with Schlumberger/Cameron, and drilling service companies with Technip/FMC, while others may be pushed more towards later life project spend and decommissioning.

Nevertheless, the decommissioning market may not see significant change in the supplier landscape unless these new merged entities can come up with integrated and innovative solutions to decommissioning that cut costs or, alternatively, improve

NEWSBASE

recovery. Only then will they be able to expand market share.

In Asia a number of fast-growing medium-sized service companies, including Sinopec Oilfield Services, Keppel and others, will also add to the competitive environment for the big merged service companies. And in the North Sea, the OGA may play a key role in supporting the emergence of a new local decommissioning industry. The costconscious mature offshore segment serviced by upstream independents has traditionally relied on smaller/local OFSE companies, and the experience of decommissioning the Brent platform gave British companies an early opportunity to develop specialist skills and expertise in the safe removal and recycling of oil platforms and pipelines.

As decommissioning volumes expand, the shape of the supporting industry will take shape. Whether this remains dominated by low-cost local support services or becomes more influenced by larger international operations will be affected by the degree of OFS sector consolidation, technology, cost and local regulation. n

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March 2017

DECOMMISSIONING

Old assets, new opportunities Oil & Gas UK’s latest Decommissioning Insight Report identifies key areas where cost reductions could be made through new technologies

P

Tonnes to be Removed

AINTING a comprehensive picture Plugging the gap of the decommissioning market is As is perhaps well recognised, P&A is tricky. Certainly, there has been no the area where cheaper or more efficient explosion of activity in recent years, methods could have the greatest impact. especially in light of low oil prices. But while Between the UK and Norway, P&A accounts some operators have opted for life extension for somewhere between 47-56% of the total programmes or indefinitely delayed expenditure. Average costs per well have decisions, the sector is growing year on year been estimated at GBP2 million-GBP4 suggesting the topic is no longer a case of million, depending on the location and well 18:down Uncontracted Topside Removal Forecast in the Central and Northern North Sea “kicking Figure the can the road. ” design. and West of Shetland 2016 to 2025 In its Decommissioning Insight 2016 According to OGUK, the exploration and 80,000 report, Oil & Gas UK (OGUK) points appraisal well P&A unit costs over the next Increased Uncertainty in Forecasts 70,000 was spent on out that GBP1.1 billion ten years are forecast to fall by 35% in the decommissioning in60,000 the UK and GBP1 southern North Sea and Irish Sea to GBP5.6 billion in Norway – up from the GBP800 million per well. In the central North Sea, 50,000 million and GBP770 million respectively in Northern North Sea and West of Shetland 40,000 2014. is forecast to be around 20% cheaper at Nevertheless, the30,000 size and scope of the GBP6.2 million compared with forecasts issue is growing too. Over 100 platforms made last year.

20,000 require complete or partial removal and The type of rig needed to perform these 10,000 1,800 wells are in line to be plugged and operations will vary on well type and abandoned (P&A), as well as 7,500 km of water depth, but rigless P&A, as InnovOil 0 2016 2017 2018 2019 2020 2022 2023 2024 2025 pipeline in UK and Norwegian waters.

That has2021 reported on previously, could reduce is a sizable opportunity for technology firms. costs dramatically. The authors note that: Source: Oil & Gas UK

Topside Removal

Weight (Tonnes) 2016 to 2025

Number 2016 to 2025

Total

449,260

342 topside modules on 28 platforms

Contracted activity

119,880

5 platforms

Uncontracted activity

329,380

23 platforms

Figure 19: Uncontracted Substructure Removal Forecast in the Central and Northern North Sea and West of Shetland 2016 to 2025 50,000

Increased Uncertainty in Forecasts

45,000

Tonnes to be Removed

40,000 35,000 30,000

25,000 20,000 15,000 10,000 5,000

0 2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Source: Oil & Gas UK

Substructure Removal

Weight (Tonnes) 2016 to 2025

N E WNumber S B A S2016 E to 2025

“Platform wells are typically plugged and abandoned in phases. The first phase can be rig-less and uses lower cost methods such as wireline, coil tubing, or a hydraulic workover unit. This is followed by the second and third phases that are more likely to require a rig.”

Indeed, they specifically call attention to Interwell’s thermite P&A technique 1 page 22) which could reduce costs by (see up to half. Other solutions, useful in this first phase in particular in avoiding the requirement for section milling and case 2 pulling – such as using hot plasma to melt through concrete, casing and tubing – have also been trialled, although so far industry 3 uptake has been slower than might be preferred.

OGUK and its sibling organisations will be supporting development of some of 4 the most promising technologies. OGUK Communications Adviser Lucy Gordon told InnovOil that: “Well P&A is one of the key 5 areas that will be focused on by the new Oil and Gas Technology Centre (OGTC) when it establishes a centre of excellence. The work will be aimed at more core research and 6 development, with research, test facilities, simulation, big data and automation at its heart.”

7

Cut-up method Besides wells themselves, topside and substructures must also be moved. Large 8 structures require large heavy-lift vessels – the demand for which is likely to increase in the next decade. If costs can be controlled, 9 and innovative single-lift vessels may be new preferable, lifting the entire topside to shore in one piece rather than cutting structures into pieces and requiring multiple trips via barge, also known as “reverse installation”.

That is likely to require a larger or more adaptable fleet of vessels, and therein lies the opportunity for vessel contractors, shipyards

March 2017

InnovOil

page 19

DECOMMISSIONING

and designers. Moreover, because North Sea and Norwegian structures tend to be larger and heavier, suitable vessels could be replicated or adapted for use on smaller Gulf of Mexico platforms too.

Indeed, new vessels such as the Pioneering Spirit – capable of lifting 25,000 tonnes – are now setting the bar for singlelift topside removal. The Spirit is chartered for work on Royal Dutch Shell’s Brent field this year, and may begin to move the Delta 24,000-tonne Delta platform as soon as May. But more such vessels will be required if this

method is to prove effective.

New cutting technologies will also be needed, if topsides and substructures are to be broken up effectively – especially when work may take place over several deployments, and months apart. Indeed, according to OGUK, 23 platforms are scheduled to be removed before 2025 but do not yet have contracts. Provided their decommissioning goes ahead, a flurry of activity may well pick up in the next few years.

As OGUK’s upstream policy director

NEWSBASE

Mike Tholen remarked in a statement accompanying the report: “The UK’s supply chain will need to focus on developing a high-quality, cost-efficient and competitive decommissioning capacity to make the most of the opportunity and provide a range of goods and services that can not only be deployed in the UK but also exported overseas.” n For more information, you can download the Oil & Gas UK Decommissioning Insight Report here.

page 20

InnovOil

March 2017

DECOMMISSIONING

Source code: Sea-Source and the future of offshore services Kilkeel-based marine services firm Sea-Source is aiming to reposition the offshore industry as a reinvigorated business with a diverse and sustainable future

L

OW oil prices, coupled with a wider trend towards renewable energy and subsea hydrocarbons development, are driving massive structural change in the offshore industry. Recognising the pressures of the market, and new opportunities, many companies are looking to provide more agile, diverse services capable of meeting the cost and efficiencies demanded.

One such group is Sea-Source Offshore, part of the Anglo-North Irish Fish Producers Organisation (ANIFPO), a collaborative network of Kilkeel fishermen and onshore marine-related business owners. It oversees a range of offshore activity, including the supply of guard vessels and expert support services for offshore surveys for energy and pipe-laying developments, fishing, storage, processing, packaging, marketing and distribution.

Established in 1984, the members’ organisation was originally set up to manage the quotas of a fishing fleet of more than 50 vessels and to maximise the value of the landed catch at Ardglass, Annalong, Kilkeel and Portavogie. By 2007 it had grown to include a fish sales division, quickly adding a processing plant, a move which has allowed its members to catch, sell and process their own fish or shellfish under the Sea-Source name, which was formally adopted in 2015.

Sea-Source Offshore is a one-stop-shop provider of marine services throughout the northwestern European seaboard.

With the renewables and offshore energy industries developing new sites in the Irish Sea and beyond, the group is extending its reach beyond fishing to offshore marine developments. The 12-boat fleet is fully

compliant with regulations for guarding and survey work and is in high demand thanks to the expertise of its crews and shore-based logistical personnel.

International gateway A new focus on offshore services, such as the development of cable-laying projects, interconnectors for gas and electricity and seabed surveys for tidal and wind projects, is generating potential new business opportunities.

A successful fishing industry has allowed the group access to numerous international markets and suppliers of benefit to the energy industry. “As one of the top three landing locations for langoustines in the UK and Ireland, Kilkeel has developed international export markets and has NEWSBASE

diversified into other areas of the marine economy, including commercial offshore developments,” commented Sea-Source chief executive Alan McCulla.

Sea-Source says it has scored early successes in its pursuit of contracts with developers. It has already undertaken a number of contracts, including the deployment of 11 vessels to lay a communication cable between Wales and Ireland and work for a wind project developed by Danish state-backed utility DONG Energy.

Davey Hill, who leads the Sea-Source Offshore Services division, says that the firm has now secured a new contract with DONG Energy for work to be undertaken in the North Sea. “This is a clear sign that we can operate well beyond our immediate patch

March 2017

InnovOil

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DECOMMISSIONING Left to right: Davey Hill, Manager, Sea-Source Offshore Services and Alan McCulla OBE, Chief Executive.

in its infancy and progress is expected to be slow before the market grows significantly.

Pressure to keep decommissioning prices down comes largely from Third World nations where vessels and rigs can be dismantled and recycled at a fraction of the cost in the West.

However, Davey says that recent developments and changes to environmental regulations which govern ship decommissioning mean there is scope for business. “We have partnered up with Norfolk Marine based in Lowestoft and this gives us the springboard for the North Sea. We see decommissioning as an important part of Sea-Sources’ expansion into the offshore industries.”

in the Irish Sea,” he said. “If we can operate successfully for clients in the North Sea we can expand beyond that again.”

To assure its success, a bigger base in Kilkeel will be required. Nestling at the foot of the majestic Mourne Mountains in County Down, Kilkeel Harbour is picturesque but small. The current port facilities are suited to a fishing industry which stopped expanding in the 70s. “We need to grow,” says Davey. “We urgently need to build a bigger port.”

“Kilkeel is currently the subject of a study

by Northern Ireland’s Strategic Investment Board to assess the need for a harbour extension. While the offshore services division can be successfully operated using the boats we have, the need for shore-based support systems, engineering expertise, ship

repair and technologically advanced centres of excellence which allow us to function and expand is now becoming urgent,” Davey explained.

“If Kilkeel, and consequently Sea-Source, is to remain competitive, this harbour expansion plan is the number one priority,” he added.

“There now exists a fleet of specialist vessels and crews which can undertake all sorts of work on behalf of offshore developers, particularly those in cable-laying and renewable energy. The risk is that other ports in the Irish Sea Basin could benefit from our success if we don’t expand,” noted Alan.

Decommissioning opportunities Sea-Source is also exploring the potential of decommissioning work. This sector is still NEWSBASE

New skills “We’ve put a lot of work in behind the scenes, upskilling both the boats and crew, making sure all safety measures are in place and that we’re ready to work with the energy companies,” Davey noted. “But it was all worth it. We can now harvest a living not just from fishing but from diversifying as well. We’ve even trained people up to become marine mammal observers, an initiative of our own.”

“Customer service is as critical to us as is health and safety,” he continued. “We operate everywhere in northwestern European waters and work with some of the most innovative renewable energy developers, gas and oil explorations and cable-laying projects.”

With an innovative overhaul of its marine industry, including the input of the supply chain such as marine mechanics, fish processing, a skills and training centre and other related activities, Alan McCulla reckons that an extended harbour could create 1,000 jobs for the region.

Sea Source Offshore is a member of the International Marine Contractors Association (IMCA), ensuring that it is aware of the latest offshore safety standards.

All vessels are checked over by an approved IMCA auditor to ensure safety standards are improved and quality assured.n Contact: Davey Hill

Tel: +44 (0)2841 762855 Email: info@sea-source.com Web: http://sea-source.com

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InnovOil

March 2017

DECOMMISSIONING

Positive reactions to exothermic P&A Interwell’s thermite P&A tool has undergone trials in Canada, where results so far have been highly promising

E

VEN in difficult times, good ideas shine through. Back in June 2016, InnovOil explored a radical new method proposed by Interwell for the plugging and abandonment (P&A) of decommissioned wells. The company was experimenting with thermite as a means of melting the well tubing, casing and the surrounding rock formation, bonding the media together in a new rock plug and sealing the well.

If it was successful, it would represent a truly new method of approaching one of the industry’s thorniest – and costliest – problems.

In the nine months or so since, the company has been conducted a number of trials, including an initial two-well pilot in Canada, with a view to fully qualifying the technology.

To reiterate the theory behind the technique: when ignited, thermite – a compound of metal powder fuel and metal oxide (most commonly iron oxide) – burns at around 2,500°C, enough to melt through tubing, casing and cement. It is also hot enough to melt the surrounding rock, bonding the materials together and – in theory – forming an ideal barrier with which to plug the well.

This is deployed via a specially-engineered tool. An anchor is set, heat protective material is placed above and the tool is lowered and activated. P&A Engineer Henriette Horjen explained that: “This will melt all the well elements and establish a cross-sectional, formation-to-formation barrier. The barrier can be divided into three components – in the middle a melt zone which will solidify into a synthetic igneous rock. Moving out there will be a thermal contact – a bonding between the synthetic igneous rock and the host rock caused by crystallisation. Outside of this we will have a thermal alteration or metamorphic zone in the host rock.”

In addition, because the reaction produces its own source of oxygen, no external supply is needed and almost no other gases are produced, making it a sound choice for use downhole.

No workover rig is required, meaning P&A operations could be performed quicker and at a lower cost than conventional techniques.

Moreover, the hope is that the new bonded

The thermite melts the casing and surrounding rock, ensuring the plug bonds well rock barrier could better prevent potential oil and gas leaks more securely than the current methods of sealing and/or cementing abandoned wells.

A very good year Having been investigated since 2012, last year proved to be a breakthrough for the technology as a viable and commercial option.

May 2016 saw the Interwell team undertake a full-scale test in a dummy well, with a fullsize tool deployed above ground for trial and inspection.

P&A Engineer Kai Rune Finnes commented that: “This test has been very good experience... We have verified that the tool can be assembled, handled and installed quite easily. We also had an ignition where we had an immediate activation and exothermic reaction after we pushed the button so we can really build confidence to go on further.”

The next stage was to deploy the technology in a real-world setting. Gasfocused operator Centrica stepped forward and, finding the technology “very intriguing,” sought approval for a two-well pilot with Albertan regulators.

Begun in August 2016, this would form perhaps the most important verification of the barrier. According to Interwell P&A Operations Manager Lars Albertsen, the two wells offered 7-inch casing at the correct depth and pressure – optimum specifications in terms of the team’s base-case scenarios – NEWSBASE

and would allow them to place the well in underbalance for the 6-month test period.

Testing included the running of cement evaluation tools and logs and casing inspection logs, both before and after deployment, as well as positive and negative pressure tests.

Deployment and initial tests proved successful, but further results from the sixmonth trial have not yet been made public.

Further tests are ongoing, with sources indicating to InnovOil that results are expected in early summer.

However, based on the initial months of trials, the company is confident that the technology works in wellbore conditions, and that the properties of the barrier have been proved. Previous reports indicated that the company would look to commercialise the P&A tool fully for onshore and offshore during 2017, and for subsea operations in 2018, although we are unsure if this is still the company’s intention.

To do so, however, will require more operators with more well candidates in order to bolster the verification programme.

Operators looking to tackle the problem of P&A would do well to consider a technology which could yet become a new standard. n Contact: Terje Hauan, Commercial Manager, P&A Tel: +47 41 44 77 22 Email: teha@interwell.com Web: www.interwell.com

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InnovOil

March 2017

Laser tracking for fugitive emissions

Statoil is deploying new monitoring technology for methane emissions at US shale sites. Ros Davidson speaks with researchers to find out more

C

ARBON dioxide might be the most high-profile greenhouse gas (GHG) that politicians and industry are seeking to address, but methane is certainly the more potent. Roughly 30 times more effective at trapping heat in the atmosphere, it also has a tendency to combine and react with numerous other molecules in the air. So-called “fugitive” methane is therefore not just a localised issue for oil and gas operators, but a global one.

In Texas, Norwegian NOC Statoil is currently field-testing an innovative low-cost laser technology that continuously detects methane leaks. So far, it looks to be accurate and on track to be priced enough to be deployed.

The methane sensor – which is solar powered – could indeed conceivably become a standard part of a “smart” well pad. It works remotely, and sends data wirelessly and securely to a cloud-based system.

The sensor technology was developed rapidly, in just four years through the Methane Detectors Challenge (MDC), – a partnership between the US Environmental Defence Fund (EDF), oil and gas companies, US technology developers and other experts.

No alternative There is as yet no widely available method for the 24/7 detection of methane in at oil and gas sites, even though it is the main component of natural gas and is regulated. An estimated 25% of today’s climate warming is

driven by emissions of methane from multiple sources, including oil and gas development, according to EDF. There are economic reasons too – from a commercial perspective, any leaked methane is also a waste of resource and therefore lost cash.

In the US, methane is emitted across the oil and gas supply chain at an estimated rate of more than 9.8 million metric tonnes per year.

Globally, the oil and gas industry loses about US$30 billion of natural gas a year from leaks at dispersed sites (the loss in the US is around US$2 billion annually). At production sites, common locations for fugitive emissions are – according to the US Environmental Protection Agency – at the site of pneumatic devices, tank batteries and processing equipment.

Current testing methods include handheld infrared cameras – deployed perhaps twice yearly to a site by a field team often of two people, says Desikan Sundararajan, a senior researcher in Statoil’s shale oil and gas R&D team. It can take three to four hours to perform one test.

Hand-held ‘sniffers’ have to be held close to a leak. It is labour intensive, and the monitoring is not possible 24/7. “The leak may start the next day [after such a calendarbased model] and we won’t know for the next six months, EDF’s Aileen Nowlan, manager of the MDC, told InnovOil. Such testing is typically also qualitative, not quantitative, adds Statoil’s Andrea Carolina Machado Miguens, also with Statoil’s shale oil and gas R&D team. In areas such as oilsands, operators may literally place a ‘flux chamber’ NEWSBASE

or large hood over a tailings pond or above a mine to capture and measure emissions, including methane, but again the method is not perfect. Refineries too have their own methods, often using costly devices used inside equipment that is not suitable for field deployment.

Quanta innovation Statoil’s latest approach uses sensing technology by Colorado start-up Quanta3, a company founded specifically to participate in the MDC. The technology was initially tested at the Southwest Research Institute in San Antonio, where it performed well, said EDF’s Nowlan, and has now been deployed at a production well site in Karnes County, in the Eagle Ford formation in south Texas.

The sensor can measure concentration, flow rate and location with a 5-10% accuracy, Dr Sundararajan told InnovOil. According to Quanta3, the sensor can detect 0.5 cubic feet (0.001 cubic metres) per minute from a distance of 130 feet (40m), although Dr Sundararajan said that it could be placed even

InnovOil

March 2017

page 25

Engineers assembling the solar-powered monitoring equipment

farther away and still perform.

The ‘smoke detector’ technology is around 7-8 feet tall, and includes a 12” x 18” x 18” casing (305mm x 457mm x 457mm) that contains the laser, as well as a solar panel and an anemometer to measure the wind, which of course affects the flow of methane. With a minimal footprint, it can be placed within the perimeter of a wellsite without causing disruption or additional safety issues.

Sample air is drawn though a port in the casing and analysed. When the laser passes through the air sample, the methane absorbs energy at a specific point in the spectrum.

Thus a ‘signature’ can be obtained from a reflector.

The resulting data is recorded in real time, transmitted to the cloud and analysed on a weekly basis by Statoil and Quanta3 in Austin, Texas.

Weatherproof When the pilot study started, in midJanuary, the weather was quite rough, and the sensor remained accurate, the researchers said.

Prevailing winds are typically fairly stable, meaning the sensor can be easily placed where the plume of a leak might occur, aiding accurate measurement.

The current testing will help researchers establish an operational baseline for atmosphere and emissions – there is already background methane in the atmosphere, and ensuring the detector does not pick up false positives is important. A team is also conducting a site inspection, to gather more data and so that the overall accuracy of the sensor can be gauged. “It’s the first time we have had 24/7 data,” Dr Machado explained to InnovOil. On the more practical side, the device is also being tested for ruggedness, and to see how the algorithms and data analysis stand up. The pilot will continue until about midApril, after which more sensor units might be deployed elsewhere, with up to two in the Eagle Ford and perhaps two in the Bakken formation in North Dakota.

The cost challenge, under the MDC programme, is to find a sensor which is deployable for about US$1,000 per site per year. The sensor unit itself is ultimately expected to cost only US$5,000 per unit, once it has been commercialised. The NEWSBASE

current cost is “significantly higher” right now, says Dr Machado, but with scaling up she believes that this should come down.

Moreover, that cost may not be associated with extra spend. Nowlan reiterated that “lost methane equals lost money,” and EDF notes that according to studies, natural gas leaks can be reduced by at least 40% for an average cost of about one penny per thousand cubic feet of gas produced.

With proven results from monitoring trials, the team expects the technology to be useful at production, processing, transmission or gathering sites.

Statoil in particular is seeking to become the most carbon-efficient oil and gas producer. Regardless of one’s perception of that message, participation in schemes like the MDC is having an effect – the company’s methane emissions have decreased by about 10%, from 40.6 thousand tonnes in 2014 to 36.3 thousand tonnes in 2015, according to its 2015 Sustainability Report.

Other companies that have worked with the MDC include Royal Dutch Shell, Anadarko Petroleum, Noble Energy and Southwestern Energy, said Nowlan.

The team are also confident that recent moves by President Donald Trump’s administration to roll back environmental regulations, such as for methane emissions, would not affect the usefulness of the technology. Nowlan cautioned: “Nobody voted for dirty air or dirty water. There’s a difference between campaign rhetoric and governing.” n

page 26

InnovOil

March 2017

Petrobras, Halliburton join forces to target complex reservoirs

Brazilian NOC and US oil services firm to cooperate on technology for pre-salt development

B

RAZIL’S state-run oil company Petrobras has inked a technology cooperation agreement with US oilfield services provider Halliburton, as the two firms look to better development in complex reservoirs.

The collaboration will focus on technological solutions for deepwater pre-salt and mature fields, as well as other kinds of projects, Halliburton said in a press statement.

Brazil has some of the most extensive presalt deposits in the world. Pre-salt reserves, located on the Brazilian continental shelf, are estimated to contain more than 50 billion barrels of oil – four times more than estimated national oil reserves.

The new agreement is multi-year and aims to develop innovative solutions across the areas of geophysics, drilling and completions, reservoir characterisation, well testing, flow assurance and production, the US firm said.

The plan is to increase well productivity, lower the costs of constructing wells, and reduce the costs of long-term monitoring required for reservoirs.

“Collaboration is a Halliburton strategic mainstay that drives our engagement with customers to develop new technologies,” said Francisco Tarazona, vice president of Latin America. “This agreement will enable experts from both companies to share knowledge and accelerate the development of tailored solutions.”

The US firm has been collaborating with Petrobras on technology solutions since 2009.

In the first phase, the two companies worked on a total of 11 projects together, including pre-stack seismic attributes for carbonates, new algorithms for better estimation of fluid sampling contamination and a new cementing system for salt and CO2 environments. The latest agreement will kick off the second phase of collaboration, relying heavily on Halliburton’s Brazil Technology Centre in Rio de Janeiro.

The technology centre, which Halliburton says is the first of its kind in the Southern Hemisphere, is part of a larger global technology network. It works in tandem with other Halliburton technology centres located in the United States, Canada, the United Kingdom, Saudi Arabia, India, Belgium and Singapore.

In the second phase of cooperation, a governance committee will determine which specific projects will be targeted, a Halliburton spokesperson told InnovOil. The projects will be led by subject matter experts in Brazil and supported by global teams all over the world, he said.

Halliburton plans to continue close collaboration with Petrobras “for the foreseeable future,” the spokesperson added.

When asked whether the innovations being tested are potentially for use outside of Brazil, he said that technology solutions are NEWSBASE

The Cidade de Ilhabela FPSO, currently deployed in the Sapinhoá field, in the Santos Basin pre-salt cluster

“often more broadly applicable… While some challenges are unique to Brazil, many are also represented in other regions in which we operate,” he noted.

Brazil’s vast pre-salt reserves cover some 149,000 square km, and are located on the coast between the southern states of Santa Catarina and Espírito Santo. Cash-strapped Petrobras is hoping that by focusing on pre-salt it can turn round its wider financial struggles.

The firm has experienced significant production declines in recent years as a result of maturing fields and ageing infrastructure.

It has also been rocked by a major corruption scandal, causing its debt to soar. On the back of this and challenges presented by a period of low crude oil prices, it has needed to resort to cash-saving measures.

It has cut investment, slashed it production forecasts and divested some of its assets, to try and improve profitability. Last year the firm cut its 2016-2020 expenditure plan by 5% to US$93 billion, having previously already lowered it to US$98.4 billion from US$130.3 billion. At the same time, it made a 20% cut to its oil and gas reserves.

The company’s new strategy centres on maximising its best-returning opportunities, which typically means pre-salt development activities. With that in mind, cost efficiency is likely to continue to be the biggest driver of this latest cooperation. n

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InnovOil

Lighting the load A new collaboration between Photosynergy and WPS Technologies will help light up divers and subsea infrastructure – without the need for manual control

B

ACK in the carefree days of 2014, InnovOil reported on Photosynergy, a company spun off from the University of St Andrews’ Photonics Innovation Centre whose innovation in umbilical lighting was making waves in the diving industry.

LIGHTPATH™ uses a low-power LED light source and side-emitting 5-mm diameter optical fibre to enable flexible, continuous illumination of diver and equipment umbilicals, hatches, gangways and/or emergency lighting at oil and gas or renewables installations. Because the cables carry no power, they can stretch hundreds of metres and be used at depths of up to 500m.

The increased safety and security offered has seen them championed by the diving industry, with LIGHTPATH notably winning the Innovation for Safety Award at Subsea Expo 2014.

Building on a successful few years, a new collaboration is now finding additional deployment options for the technology. In combining LIGHTPATH with Seatooth – a subsea wireless communication system that can download and log information gathered on subsea installations developed by fellow Scottish subsea firm WFS Technologies – the technologies can bring added safety benefits to the ROV and diving industry.

Seatooth can be used in conjunction with all standard subsea instrumentation and control systems, and is used in a variety of applications such as flow assurance, pipeline monitoring and asset integrity. The company claims its technology allows data to be transferred at high rates and with low latency through seawater, the seabed, concrete blankets, metal pipes and the splash zone.

Seatooth LIGHTPATH™ is an on-demand wireless ribbon lighting system, suitable for diver and ROV operators working either near the surface or at depths of up to 3,000m. The light is engaged automatically when the diver or the ROV comes within 5m of a structure, and provides instant illumination of subsea architecture and delineating features such as

control valves, docking bays, or the outline of the structure itself.

It then switches off automatically when the diver or the ROV departs the scene. It also has the ability to act as a proximity warning system when approaching installations, other divers, ROVs or danger areas. Seatooth components allow wireless data transfer at up to 5m, with the option of 8MB integrated memory for data logging if required.

The unit has been successfully tested in the lab, and will be trialled in subsea conditions in early 2017.

Remote controls PhotoSynergy director Don Walker explained that the companies had joined forces in a bid to find a solution to an industry request for a remote switching system which would remove the need for physical contact. “By integrating the two products, we have produced a much more convenient and efficient method for lighting a challenging environment with no physical contact required from a distance of five metres. The subsea environment is an intrinsically dangerous place where it is easy to become disoriented, so the Seatooth LIGHTPATH™ is a very significant development in safety.”

The addition of automatic engagement should also prolong the life of remote, battery-operated lighting systems. Walked added: “This is most significant in terms of battery utilisation where LIGHTPATH is only illuminated as required operating either in a flashing or continuous operation.” Its battery will provide 16 hours of continuous use, 80 hours in flash mode and two years on standby.

If trials go well, it is not difficult to imagine an appetite for the system wherever divers or ROVs are working alongside subsea infrastructure. As safety remains the industry’s biggest concern, Photosynergy and WFS continue to light the way.. n Contact: Brendan Hyland, chairman WFS Email: Brendan.Hyland@wfs-tech.com Web: www.photosynergy.co.uk/

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New regulation from Oxford Flow An Oxford University spin-out firm has developed a new range of lighter, tougher – and now smarter – pressure regulators

I

N a challenging operating environment, the industry is forever seeking ways to work more efficiently in order to keep productivity up and costs down. This presents opportunities for engineering experts to produce solutions that can help solve some of the sector’s perennial problems – and even small solutions can enable major improvements.

One company with such an innovation is Oxford Flow, a spin-off of the Oxford University’s Department of Engineering Science. The core of the company’s IP lies in a new design of industrial pressure regulators – valves for regulating the flow of gases and liquids in industrial processes – based on a piston actuator system.

Conventional pressure regulators rely on a diaphragm, which is consequently the most common failure point in the valve.

With only one moving part and fewer overall components, Oxford Flow’s PRV design is significantly simpler and does away with the diaphragm requirement.

One side of the piston is exposed to downstream pipeline pressure; the other side is balanced against a pressure cavity controlled by a pilot regulator. During operation the piston moves inward, reducing the size of the cavity when the downstream pipeline pressure exceeds that within the pressure cavity set by the pilot regulator.

Go with the flow Oxford Flow founder and technical director, Professor Tom Povey explained that the concept for the valve arose while conducting R&D for aerospace applications including gas turbines, jet engines and scramjets, for clients such as Rolls Royce. “I was working with high flow rates of compressed gas that, for reasons of efficiency and safety, needed to be regulated,” he explained. “Regulators available on the market were not precise enough so I devised a completely new method of controlling gas and developed

Below: Inside the Oxford Flow regulator

a series of products based on this technology.”

As a result, Povey’s regulator is 80% lighter than existing models yet will handle over 10 times the volume, with a high degree of precision and control. For example, a 10kg DN100 model with a flow coefficient of 65 will handle inlet pressure up to 100 bar, as opposed to the 50-60kg weight of comparable conventional regulators capable of only 35 bar.

In addition, the lack of an elastomerNEWSBASE

Above: fitting an Oxford Flow regulator based diaphragm means that these regulators can be used to transfer corrosive media and media at high temperatures (they are rated to around 100°C) in the business’ standard specification IM / IHF models, or even higher temperatures if replacement seals are deployed – something that conventional equipment simply could not manage.

As a result, the company says that design offers greater reliability and a lower failure rate, meaning lower maintenance costs for users. n Contact: Steve Busby, Business Development Director Tel: +44 (0)7779 625189 Email: steve.busby@oxford-flow.com Web: www.oxford-flow.com

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Chinese researchers claim Callum Cyrus reports on a new drilling system that could allow offshore

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ESEARCHERS at Jilin University claim to have made a breakthrough on gas hydrate exploration with a land-based drilling system that introduces new principles for cooling and sampling at high temperatures.

Jilin University launched research and development of combustible ice drilling in 2004, and has already overcome hurdles such as operations from high altitudes, Sina reported last month.

Natural gas hydrates are lattices of water molecules that contain methane, potentially representing one of the largest reservoirs of carbon-based fuel. Currently, their presence represents a barrier to deepwater exploration because of their ability to obstruct production.

But if returned to the earth’s surface, the EIA estimates that one cubic foot (0.02 cubic metres) of gas hydrate could up to yield 164 cubic feet (4.67 cubic metres) of gas.

Chills and spills The methodology for gas hydrate sampling worldwide can be broadly categorised across four techniques: thermal stimulation, depressurisation, inhibitor injection or a combination of these. Depressurisation and thermal have been considered the most viable in terms of both economics and technical achievability, but Jilin’s approach appears to be predominantly based around the injector model.

The researchers focused initially on developing mud cooling technology to ensure gas hydrate operations were conducted within the temperature bracket needed to collect high-fidelity hydrate cores. According to a 2010 blueprint, their system features four heat exchangers that form a Freon closed cycle, two secondary refrigerant open cycles and a mud open cycle.

Mud cooling was piloted in the Mohe Basin, where the researchers claimed to have proved their system is capable of resisting ambient temperatures and geothermal gradients with an efficiency rate of 54.8%.

Jilin University also said that their system was cheaper to operate than a comparable technique designed by Texas-based DrillCool.

Subsequently, the team’s development work turned to the sampling system

needed to retain hydrate batches and observe the properties of reserves held in permafrost land. In 2011, they unveiled a borehole freezing technique for sampling which satisfied the thermophysical and temperature-pressure requirements of gas hydrate drilling.

They argued this technique could significantly reduce sampling pressures while inhibiting the decomposition of hydrate samples, by providing an external cold source capable of freezing cores at the bottom of the borehole.

The researchers said the system had been demonstrated successfully during pilot core NEWSBASE

drilling, carving out a “novel” approach to in-situ hydrate corers for Chinese research.

Also crucial was what researchers described as a “low temperature mud system” for sodium chloride (NaCl) and potassium chloride (KCl), as ordinary mud was found to perform inadequately at low temperatures. This component is said to yield mud capable of resisting temperatures as cool as minus 20 celsius.

Size of the prize With Chinese energy demand projected to rise by 1.5% annually until 2020 and then 1.4% until 2030, according to CNPC’s

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gas hydrate breakthrough resources to be tested and sampled from land-based equipment An aggregation of methane ice worms inhabiting a white methane hydrate. Studies suggest that these worms eat chemoautotrophic bacteria that are living off of chemicals in the hydrate. Picture: NOAA Ocean Explorer

research think-tank, Beijing has been eager to drive progress towards gas hydrate production. China extracted its first gas hydrate sample for research purposes in 2007 and plans to ramp development and testing this year.

But questions remain over the substantial costs associated with largescale development and the potential environmental implications of mining. In September 2014, deputy director of the China Geological Survey Li Jinfa was quoted

by IB Times as warning the release of gas hydrate during “improper drilling” could potentially trigger geological disasters.

Estimates from the US Geological Service (USGS) suggest Earth could contain anywhere between 10,000 tcf and 100,000 tcf (283.1-2,831 tcm) of gas hydrate resources.

Figures for China itself are unstable, with incomplete research estimating it holds 84 tcm of reserves, primarily concentrated in the East and South China seas, as well as permafrosts in Northeast China and at the Qinghai-Tibet Plateau.

With Chinese energy demand projected to rise by 1.5% annually until 2020 and then 1.4% until 2030, according to CNPC’s research think-tank, Beijing has been eager to drive progress towards gas hydrate NEWSBASE

production. Schedule estimates cited by the MDPI’s sustainability review last year indicated China would target commercial production testing between 2021 and 2035, and larger-scale testing from 2036-2050.

But the same paper, written by Zhongfu Tan, Ge Pan and Pingkuo Liu of North China Electric Power University, concluded that Beijing lacked a concrete strategy for development and industrial deployment.

It said that gas hydrate, with a cost of around US$200 per cubic metre, would somehow need to overcome competition from cheaper unconventional fuels such as shale and CBM. n

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ExxonMobil premieres new dehydration technology

March 2017

Tim Skelton takes a closer look at ExxonMobil’s cMIST gas dehydration technology – a smaller, lighter alternative to steel towers

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OLLOWING successful field trials, US oil and gas giant ExxonMobil now says its compact in-pipe dehydration technology is ready for commercial launch. The new proprietary cMIST™ technology is aimed at improving the efficiency of offshore gas production, which the company modestly describes as a “step-change in operational efficiency.” It uses the absorption of moisture inside the pipes themselves to dry the extracted gas, bringing significant savings in size, weight and costs.

Conventional dehydration Drying extracted gas by removing the water vapour mixed with it is not a new concept.

Dehydration technology is already a wellestablished standard part of processing natural gas on onshore and offshore rigs. But the conventional manner of achieving this normally involves bulky and expensive steel dehydration towers. These can be as much as 30 metres in height, they are heavy, and – perhaps most importantly – they take up a great deal of valuable room on the rig. This can be a particular issue at offshore facilities, where space is always at a premium.

The new technology effectively does

In-line dehydration equipment on a skid

away with the need for this large equipment, dehydrating the gas using an innovative patented absorption system located inside the pipes.

How does it work?

In its most basic form, the cMIST process involves two key technologies: the first stage uses a patented droplet generator that was developed in-house by ExxonMobil Upstream Research following what was said to be around 6,500 hours of research.

The droplet generator’s passport to success is that it can improve the effectiveness of what is otherwise a conventional glycol solvent.

One innovative feature is that the energy it requires is harvested from the fast-flowing gas within the pipe. It uses this to break up the solvent into tiny micro-droplets of the desired size. These droplets are small enough to be easily dispersed throughout the whole pipe diameter when sprayed into the gas flow.

The decrease in droplet size also greatly increases the relative surface area of the solvent that can be exposed to the gas. This in turn enhances the solvent’s ability to absorb water, boosting the efficiency of the process as a whole.

After the solvent has become saturated, the second process stage involves an in-line separator. This re-coalesces the tiny waterladen glycol droplets back into a cohesive whole, and moves the solvent to the outside wall of the pipe, whereupon it can be more easily separated from the dry gas and removed.

Once it has been syphoned out of the system, the solvent is regenerated using a conventional drying system to remove the water. As this point it is recycled and returned to the droplet generator to begin another cycle.

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The separator ExxonMobil chose to use is a special compact HiPer™ in-line model developed and patented by the Chemtech division of Swiss engineering giant Sulzer.

Chemtech is an established player in such technologies, and its HiPer line already has a proven track record in the field.

The resulting droplet generator and separator combination is able not only to remove water vapour from gas more effectively; it also reduces both corrosion and interference in the equipment. This, the developers say, will help to ensure safer and more efficient transport of gas through the entire supply infrastructure.

Reducing the footprint By moving much of the process inside the pipes and effectively removing the need for a conventional drying tower, cMIST reduces burdens of the system in several ways.

According to the developers, the compact size of the new technology means it decreases the surface footprint of the dehydration system by as much as 70%. Moreover, the weight of the new system is no more than half that of its conventional predecessors. These reductions could have a significant impact in terms of lowering the cost of materials, as well as offering the tangible benefit of space savings – especially useful for offshore platforms.

“With cMIST we’ve eliminated a large

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Conventional dehydration tower “Our researchers were able to create this advanced natural gas dehydration technology, which represents a step-change in operational efficiency and a significant reduction in footprint,” Tom Schuessler, president of ExxonMobil Upstream Research said in a statement when the process was unveiled to the press.

ExxonMobil’s cMIST unit is 50% lighter and takes 70% less spave than the traditional option

and cumbersome piece of equipment and replaced it with a solution that fits into a few pipe segments,” Norman Yeh, a member of the cMIST development team at ExxonMobil Upstream Research, told the parent company’s

own corporate news site Energy Factor. “The space and weight reduction is important because we could, for example, use the freedup space to deploy devices that could help increase output,” he added.

NEWSBASE

Ready to launch The company launched the cMIST process at the beginning of this year. ExxonMobil says it is suitable for deployment at both land-based and offshore natural gas production operations. As a result of the technical tie-up between the two companies, it has also selected Chemtech to be the exclusive worldwide licensee of the technology. Chemtech will use its expertise in the specialist field to facilitate commercial deployment of the technique across the industry.

The developers say they are confident the new technology will provide the industry with much-needed reductions in capital expenditures for both new projects and at existing facilities.

This will come as welcome news at time when margins across the upstream industry are being squeezed at both ends by a combination of higher production costs and low oil and gas prices. n

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Study contracts awarded for SW Britain and East Shetland Platform As part of the 21st Century Exploration Road Map initiative (21CXRM), the Oil and Gas Authority (OGA), in collaboration with the 21CXRM Technical Advisory Committee, has awarded two contracts for petroleum system related studies for the East Shetland Platform and South West Approaches areas.

The contracts have been awarded to Getech and BGS for South West Approaches and FROGTECH and IGI Limited for the East Shetland Platform. Both projects are expected to be completed by the end of Q1 2017.

The provision of the studies has been supported by the MER UK Exploration Task Force and will complement the acquisition and reprocessing of seismic data in this area which has formed part of the 2016 UK Government Seismic Programme.

Nick Richardson, OGA Head of Exploration

and New Ventures, said: “These projects represent the initial phases of more extensive regional mapping projects to drive exploration across the UK Continental Shelf.

“The results of these projects from Getech, BGS, FROGTECH and IGI Limited will enhance industry knowledge, awareness and understanding of both the South West Approaches and East Shetland Platform ahead of the 31st Frontier Licencing Round.”

Other projects completed by the 21CXRM include a post-well analysis of exploration and appraisal wells drilled during 2003-2013 in the Moray Firth and Central North Sea, which can be found here, and a geoscientific regional petroleum system analysis of the Palaeozoic which is due to be released publically in Q2 2017 OGA

Retender due for ADCO field expansion ABU Dhabi Company for Onshore Petroleum Operations (ADCO) is expected to issue a

revised tender by the end of the first quarter for the development of the Qusawira oilfield to the south east of the UAE capital.

The move follows formal abandonment of the previous bidding process – which had stalled amidst the industry downturn that prompted a review of major capital projects across the slate of the ADCO’s parent Abu Dhabi National Oil Co. (ADNOC).

Renewed progress is reflective of the greater certainty around ADCO’s plans over the past month after the assignment of a stake in the newly-reconstituted onshore concession to a second international oil heavyweight and assertiveness on the part of the first foreign partner in pushing forward delayed expansion projects, which have simultaneously been rendered more attractive by the strengthening oil price.

ADCO originally tendered the engineering, procurement and construction (EPC) for the phase-two expansion of Qusawira field – located in an environmentally-sensitive area 260 km south of Abu Dhabi City – in early 2015 and received technical bids during the third quarter of that year, with a deadline for commercial offers pending ever since.

The project calls for an increase in capacity at the field – brought on stream at 30,000 barrels per day in 2013 by the local National Petroleum Construction Co. (NPCC) – to 55,000 bpd.

Five companies were competing for the estimated US$500-700 million job – the local Al-Asab Contracting Establishment, China Petroleum Engineering & Construction Co. (CPECC), UAE-based Dodsal, Spain’s Intecsa Industrial and Italy’s Tecnimont.

However, bidders were finally informed recently that the tender had been cancelled with a view to a new invitation to bid being floated by the end of the first quarter with a revised scope.

Canada’s SNC Lavalin carried out the original front-end engineering and design (FEED) study.

Edited by Ian Simm ians@newsbase.com

Hyosung plans LPG, petchem complex in Vietnam South Korean chemical and textile maker Hyosung has signed a memorandum of understanding (MoU) with the Vietnamese government on investing US$1.2 billion in the construction of a manufacturing and storage NEWSBASE

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complex to turn out polypropylene (PP) and LPG. The new complex will be located in the Cai Mep industrial zone, in Ba Ria Vung Province near Ho Chi Minh City. The manufacturing plant will run on natural gas.

Construction will be in two phases, starting with a US$336 million polypropylene plant and a US$133 million LPG storage facility. That will be followed by construction of a US$496 million propane dehydrogenation plant and a second polypropylene facility for US$226 million.

According to VietnamNet, the completed polypropylene plants will have capacities of 300 million tonnes and 300,000 tonnes per year. The complex will cover 600,000 square metres.

“We will boost our price competitiveness with the integrated production system ranging from LPG to PP and expand our share in markets with great potential, such as Vietnam, China and Southeast Asia,” Hyosung said in a statement.

It added that the size of investment and the project’s timeframe were subject to change.

The deal comes less than a month after the promotion of Cho Hyun-joon, grandson of the firm’s founder, from the position of president to that of chairman. He succeeds his father Cho Suck-rai. It was the younger Cho who began negotiations in November 2016 with the Vietnamese government on the Cai Mep project.

Hyosung has operated in Vietnam’s Nhon Trach industrial zone, Dong Nai Province, since 2007. Its production there includes tire cord and spandex. Hyosung leads the world in market share for both those products. Its investment at Nhon Trach has reached US$1.3 billion to date.

The firm recently announced that its operating profits reached 1 trillion won (US$870 million) for the first time in 2016. Hyosung is expected to concentrate on the Chinese market for the expansion of its chemical business, which accounted for 15% of its profits in 2016. It is also planning to build a new PP plant in South Korea with annual capacity of 200,000 tonnes.

That facility will cost US$122.2 million

Brent, which lies in Block 211/29 and gives its name to the crude benchmark, reached first oil from four platforms in 1976 and has produced some 3 billion boe to date. Charlie is the only Brent platform still produce oil, though Shell said it expected the installation to do so for “some time.

At one stage, Brent represented 10% of production on the UK Continental Shelf (UKCS), and the project received a GBP1.3 billion (US$1.63 billion) overhaul in the mid1990s. UKCS explorers are increasingly nearing the decommissioning phase as fields deplete at one of the world’s oldest active upstream regions after around 40 years of production.

Other big UK decommissioning projects under way include BP’s end-of-life contract with Petrofac at Miller and CNR International’s Murchison in Block 211/19a. There have been concerns that the UK sector lacks sufficient capacity to undertake the scale of decommissioning on the UKCS. More than 250 fixed installations in the UK are awaiting decommissioning, plus around 250 subsea production systems, 3,000 pipelines and 5,000 wells. In July 2016, the OGA recommended that firms would need to shave 35% from decommissioning spends, in particular within the well abandonment, topsides and cessation of production areas.

The OGA also warned the substantial costs of decommissioning could deter smaller investors from becoming involved with the North Sea, thus preventing mature fields from reaching maximum economic potential.

Nevertheless, the region has seen a series

of deals between big players and their smaller counterparts, often backed by private equity firms. Under Shell’s US$3.8 billion disposal of UKCS assets to Chrysaor, the decommissioning cost associated with the package was estimated at US$3.9 billion, surpassing the transaction’s price tag itself. But Shell agreed to retain a fixed liability of US$1 billion for deconstruction, perhaps illustrating how majors will need to give some headway on end-of-life assets to ensure maximum production on the UKCS. Edited by Ryan Stevenson ryans@newsbase.com

Russia mulls support scheme for local tech THE Russian Industry Ministry has reportedly developed a scheme that could unlock some 35 billion rubles (US$581 million) in financial support to oil and gas developments in the Russian Arctic.

The scheme, which was outlined in a document seen by Russia’s Kommersant newspaper, is designed to curb Russia’s dependence on foreign equipment and technology. If approved, it could receive as much as 24 billion rubles (US$398 million) from the state budget and 11.7 billion rubles (US$194 million) from non-budgetary sources.

These funds would be spent on research of new technologies and equipment, including development of prototypes, for use at onshore

Edited by Andrew Kemp andrew.kemp@newsbase.com

Shell submits plans for Brent decom work

DECOMMISSIONING THE BRENT FIELD

Royal Dutch Shell has marked a milestone for the offshore UK North Sea after filing the decommissioning programme for Brent oilfield to the UK government.

WWW.SHELL.CO.UK/BRENTD ECOMM

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and offshore fields in Russia’s Arctic frontier.

According to the document, the ministry expects a return of 51.7 billion rubles (US$858 million) from these investments. US and EU sanctions currently prevent Russian oil companies from tapping advanced Western technologies and equipment for use at offshore sites in the Arctic. The ministry concluded in the report that Russia lacked the modern technologies necessary to prospect and explore deposits on the Arctic shelf on its own.

Currently, the ministry said, the oil and gas sector relies on imports to meet 80% of its needs in this field. Furthermore, 90% of software used in the Russian oil industry is developed abroad, it said, exposing the country to security risks.

The ministry said its main goal was to develop at least 25 prototypes of domesticallyproduced devices that could replace imported equipment. These models would be tested at sites in Murmansk, Tiksi and on the coast of the Pechora Sea. The ministry also noted that Russian seismic technology was “significantly” below international standards. Many Russian surveying vessels operating on the shelf use foreign equipment, it said, while only Rosgeologiya subsidiaries Sevmorgeo and Geotech use domestically-produced kit.

The timeframe for implementation of these plans is unclear. However, the ministry noted that full-scale oil and gas production on the shelf was not expected to begin before 2025.

Currently, Russia’s only producing asset in the Arctic is Gazprom Neft’s Prirazlomnoye field, which yielded 1.8 million tonnes (36,000 bpd) of oil last year.

According to Kommersant, the Russian Finance Ministry is likely to oppose the measure as it will act as a subsidy for production equipment. However, most of the sources who spoke to the newspaper concluded that the scheme was likely to be adopted, as oil companies will support it

engineering, and services to BP for three years under frameworks extendable by a further two years.

It follows similar FEED frameworks signed between Aker and BP for subsea engineering work in August 2016. Aker Solutions will be among four preferred bidders considered for subsea contracts across BP’s portfolio over the next five years.

It will also be able to supply subsea services to BP under a second contract covering auxiliary business for any hardware installed by the Norwegian firm. Aker Solutions primarily serves the subsea and field design segments, but has shifted its focus towards overseas markets to compensate for the poor outlook at its core operations.

Around 66% of Aker Solution’s revenues were generated from outside Norway in 2015, up from below 50% two years earlier. Low oil prices forced explorers to limit their capital expenditures, leaving design vendors with fewer orders and greater pressure to provide the best price. Accounting for write-downs booked in 2015, Aker Solutions has made firm progress on cost reductions and earnings growth over the last year.

Its EBITDA margin reached 6.2% during the fourth quarter of 2016 compared with 2.3% one year earlier, lifting core earnings from 182 million Norwegian kroner (US$21.7 million) to 380 million kroner (US$45.47 million).

Aker Solutions’ parent, Aker, was last month reported to be considering the sale of its 34.8% stake reportedly valued at 3.5 billion kroner (US$418.85 million) as of September 2016, up from 178 million kroner (US$21.3 million) in June 2016.

But fiercer competition is on the horizon following the US$13 billion merger of FMC Technologies with Technip in January, which is

Edited by Joe Murphy josephm@newsbase.com

Aker scores two FEED deals with BP AKER Solutions has advanced its battle for market share in the design and engineering segments by landing two FEED frameworks with BP for projects across the UK supermajor’s global portfolio.

The Oslo-based company will be given the opportunity to offer feasibility work, concept NEWSBASE

anticipated to threaten Aker Solutions’ presence in the subsea segment. Generally, the subsea market has consolidated in recent years to reduce costs and offer customers a one-stop shop for services and construction.

FMC and Technip initially partnered with their Forsys Subsea JV announced in March 2015, while Aker Solutions announced its own subsea tie-up with Eni-subsidiary Saipem in December 2015.

Edited by Ryan Stevenson ryans@newsbase.com

World’s first barge-based FSRU undocks THE world’s first barge-based floating storage and regasification unit (FSRU) has undocked from its drydock at Nantong, China, where Wison Offshore & Marine provided engineering, procurement and construction (EPC) services for Exmar of Belgium.

The undocking, topside installation has been completed, paving the way for successful delivery, Wison Offshore & Marine said on January 25. The FSRU is the first to be built in China and will become the world’s first FSRU with small-scale storage capacity, Wison said. The non-propelled FSRU barge has a regasification capacity of 17 mcm per day. Two SPB (self-supporting, prismatic IMO Type B) cargo tanks, each with a capacity of 12,500 cubic metres, are installed in the hull for LNG storage.

The FSRU is the second project on which Wison and Exmar have been co-operating following the Caribbean FLNG. Wison noted in its statement that it had adopted a modularisation strategy, so that the hull and

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shareholder and creditor, has reiterated plans to keep the shipbuilder afloat via an additional bailout.

Edited by Richard Lockhart richardl@newsbase.com

Amec wins Kuwait petchem design contract

the topside modules of the FSRU had been fabricated simultaneously.

This not only reduced the safety risks and improved construction quality but also helped to shorten the delivery schedule, Wison said.

It added that it had made a few technological breakthroughs, including development of its own cargo containment system and cargohandling system for the IHI SPB tanks.

Meanwhile, the regasification module has been successfully applied in the final performance test of Caribbean FLNG project as its temporary regasification skid, Wison noted.

“The successful undocking of the FSRU once again verifies Wison’s strong competence in the lump sum turnkey projects for floating LNG facilities,” said An Wenxin, senior vice president of Wison Offshore & Marine.

“It further proves that we are capable of providing the market with the most costeffective EPC solutions that are applicable in other LNG developments, such as the new W-FSRP (Wison – Floating Storage, Regasification and Power generation) series we launched recently,” he said.

Edited by Richard Lockhart richardl@newsbase.com

Excelerate and DSME set up prospective 7-strong FSRU order EXCELERATE Energy has placed a preliminary order with Daewoo Shipbuilding & Marine

Engineering (DSME) for up to seven FSRUs in what could be a life-saving deal for the financially-strapped South Korean shipbuilder.

Texas-based Excelerate announced on February 9 that it had executed a letter of intent (LoI) with DSME to order one FSRU in the second quarter of 2017, with the option to commission an additional six vessels, in a total order worth a combined US$1.6 billion.

DSME separately issued a disclosure on the deal, but said details for the final contract had not been set. Korean media said the two sides were to sign the final prospective deal next month.

The world’s largest operator of regasification vessels and developer of LNG import solutions, Excelerate said the initial specifications are for 173,400 cubic metre FSRUs with a baseload send-out capacity of 28.3 mcm per day of gas which can be modified to suit specific project needs.

It described them as the “most capable and fuel-efficient FSRUs in the industry”, following their introduction in 2005.

Excelerate said the agreement affords it the ability to respond to increasing market demand for natural gas at a time when its existing fleet of nine FSRUs become committed to long-term projects.

“Excelerate Energy is very pleased to continue its longstanding relationship with DSME in building the industry’s leading FSRUs. These vessels have been proven in long-term service as safe, efficient and reliable components of our comprehensive suite of LNG import solutions,” said Excelerate chief executive officer Rob Bryngelson.

DSME, for its part, is reportedly facing a default crisis on 440 billion won (US$383 million) of bonds that mature in April. The state-run Korea Development Bank, its largest NEWSBASE

PLANS to create a world-scale downstream hub at Kuwait’s southern port of Al-Zour took an important step forward in late January. A design contract was awarded on the proposed petrochemicals complex to be integrated with the greenfield refinery now finally under construction at the site.

The move follows the formation last year of a dedicated subsidiary of state oil conglomerate Kuwait Petroleum Corp. (KPC) to oversee development of the overall project, which also encompasses an upcoming LNG import terminal.

Official announcement of the contract additionally revealed the planned configuration of the chemicals complex – chosen after lengthy studies over the past two years by an international consultancy.

Kuwait is a currently a relatively minor petrochemicals producer compared to similarly oil-rich Gulf Co-operation Council (GCC) counterparts, largely through a lack of the ethane gas feedstock on which the existing local industry is based. However, recent progress on long-planned refining sector expansion has occurred at the right time for the state to join the GCC trend towards diversifying into liquids-based production.

The UK’s Amec Foster Wheeler was selected to carry out design studies on the proposed Al-Zour petrochemicals plant, according to a statement carried by the official KUNA news agency on January 26.

Surprisingly, Petrochemical Industries Co. (PIC), KPC’s longstanding subsidiary for the development of the sector since 1963, was named as the client – rather than the new Kuwait Integrated Petrochemical Industries Co. (KIPIC).

The creation of the new firm to own and operate the three Al-Zour projects was approved by the government’s Supreme Petroleum Council in the third quarter of 2016.

Amec’s selection was not unexpected. The British company has a longstanding relationship with KPC’s existing refining subsidiary, Kuwait National Petroleum Co. (KNPC), dating back to

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Purple Hayes

before the acquisition of the US’ Foster Wheeler in 2014 and was the project management consultancy (PMC) and front-end engineering and design (FEED) contractor on the Al-Zour refinery – which, in common with the LNG terminal, has hitherto been handled by KNPC. Edited by Ian Simm ians@newsbase.com

ITF steps up action to solve costly pipe-walking problems The Industry Technology Facilitator (ITF) is welcoming additional participants to a new joint industry project (JIP) to develop pipeline anchoring and monitoring systems which could mitigate the risk of pipeline walking and cut pipeline anchor installation costs in half.

The Anchoring Pipeline Technology (APT) JIP will bring together major global operators and pipeline installation companies to collaborate with ITF and Crondall Energy, an independent oil and gas consultancy, to investigate alternative and less costly solutions and create a roadmap on how to manage and mitigate the pipe-walking challenge.

David Bruton, Director Subsea, Crondall Energy, said: “There is much uncertainty over walking rate predictions in design, leading to increased design costs and schedule overruns.

In many cases, these uncertainties are resolved by installing anchors as a pre-emptive mitigation measure, which has proven to be extremely costly, not entirely successful and, in some cases, unnecessary.

“Because the evaluation of alternative, less costly, more elegant design solutions are generally beyond the timescale of a typical project, there has been little opportunity for optimisation or more considered evaluation of alternatives. The knowledge gained from the APT JIP will add significant value to a client’s ability to design and install efficient and safe pipeline anchoring systems.”

Pipe-walking, or axial ratcheting, has been observed on a number of pipelines and can cause integrity concerns, including very large global axial displacements of the pipeline. In some cases, this has resulted in tie-in connector failures or subsea intervention to mitigate or control high rates of walking.

Large suction anchors, with a capacity of around 100 tonnes are typically installed at the end of the pipeline to control walking. In more recent projects, some long pipelines have required several anchors to be installed over the pipeline length.

The potential overall saving from the deployment of optimised distributed-anchoring systems is expected to be up to 50% of a typical installed cost. For example, this could result in a cost saving of more than USD5m for a project planning to install several anchors on a single long pipeline.

The study will complement existing research by using the extensive experience of JIP participants. It will provide design strategies to simplify the design process and present a roadmap for projects to manage and mitigate the walking challenge over the project cycle.

This will include the development of a ‘wait and see’ approach based on effective monitoring of pipeline walking by applying mitigative measures only when and where they are required.

ITF

NEWSBASE

Eclipse sets out super-lateral plans PENNSYLVANIA-BASED Eclipse Resources has said it will step up capital expenditure to US$300 million this year, which will see the company drill a number of super-lateral wells – which extend 15,000 feet (4,572 metres) or more – in the Utica shale.

On February 7, the company released an operations update along with details of fullyear production for 2016, which stood at an

March 2017

InnovOil

page 39

NEWS IN BRIEF

last year, even as it was constraining activity. The well reached a total depth of 27,046 feet (8,244 metres).

According to the company’s initial capital budget for 2017, 19 net – or 22 gross – horizontal Utica wells will be drilled. Eclipse anticipates completing 19 net – or 20 gross – horizontal Utica wells. The budget also includes the drilling and completion of 1.9 net – or two gross – Marcellus wells.

Eclipse went on to say that 11 of these wells would be super-laterals, three of which would be located in its Utica dry gas acreage area, and eight in its Utica condensate region.

Eclipse projects that its capex budget for the year will be around US$300 million, though the company noted that this excludes potential acquisitions and payments for land leased in 2016 and due to be paid in 2017.

Edited by Anna Kachkova annak@newsbase.com

average of 229 mmcf (6.5 mcm) per day of gas equivalent. This, it said, was above the midpoint of its previously issued guidance range.

In addition, Eclipse outlined its 2017 plans, which call for a further ramp-up in spending, after the company started raising its capex budget in the second half of last year.

Initially, low energy prices had forced the company to cut capex to US$196 million for 2016, with rigs idled and output voluntarily lowered as a result. However, improved market conditions prompted a rethink of plans and an uptick in operations. The company also completed the record-setting Purple Hayes well at a lateral length of 18,544 feet (5,652 metres)

Gazprom trials Russian-made PDC bit GAZPROM Neft, the oil arm of Russia’s stateowned natural gas monopoly Gazprom, said last week that it had completed the pilot testing of a new type of drill bit at an oilfield in the YamalNenets autonomous area.

In a statement, the company said it had been testing the first polycrystalline diamond composite (PDC) drill bit ever produced in Russia. The tests were carried out at the Vyngapurovskoye site, which is now in the pilot production stage, it said.

According to Gazprom Neft, the PDC drill bit performed well in the tests and demonstrated high durability. The new bit allowed the drill to NEWSBASE

pass through the 2,237-metre test section of the well without sustaining any damage or loss of inserts, the statement said. It also showed a high penetration rate and good manoeuvrability, it said.

The company intends to continue testing the new bit at another field – Yarainerskoye, located in the Purovsky district of the Yamal-Nenets autonomous area. It will use the bit to spud a new well at the site later this month. This phase of the pilot programme will allow Gazprom Neft to assess the equipment’s performance in a more geologically complex reservoir. If the tests are successful, the firm’s upstream subsidiaries will begin using bits of this type for drilling projects.

The PDC bit was designed by VolgaBurService, a company based in Russia’s Samara region. It is capable of drilling vertical, horizontal and directional wells in soft strata interspersed with medium-hard rocky layers – that is, in conditions similar to those prevailing in the Yamal-Nenets autonomous area.

Sergey Arkhipov, Gazprom Neft’s head of technological partnerships and import substitution, said that the company had worked with VolgaBurService within the framework of a wider effort to reduce dependence on imported production equipment and technologies.

“Russian oil and gas equipment manufacturers are successfully replacing many foreign offerings with their own solutions,” he said. “Gazprom Neft is playing an active role in this process, working closely with domestic companies to develop new products, offering technological expertise and offering opportunities for testing prototypes at our own facilities. It is precisely this sort of technological partnership between producers and customers that is so fundamental to the successful development of the country’s industrial base.”

Edited by Joe Murphy josephm@newsbase.com

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What next …?

To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections

The automated decision-making protocols of Motive Drilling’s Directional Drilling Bit Guidance System are increasing the speed and accuracy of directional drillers, To see how it could help your operations, contact Bill Chmela on (+1) 469 729 6470 or via info@motivedrilling.com If the 3D-printed sensor technology developed by Professor Therriault and his team could be of use to your technology or assets, please get in touch on (+1) 514 340 4711 ext. 4419, or email daniel.therriault@polymtl.ca For more information about Sea-Source Offshore Services, or the ongoing work at Kilkeel harbour, contact Davey Hill on +44 (0)28 4176 2855 or email info@sea-source.com Oil & Gas UK’s Decommissioning Insight 2016 Report is available to download here For information about the Seatooth LIGHTPATH™ system, contact WFS chairman Brendan Hyland, at Brendan.Hyland@wfs-tech.com or Photosynergy at info@photosynergy.co.uk Interwell’s thermite P&A programme is already yielding promising results for the decommissioning sector. Contact Terje Hauan, P&A commercial manager, for more information on +47 41 44 77 22 or via teha@interwell.com If Oxford Flow’s innovative PRV design could enable improvements in your operations, contact Steve Busby, OF business development director on +44 (0)7779 625189 or email steve.busby@oxford-flow.com

NEWSBASE

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