InnovOil Issue 37 September 2015 by NewsBase Ltd.

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Bringing you the latest innovations in exploration, production and refining Issue 37

September 2015

A new era in completion fluids has arrived … Page 14

Down tools

Utility ROV Services’ unique subsea equipment Page 6

Sustainable supply

AkzoNobel’s take on the future of the chemical oilfield Page 18

s l caDE i mt INSI e hemen21 C dsuppl s 9l ieecial Page f l Sp i o w

InnovOil

September 2015

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Inside A note from the Editor

Utility players

The engineering behind Utility ROV Services specialist subsea equipment for renewables and decommissioning

Contacts: Media Director Ryan Stevenson ryans@newsbase.com

Oilfield Chemicals 9 The chemical challenge

Going ultra-deep

Clariant’s innovation

The chemical future

Deeper and greener

The power of Zero

Sixth sense

Dr Henry Craddock discusses new chemistry and new responsibilities

Associate Director of Business Development Andrew Stalker andrews@newsbase.com

TETRA Technologies has new, innovative and high-performance completion fluids

Media Sales Manager Riley Samuda RileyS@InnovOil.co.uk

Clariant Oil Services’ history of nurturing innovation and sustainability

Editor Andrew Dykes andrewd@newsbase.com

Innovator AkzoNobel offers its view of oilfield chemistry for the 21st century

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

Oil and fluid marketer SIP is helping the industry move to new frontiers

Phone: +44 (0) 131 478 7000 www.newsbase.com www.innovoil.co.uk

U.S. Water’s corrosion and scale inhibitor is without aquatic toxicity concerns

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

Distributed Acoustic Sensing from Fotech Solutions

Miraah, Miraah 24 GlassPoint Solar’s Miraah EOR project in Oman is set to be the largest of its kind

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ations Bringing you the latest innov

and refining in exploration, production

September 2015

Issue 37

The future is robotic

Propane – no gain?

News in brief

The London South Bank Innovation Centre and the robotics which could shape the future oil and gas industry

A new era in completion fluiDs hAs arriveD …

Page 14

A new proposal to use gelled propane for hydraulic fracturing in New York

Down toolss’ unique subsea equipment Utility ROV Service Page 6

ble supply sustaina chemical oilfield take on the future of the AkzoNobel’s Page 18

ls ca mtiinsiDe e chemen 21

Recruitment 38

D ppl 9ielal su ges lfspeci Pa i o

Contacts 39 NEWSBASE

Researched & Organized by:

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September 2015

InnovOil

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A note from the Editor Although the global news flow tends to take a dip in August – and even technical departments need holidays once in a while – September remains one of InnovOil’s busiest months. The upcoming Offshore Europe conference in September looms over most of the industry’s calendar, but our attention this issue is turned even further – to the Royal Society of Chemistry’s biennial Chemistry in the Oil Industry symposium in November. This year meeting under the banner of “Challenges and Responsibilities,” the event tackles some of the issues facing the oilfield chemistry sector, as well as shining a spotlight on some of its more interesting and innovative chemical developments. Our accompanying Oilfield Chemistry supplement aims to do the same. One of the conference’s organisers, Dr Henry Craddock, also spoke to us on the theme, outlining the state of new chemistry today, and where the industry should look next. While environmental regulations – and operator budgets – pose their own hurdles to innovation, he points out, “That doesn’t mean there are not new and clever applications.” Inside our supplement, Clariant Oil Services explores its recent contract win at the Johan Sverdrup field, as well as profiling its latest flowback aid, HOSTAFRAC SF 13213. Meanwhile, AkzoNobel discusses its view of how innovation can be a driver to make the whole chemical supply chain more sustainable, while fluid marketer SIP also profiles its SIPDRILL base oils. From this month’s cover, Houston’s

TETRA Technologies offers up its latest innovations, formulated to meet the demands of a market pushing into deeper waters and higher pressures. We take a look at TETRA CS Neptune completion fluid and the SafeDEflo® ultra deepwater (UDW) Filtration System, both of which been deployed successfully to operators in the Gulf of Mexico. We also sat down with John O’ Donnell of GlassPoint Solar to discuss the 1,021-MW Miraah project in Oman – the bold next step for a company pushing the boundaries of solar enhanced oil recovery (EOR). We also speak to Scotland’s Utility ROV Services, a company with a pedigree in developing and designing innovative technology for commercial salvage, now turning its hand to providing subsea equipment and expertise for the oil and gas industry. With fracking once again on the national agenda in the US, thanks to an unusual proposal in New York State, Ros Davidson weighs up the pros and cons of hydraulic fracturing using gelled propane. In the realm of robotics, Sophie Davies also speaks to robotics and technology firm TWI about its recently opened South Bank Innovation Centre (LSBIC), and how its research is forging new paths for robotic inspection. You’ll also find our recruitment section located at the rear of the publication, bringing you some of the best new opportunities from around the world. The team and I are pleased to bring you the September edition of InnovOil.

Andrew Dykes Editor

NEWSBASE

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InnovOil

Utility players

September 2015

InnovOil talks to Utility ROV Services about the engineering behind its specialist subsea equipment for renewables and decommissioning

hile subsea equipment can now perform more functions than ever before, the industry lacks a true workhorse. Different classes of ROVs are, of course, tasked with different roles, but while these can be re-engineered, re-tooled and redeployed, this all adds time and money. Enter an ingenious Scottish firm. With its roots in a family-run commercial cargo recovery business, Utility ROV Services’ managing director Patrick Crawford has helped develop a versatile and flexible set of winch-deployed tools for subsea work – a concept explained to InnovOil as “a subsea tractor.” Formed in November 2013, the launch of the Glenrothes-based company was the culmination of around seven years’ worth of development and deployment, producing a number of innovative tools used to tackle the unique challenges posed by sunken ships and offshore structures. These jobs saw the firm continuously design and build its own bespoke equipment – the result of which is the UTROV system. It allows the team to undertake a range of industry tasks, from clearance, trenching and construction to concrete mattress recovery, subsea demolition and decommissioning. Crawford explains that his approach is grounded by experience in the salvage market: “We’ve got to cover the whole project and have to be able to try and do as many jobs as possible, as cost-effectively as possible… So we saw the opportunity in the industry, and particularly decommissioning as an inroad into the oil and gas market, in terms of providing new technology.” The right tools for the job The Utility ROV unit itself (UTROV) is essentially a subsea tool carrier. Its primary functions are to transfer the lift capacity of its umbilical winch and to provide common connections for the electrics, hydraulics and comms of the various tools. The system is controlled via a mobile control system housed in a 10-ft (3-metre) shipping container, or in an alternative location if space is tight. At roughly six cubic metres, its footprint NEWSBASE

remains fairly small. The 2.6 tonne unit is suspended by the umbilical, but also has 4 vectored thrusters which allow it to move in a 15-metre radius when subsea, dependent on water depth. It is rated for work at depths of up to 3,000 metres – though it can work deeper if its lights and camera are changed. A 35 tonne A-frame winch mounted at the stern of the vessel is used to deploy and recover the UT ROV. The system will work in a 3-metre swell and in currents of up to 3 knots, as tension controls on the winch mean it will heave and render automatically to keep the unit steady whilst subsurface. This unit provides a base for a range of tools to be deployed. The bulk of UT ROV tools are comprised of 3 modified grabs from land-based excavator systems. Their use onshore means they have been extensively tried and tested, and are up to the task of working in the harsh subsea environment. The Tine Grab is a general-purpose grab to handle any material. Sets of legs are available with or without orange peel. Previous deployments have seen this used for wreck demolition and material recovery. The Clam Shell Grab is used for bulk material handling, and is available with or without teeth for use with denser materials. Meanwhile, the Shear Grab is a dedicated to subsea demolition, and is ideal for dismantling structures and/or cutting pipelines. It is deployable in two frames: one is remotely movable between vertical and horizontal positions, while another is fixed on its side for use in cutting vertical structures. The MFE, or mass-flow excavation tool, was developed by the team to perform noncontact dredging. The max 250-RPM unit offers an efficient method of clearing and removing sediment from subsea structures without damaging them – a task the salvage team is well-versed in. Owing to the large hydraulic flow needed to operate, traditional MFEs are often powered directly from the surface. The distance between the two often results in a loss of power in the hydraulic hoses, all of which makes for an inefficient system unsuitable for use in deeper water. The inbuilt hydraulic power of the UTROV solves

September 2015

InnovOil

The MFE rises from the deep

this problem since the power is at source Heavy duty lighting and camera mountings are fitted onto each of the tools as well as the UTROV, giving the operator specific and general views to carry out his work safely and effectively. On deck, the system is stored and transported in several containers which also house the control system, power and workshop. These are can be easily moved by road or air, before being loaded onto a suitable vessel of opportunity and configured as required. Plus shipping Unsurprisingly, the team has had a busy year. An agreement made early in 2015 saw a joint venture between the company and Fletcher Shipping to install a system permanently on one of the latter’s vessels. The FS Pegasus, an 84-metre, Ulsteinbuilt 745 platform supply vessel (PSV), is now fitted with a full UT ROV system. Owing to the small footprint of the UT ROV and the high loading capacity of the deck, the vessel is a versatile platform for subsea work – and at a much lower per-day cost than other options. “If you look at the costs of a project,” Crawford says, “It’s all vessel costs. Using an offshore construction vessel or a dive support vessel will incur a day rate

somewhere in the region of six times higher than that of a PSV. The UTROV system exploits this and capitalises upon the lower cost vessel.” The deck features a single deck crane for use with the UT ROV, as well as two 10 tonne tugger winches and the ship’s 2 tonne crane. Additional deck cranes can then be fitted as required –the FS Pegasus has the capability to deploy a full campaign of 300 subsea mattresses without returning to port, thanks to a configuration of lifting frames. Carrying all the necessary UT ROV tools in the one vessel also means projects can often be completed in one trip. In addition to the vessel’s crew, 14 berths are available to house client staff, survey teams. The vessel choice and the capabilities of the UT ROV tools are all about providing the most flexibility at a competitive price – and this requires a holistic approach to the tasks in hand. “It’s about looking at the whole system, not individual aspects of it – and that’s how you reduce costs,” Crawford says. “If you don’t understand the whole system, you generate a problem by using the component which might be the best component on an isolated basis but isn’t the best for the whole system.” Future plans Forging links with other innovators has been NEWSBASE

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key to Crawford’s strategy, and the expertise and help of companies like Fletcher Shipping “have been a big support,” he says. But in what has already been a busy year, Utility ROV Services still has new avenues – business and technological – to explore. “I designed a mattress recovery system which we’re going to start building and testing just as soon as I get this first contract under my belt and under way,” he enthuses. A recent salvage operation offshore Ireland also gave the team cause for some unexpected innovation. Owing to “some pretty terrible weather and some pretty bad luck” the umbilical was snagged and severed while working, leaving the UTROV and one of the tools inside the wreck. Despite the setback and a hurried trip back to their Fife base: “In 4 days we designed, built and got working a whole new system” capable of retrieving the lost equipment, he says. Deploying it within a matter of days, not only was the tool recovered, but Crawford and his team had also engineered “a brand new bit of kit.” This spirit of innovation runs through the now 12-strong company, but is always balanced with the cost-conscious view of a salvage outfit. Future changes to the equipment may even see some pieces of equipment scaled down, enabling the UTROV to be more agile and responsive to particular tasks. “I personally think we’ve way over-spec’d the machine we have for the operations we are currently tendering for,” he suggests. “By using smaller vessels, we can offer again a cost saving to the end user – because ultimately for shifting rocks, you don’t need a machine like we have.” From here, the company has the enviable position of being almost too busy to cope with interest. The next year will see new equipment built and more opportunities to prove the system’s capability to the various sectors of the offshore industry. “We want to show that this method works and that it’s cost-effective and productive,” Crawford says. n Contact: Craig Roberts Tel: +44 (0) 1592 773 344 Email: enquiries@utrov.com Web: www.utrov.com

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InnovOil

September 2015

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Oilfield Chemicals Special supplement Pages 9-21

Cleaning up chemistry

Oilfield chemists tackle complex completions, sustainable innovations and ecotoxicity

Challenges and responsibility Dr Henry Craddock chats ahead of the RSCâ&#x20AC;&#x2122;s oilfield chemistry event Page 10

The power of Neptune

TETRA Technologiesâ&#x20AC;&#x2122; CS Neptune completion fluid Page 14

NEWSBASE

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InnovOil

September 2015

The chemical challenge OILFIElD CHEMISTRY EDITION

Dr Henry Craddock discusses new chemistry and new responsibilities ahead of the RSC’s Chemistry in the Oil Industry conference

“I

limits of chemistry, are more static than n any market like this when it others. Biocides, Craddock highlights, goes from bullish to bearish, the are dominated by two main groups: question is: ‘Can you play in glutaraldehyde-based products or tetrakis it?’” Dr Henry Craddock posits hydroxymethyl phosphonium sulphatea question facing almost every part in based (THPS) products, both of which the industry, and none more so than the have remained relatively unchanged. suppliers and innovators of the oilfield Similarly, surfactant chemistry, while chemistry sector. Yet changing priorities important for EOR and many other and more stringent environmental applications, is not “new,” with most of its legislation are presenting chemists with constituent chemicals having been used for as many opportunities to develop new decades in various forms. solutions as challenges to overcome. The exception is polymers, afforded This is not without its own hurdles. “I extra room for experimentation owing wouldn’t say there’s no new chemistry, but to the regulations regarding it’s quite difficult to bring in monomer use. Using new chemistry for a variety multiple monomers means of reasons,” Craddock polymer development, for continues. “That doesn’t waterflood efficiency or EOR mean there are not new and for example, is easier than clever applications.” in other areas of research, With 25 years’ experience allowing companies a little in the oilfield chemistry more room to “play with the sector, he has presided over chemistry set,” as he puts it. the creation of a few of Yet advances in these. As a Fellow of the deployment mean the Royal Society of Chemistry chemistry remains innovative. (RSC), and a member of its Dr Henry Craddock, “There’s a lot of bespoke-ness, Speciality Chemicals Sector, Fellow of the Royal particularly in drilling and he also plays a key role in Society of Chemistry production, even down to the organising and overseeing (RSC) well-level. So there’s a drive to its biennial Chemistry in the be clever about application,” he says. Oil Industry symposium. This year’s focus An increasingly tailored approach is “Challenges and Responsibilities” and has actually meant that some chemical incorporates the aforementioned issues of applications have undergone major innovation and reducing environmental advances in recent years. Scale inhibitors, impact as well as other areas such as flow one of the most common areas of assurance and enhanced oil recovery new chemistry, have seen a wealth of (EOR). improvements in effectiveness and accuracy. “You can [now] put a scale Pushing the limits inhibitor at a certain point within the Some areas, owing to regulation or the NEWSBASE

wellbore and have it last for a year or more – that has serious implications for protection from scaling issues through the system,” Craddock explains. How these are deployed has also come on leaps and bounds. “Rather than having to inject further upstream, you can inject at the wellhead where you need it and then all the way down to the separators and into production processing, as well as protecting in the near wellbore, so the water coming through in the production stream is protected as well,” he continues. Scale inhibition by “squeezing” – pumping and placing an inhibitor by injecting it into a formation – in particular has improved dramatically during his career, becoming “much more sensitive, much more accurate and much more defined.” Monitoring developments From the user’s end, monitoring chemical displacement and effectiveness is also

September 2015

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OILFIElD CHEMISTRY EDITION The AQSENS™ unit combines a microfluidic chip and spectroscopy technology, and is aimed at providing comprehensive analysis of fluid and chemical samples at the touch of a button

a challenge. In particular, being able to take the tools needed for chemical analysis offshore has proved one area of innovation. Dr Craddock has been involved in tackling the issue through his consultancy HC Oilfield & Chemical, working on a recent project in Finland – AQSENS™ – which combines chemistry with biotech and IT. With a launch planned for this year, he is excited about its potential. The unit combines a microfluidic chip and spectroscopy technology, and is aimed at providing comprehensive analysis of fluid and chemical samples at the touch of a button. “[The company’s] goal is to have a water sample and be able to tell you everything about it with the one analysis. It’s a bit Star Trek-y, but it’s a laudable objective,” he enthuses. Successfully implementing the technology could dramatically reduce the time, effort and costs of testing and sampling chemical performance in the

field. Traditionally this “is difficult to do offshore, and can be very unreliable,” he continues. Whereas currently samples are transported onshore – for which they have to be treated, bringing added uncertainty – the savings inherent in being able to confirm and identify the presence of chemicals there and then are significant. He also draws attention to similar projects undertaken by NALCO Champion and LUX Assure. A venture by the latter involves using colourmetric technology to examine small organic molecules such as methanol and monoethylene glycol. It highlights the fact that, in many cases, it is the chemical manufacturers and suppliers leading the way in terms of R&D, rather than the more diverse operators and service companies. “I think the oil companies don’t see it as a core piece of R&D for themselves, but others do and have capabilities in terms of bringing the expertise of one industry into NEWSBASE

another,” Craddock posits.” Yet it has been advances in chemical understanding which have unlocked major developments. He cites BP’s pioneering work with low-dose kinetic hydrate inhibitors (LDHIs) in the 1990s – a sector we examined in InnovOil Issue 27 last year – sparked from the observation that the blood of arctic fish does not freeze. The result was “some reasonably innovative chemistry,” producing polymers which could be used as LDHIs. This also had an effect in terms of the future of the company’s projects. “I think, from the point of view of BP, [this] changed some of the developments they had in process, in terms of making them more viable or helping them become more safe because they then didn’t need to use large volumes of methanol,” Dr Craddock adds. The scale of shale In Europe, shale development had been touted as the oil industry’s next great

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InnovOil

September 2015

OILFIElD CHEMISTRY EDITION Chemical innovations are becoming increasingly controlled by environmental legislation

venture. But while evaluations and exploratory drilling are ongoing, today’s policy, regulatory and media environment suggest it will not be the energy revolution many had hoped for. Furthermore, while the US offers helpful analogues, key variables such as the well depth, pressures and temperatures of European plays mean that the production chemicals required will also be subject to different criteria. Likewise for chemical providers, Craddock says, European regulations are likely to prove much stricter than in the US. “It’s much more defined and it’s much more transparent, but it’s also much more demanding on chemical suppliers to meet the criteria,” he says. “And I think a lot of that [regulation] will be around potential water contamination.” But the need to recycle water in frac jobs – or to avoid using it altogether – has led to some interesting chemical applications too. Foam fracturing, for example, could be a viable alternative in areas with sensitive or insufficient supplies. In some cases, it can also carry proppant further through the formation than other solutions. Fundamentals to the future Moving beyond the near-term debate

around shale, Dr Craddock believes that chemical applications will play an even more vital role in the fields of the future. Soon, more explorers will turn their attention to harder-to-reach deposits of heavier, denser hydrocarbons. Waxy crudes in particular are difficult to move, store and treat, and traditionally this is thought of as an engineering challenge. But whereas engineering tasks such as heated pipelines require even more energy, Craddock thinks chemistry could play an important role in making these projects more feasible and more efficient. This is where the whole industry must begin to look in the longer term, and work to fill some of its knowledge gaps. “There’s a lot of fundamental work missing in understanding paraffin deposition. If you compare it to looking at asphaltenes, there is a huge amount of understanding about them, but with organic crystallisation… the fundamental understandings there need work. And it needs a lot more focus, because that’s where we will be going.” This “blue sky” work on the fundamentals of complex chemistry is where the RSC steps in. The upcoming symposium offers a chance for the leading oilfield chemists to meet, present and share expertise. It is also a chance for NEWSBASE

oil companies to become more aware of the applications and to get involved in interesting projects. Ultimately, Craddock and the organising committee want to see innovative, interesting work. “When we’re looking at papers we want chemistry – if we see something that has good chemistry or technology behind it, and looks interesting, we’ll give it a platform.” Chemical innovation – like most industry subsectors – is not immune to the pressures of oil prices, but it is one area which certainly deserves more attention than it is often given. Whether using chemistry to understand the basic mechanics of hydrocarbon behaviour better, or to unlock game-changing technological developments, it should not be ignored. “There are probably three hurdles in terms of new technology in the oil and gas industry, and regulation and economics are to the fore,” Craddock concludes. “Third is its reluctance to be adventurous.” n The RSC’s Chemistry in the Oil Industry XIV event will be held on November 2-4 at the Hilton Manchester Deansgate Hotel, Manchester UK. For more information, click here.

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September 2015

Going ultra-deep with innovations from TETRA OILFIElD CHEMISTRY EDITION

TETRA Technologies has new, innovative and high-performance completion fluids to meet the needs of ultra-deepwater completions

oday’s well completions present a unique set of challenges. As operators move to more remote locations, logistical issues, high pressure-high temperature (HPHT) wells, complex subsea and wellbore conditions have spurred demand for new and innovative technologies. More than ever, producers want to reduce risk, increase completion efficiencies and maximise production – all of which must be done at a lower cost. Environmentally Friendly HPHT completion fluids TETRA CS NeptuneTM is a new innovative, high-density completion fluid, free of solids, zinc and formates. CS Neptune has been specifically developed for deepwater and complex high-pressure wells that require heavy clear brine solutions to control well pressure during the completion phase. TETRA CS Neptune addresses the environmental challenges facing offshore oil producers seeking an alternative to zinc brines, which are classified as “marine pollutants” in the U.S. and have been prohibited from being used in the North Sea since the late 1990s. Caesium formates replaced zinc brines in the North Sea and have continued to be the only viable alternative. TETRA CS Neptune provides another environmentally-friendly and costeffective option that meets requirements for both the Gulf of Mexico and North Sea, as well as for use in other sensitive environments. TETRA CS Neptune is an engineered solution formulated with renewable chemistry, stable at elevated temperatures and during storage, and mixable with standard clear brine mixing equipment. It’s compatible with elastomers and poses low corrosion risk, performs at low temperatures and high pressures without crystallization, and can also be formulated as a low-solids reservoir drill-in fluid.

Safety first In challenging environments such as HPHT and deepwater wells, the impact on health, safety and the environment (HSE) must be considered when designing completions. The formulation of TETRA CS Neptune can significantly reduce an operator’s risk of environmental damage and personal injury. TETRA CS Neptune delivers excellent HSE test results when compared to conventional fluids. The lower toxicity of the fluid provides for a safer and less restrictive working environment. It meets the demanding environmental standards set forth by many environmental authorities around the world, as well as reducing an operator’s risk of environmental damage and personal injury. In the event of an accidental release or spill, its effects and liability are reduced accordingly. Development The fluid brings together TETRA’s in-depth knowledge of completion fluids, expertise in halide manufacturing and experience in renewable chemistry. TETRA’s Technology Center partnered with a major operator to develop and deploy TETRA CS Neptune in 18 months. As part of the development, the fluid was validated using a rigorous testing programme which included the testing of pressurised crystallisation temperatures NEWSBASE

(PCTs), stress-cracking corrosion (SCC), elastomers, regain perms, and compatibility with multiple fluid types (mud, control line, spacer, frac fluids, gases and chemical additives). This effort required more than 50 separate tests and 250 testing scenarios, at a cost of more than US$1.5 million. Delivering results The first application of TETRA CS Neptune was for a Gulf of Mexico operator on an ultra-deepwater completion. The job required a 14.5 pound per gallon (ppg) completion brine, for use at a well depth of over 30,000 feet (9,150 m), in a water depth over 7,200 feet (2,200 m) and a seabed temperature of 39°F (3.8°C). The lower completions were installed successfully, with TETRA CS Neptune performing as designed. The fluid performed as designed after a 15,000-psi BOP test, encountering no issues with true crystallisation temperature (TCT) or PCT throughout the well. The fluid displayed no compatibility issues with loss circulation material (LCM) and polymers, and the synthetic oil-based mud (SOBM) was displaced without any fluid property deterioration. The fluid was tolerant to low levels of sea water contamination, with fluid clarity equal to that of a standard brine, staying at a nephelometric turbidity unit (NTUs) measurement below 5.

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OILFIElD CHEMISTRY EDITION SafeDEflo UDW filtration

TETRA CS Neptune Features • Zinc-free and hence does not require zero-discharge system of work • Environmental acceptability • Formulated from renewable products, ensuring continuity of supply • Neutral pH - poses low health and safety risks to rig site and plant personnel • Significantly lower unit cost than alternative fluid chemistries • Requires no special mixing, handling, or storage equipment at the rig site • Can be formulated as a low solids, reservoir drill-in fluid • Can be reclaimed for reuse, using standard technology. Benefits • Can be formulated to a density of up to 15.4 ppg, 1.85 g/ml (efforts are underway to extend the limits) • Exhibits significantly lower crystallisation temperatures (TCT & PCT) than equivalent density calcium bromide brines • Stable at elevated temperatures and during storage • Can be mixed with standard CBF mixing equipment • Compatible with downhole elastomers and metallurgies • Exhibits compatibility similar to that of calcium bromide with other working and reservoir fluids

SafeDEflo UDW filtration Filtration often goes hand-in-hand with clear brine fluids (CBFs) and TETRA has the expertise, equipment, and engineering and operations team available to handle any operator’s filtration needs. The added benefit with TETRA is that it has an in-depth understanding of the nature and characteristics of the fluids being filtered. SafeDeflo® ultra deepwater (UDW)

Filtration System is a high flow-rate, largecapacity plate and frame filtration system with a comparatively small footprint. The unique design of the SafeDEflo UDW Filtration System includes diatomaceous earth (DE) filtration technology – a porous siliceous sediment made from diatoms – to keep pace with the challenges presented by the UDW environment. The UDW filtration system offers 30% more filter area in the same footprint as conventional 1,600-square foot (149-square metre) filter presses, with a design capability to handle twice the conventional flow rate – a sustained circulation of around 30-50 barrels per minute. As well as being stackable, the system can filter around 5,000 barrels of surface volume without any interruption to service. The system allows the effective filtration of CBFs with densities ranging from 8.3 lbs per gallon to 18 lbs per gallon. SafeDEflo UDW Filtration System Benefits • Rig time savings • Enhanced filtration performance • Longer sustained run times • Efficient, environmentally friendly, safety-enhancing de delivery

Delivering results Working for an operator in the Gulf of Mexico, TETRA designed and planned an effective displacement of 13.4 ppg synthetic oil-based mud with 13.4 ppg completion brine from a well of over 13,000 feet (4,000 NEWSBASE

metres), at a water depth of 3,500 feet (1,000 metres). The operator’s targeted specifications included end-results of less than 50 or 20 NTUs above the baseline, and a 0.02% solids content. TETRA’s SafeDEflow UDW System was paired with a 1,500-square foot (140-square metre) unit in order to deliver the required flow rate, capacity and continuous filtration throughout the project. The solution was able to slash the expected time for displacement and final clean-up by almost 60%, coming in at 20 hours rather than 48 hours and exceeding all expectations for the displacement. The reduction in time resulted in a cost savings of over US$1 million for the customer. TETRA CS Neptune fluids and the SafeDEflo UDW Filtration System are excellent examples of how the company delivers innovative solutions to help its customers gain a competitive advantage. Headquartered in the Woodlands, TX, TETRA operates globally, focused on production testing, fluids, offshore and compression, and has been serving the oilfield industry for nearly 35 years, and has a reputation for delivering quality products and superior services. n Contact:

Barry Donaldson, Vice President Sales and Marketing Tel: 1.281.364.2254 Email: bdonaldson@tetratec.com Web: www.tetratec.com

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September 2015

OILFIElD CHEMISTRY EDITION

Clariant fosters innovation

A recently acquired contract and newly developed flowback aid highlight Clariant Oil Services’ history of nurturing innovation and sustainability

he global, Houston-based provider of chemical products and services has a long history of pushing the boundaries and stretching limits when it comes to new technologies, and is well-known for developing state-of-the-art products with an emphasis on continuous improvement and sustainability. “We are guided by the needs of our customers as we develop ecologically sustainable products and mechanisms to help optimize each stage of the oil and gas life cycle,” Doug Hayes, Head of Clariant Oil Services recently told the company’s annual publication, The Innovator. Clariant’s commitment to innovation can be seen in both the products it offers and the processes in place which enable these products to be developed. Clariant’s Centers of Excellence are hubs for the development and enhancement of specialty oilfield chemicals. Clariant Oil Services Gulf of Mexico Center of Excellence in Houston, Texas, features robust capabilities encompassing deepwater, flow assurance, integrity management and well service additives, as well as pipeline cleaning and chemical solutions. The recently-opened 100 million euro Clariant Innovation Center in Frankfurt, Germany, which serves as the corporation’s global research and development hub, provides a broad range of research and testing services and is structured within Clariant Corporation’s ambitious R&D program. Clariant’s commitment to continuous improvement can be seen in the company’s dedication to acting sustainably, which CEO Hariolf Kottmann calls an “integral part of [Clariant’s] corporate strategy.” Clariant has been listed as a member of the Global Dow Jones Sustainability Index since 2014; out of the 2,500 companies listed on the Dow Jones Global Stock Market Index, only the top 10% of the most efficient companies in the areas of economic, environmental, and social responsibilities are listed. Additionally, the company has a dedicated Sustainability Council devoted to these efforts.

“This long-term contract, especially with the highly contested bid process, shows the confidence Statoil has in Clariant’s capabilities to provide supply of innovative chemicals and services to meet their needs,” Bekkestad says. The agreement, which Bekkestad notes will “continue to strengthen Clariant Oil Services’ position as a major supplier in the oil production chemicals market in the North Sea,” places Clariant at the forefront of the largest offshore oil find in the Norwegian continental shelf in 30 years. The field is estimated to hold between 1.7 and 3.0 billion barrels of oil equivalents and is expected to produce 550,000 to 650,000 barrels of oil per day when fully developed.

Such investments, coupled with the strive to push past technological limits, set Clariant apart from the competition, and enable the company to provide sustainable solutions worldwide. Johan Sverdrup To be truly effective, a company must go beyond state-of-the-art facilities and programs. Performance must be proven through long-term stability, both in the field and through continuous relationships with clients. In these aspects, Clariant shows a proven ability, building teams from the ground-up with a focus on cultivating long-term innovation projects and creating substantial client relationships. Most recently, Clariant signed a framework contract with Statoil to supply production chemicals and services for the Johan Sverdrup oilfield for eight years, with a four-year extension option. According to Frode Bekkestad, Managing Director of Clariant Oil Services Scandinavia, the agreement will provide the “foundation for a long-term, successful relationship” between Clariant and Statoil, “with the goal of delivering enhanced performance over the full term of the contract.” NEWSBASE

Higher yields with HOSTAFRAC® SF A complete provider for the entire oil and gas value chain, Clariant Oil Services develops products designed to maximise oil and gas production. Clariant’s newly developed product, the flowback aid, HOSTAFRAC SF, is just one more example of the company’s dedication to innovation, with an emphasis on enhancing the profitability of fields with concern for the environment. A chemical additive designed to produce a higher proportion of fracturing fluids and, subsequently, a higher oil and gas yield, HOSTAFRAC SF is a uniquely composed system of surfactants, including sustainably sourced sugar-based amides, a solvent, and co-solvent. These components form an advanced innovative technology system which enables the faster and more efficient return of fracture fluid, and enhances the production of hydrocarbon-containing fluids in fractured tight subterranean formations. According to Dr. Jonathan J. Wylde, Global Head of Innovation for Clariant Oil Services, the newly developed additive will enhance both operation productivity and sustainability. “HOSTAFRAC SF is one of a series of high performance and environmentallyacceptable surfactant packages,” he says. “The notion of using sustainably sourced sugar to make chemicals is not new, but using it in an advanced delivery system

September 2015

InnovOil OILFIElD CHEMISTRY EDITION

and in hydraulic fracturing operations is state-of-the-art. This development has and will continue to truly make a difference to our customers operations by delivering high performance chemistry, while at the same time improving the environmental profile of their operations.” The major advantage of HOSTAFRAC SF is its ability to reduce both the surface tension and interface tension of fracturing fluids, ensuring that water can flow out of the channels more effectively. Additionally, HOSTAFRAC SF provides a dramatic increase in flowback of the hydraulic fracturing fluid used; using the additive, 87% of the fluid can be recovered, as compared to 13-22% without. The decreased surface and interfacial tension also decreases the likelihood of formation damage and allows oil to be flushed discretely away by the low surface tension fluid. The fluid pumped out of the reservoir can then be recycled and reused, reducing water consumption and increasing the oil and gas quantities that can be extracted from the reservoir. HOSTAFRAC SF is distributed worldwide. Enhancing Field Profitability while Protecting the Environment In-line with the company’s goals of continuous improvement and excellence for both customers and the environment, Clariant created the EcoTain® label, which represents sustainability efforts at a product level. As part of the EcoTain label, HOSTAFRAC SF has undergone a systematic, in-depth screening process using 36 criteria in all three sustainability dimensions: social, environmental and economic. EcoTain products significantly exceed sustainability market standards, have best-in-class performance, and contribute overall to the sustainability efforts of the company. n Contact:

John Schulte Tel: +1 281 296 3244 Email: john.schulte@clariant.com Web: www.clariant.com

NEWSBASE

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September 2015

OILFIElD CHEMISTRY EDITION

The oilfield’s chemical future Chemical innovator

OILFIElD CHEMISTRY EDIT

Corrosion inhibitor added

@22h, H2S added

Blank Corrosion Rate (mm/yr)

“T

he future of the oilfield industry is clear,” says AkzoNobel’s global oilfield marketing manager, Jeroen Pul. “All the players in the value chain must become more sustainable in order to maintain a licence to operate – quite literally in the case of companies operating in the North Sea.” Regulations for operators in environmentally sensitive areas are becoming continuously and increasingly stringent. Rules and standards which have been set in areas such as the North Sea are also beginning to be taken further afield – and countries such as Angola are now starting to work on legal frameworks which would force the oil industry to become more sustainable if they want to “play ball.” As a chemistry solutions supplier to oil service companies around the world, AkzoNobel plays only a small role in the process, early on in the supply chain. Yet, it places a strong emphasis on the importance of sustainability within that entire chain. “We do play a very crucial role,” he continues, “Because if the downstream value chain is not sustainable it will affect the end product.” The company’s approach – which includes a target to make 20% of its revenue from products that are more sustainable for its customers than those of the competition by 2020 – has won accolades, including the top spot in the Dow Jones Sustainability Index for three consecutive years. By developing and manufacturing more innovative chemistries that are made from renewable raw materials and which can be safely disposed of at the end of the lifecycle, AkzoNobel’s customers can also make more sustainable end-market solutions. “So we all have to become more sustainable,” Pul says. “But in the end of the day what pays the bills for our service company customers is their productivity. Because you can have the

@22h, H2S added

@12h, + 10 ppm for TOFA imidazoline

Corrosion Rate (mm/yr)

AkzoNobel offers its view of oilfield chemistry for the 21st century

10 Corrosion inhibitor added

@12h, + 10 ppm for TOFA imidazoline

Blank Armohib CI-5150, 10 ppm

Armohib CI-5150, 10 ppm TOFA imidazoline, 10-20 ppm

TOFA imidazoline, 10-20 ppm 98,3% protection 98,3% protection 0.1

0.1

0.01 0

Conditions : RCE, 30 Pa wall shear stress Conditions : +60ºC RCE, 30 Pa wall shear stress Brine only (3% NaCl); +60ºC Concentrations refers to active CI added Brine only (3% NaCl); Concentrations refers to active10CI added 5 5

99.2% protection 99.2% protection

Time (h) 15 Time (h)

most environmentally friendly chemistry formulations in the world, but if they don’t get the job done they add no value.” Added value please! AkzoNobel’s value proposition to its oilfield customers lies in helping them consistently deliver world-class productivity. Its solutions aim to offer the performance required for increasingly demanding market and operating conditions, but also to reduce the environmental impact of oilfield operations. “Specifically, we aim to improve the ecotoxicity of chemistries used in the market today with more benign materials and continuously improve our current portfolio with more environmentally friendly versions of products with equal or better performance,” he explains. Armohib CI-5150 is a corrosion inhibitor engineered specifically for use in the oilfield. Based on alkyl polyquaternary amine chemistry, Armohib’s film-forming polymeric structure is positively charged at multiple points in the polymer chain, which it believes makes for better adhesion to metal surfaces, and greater film integrity under a range of operating conditions. This makes it ideal for deployment to prevent sweet corrosion – metal deterioration by carbon dioxide and moisture – in pipelines, and in severe brine NEWSBASE

20 20

Figure 1

environments. This same stability in brine also makes it versatile; it can be used not only for production chemistry, but in drilling and completion fluid formulations too. And herein is the crux. Armohib CI-5150 is formulated to meet important environmental toxicity regulations, but without compromising on performance of “original” chemistries – Figure 1 shows the newest generation with a clear advantage when compared with previous corrosion inhibitors based on Imidazoline chemistry (see graph above). “It’s also easy to formulate,” says AkzoNobel’s Regional Sales Manager Oilfield, Adrian Zuberbühler, “Taking headaches away from our customers while blending.” Separation anxiety The crude separation process remains another challenge to service companies and operators. The nature of demulsifying chemicals – which usually include polymeric materials – can mean that biodegradability is an issue. AkzoNobel has taken a new approach with cleavable surfactant technology, which breaks down the molecule’s ester links, whilst degrading. Interestingly, the technology originally derives from the fabric and homecare industry, where weak links are built into

September 2015

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OILFIElD CHEMISTRY EDITION

TION

Witbreak GT for crude separation surfactants in order to prolong the release of “fresh” or “clean” odours. The principal mechanism was then incorporated into the development of its new sustainable demulsifiers, as well as preserving the high-performance and low-dosage rates of traditional products on the market. It was also important to resolve the builtin conflict between high molecular weight which contributes to a low aquatoxicity, but often results in poor biodegradability. Having solved these issues, the company has recently launched its newest demulsifiers, the Witbreak GT range. These show 20-60% biodegradability in 28 days (tested to OECD 306) and meet aquatic toxicity regulations, such as tox marine algae (EC 50) in concentrations > 100 mg/l. (see separation image above). Owing to the high degree of versatility these “Orthoesters” offer, it expects further products to be launched in the future, including the option for AkzoNobel to formulate new, tailor-made products for its customers. The Ecotox hurdle “A current challenge in using surfactants in the North Sea is the use of the traditional non-ionic surfactants in applications such as rig cleaners and casing cleaners,” Zuberbühler says. Some of the more commonly used synthetic alcohol

ethoxylates are on the verge of being banned as a result of their aquatoxic properties. Replacing them with safer products with equal performance is one of the chemical sector’s biggest challenges. In response, AkzoNobel developed the Armoclean range. “The tuned Armoclean alcohol ethoxylates outperform traditional non-ionic surfactants and show a 10 times better aquatoxic profile,” he enthuses. The Armoclean range consists of nonionic surfactants, as well as a number of alkylglucosides. “The favourable ecotoxic profile of alkylglucosides is well-known, but the trick is in the right use,” Zuberbühler explains, “So we work closely together with our customers to help them find and formulate the best solutions in order to get the features of the final product right.” Often traditional hydrotopes are highfoaming, presenting problems when using such surfactants. Products like Armoclean 6000 and Armoclean 6040 are low-foam alkylglucosides, with excellent hydrotroping properties. Using these formulations as hydrotopes/co-surfactants increases the temperature and brine stability of the overall formulation. What’s next? There are many chemistry related challenges facing oil service companies today – and there are inevitably many more NEWSBASE

ahead. AkzoNobel is already developing sustainable chemical solutions with environmental benefits to address wax build-up, as well as problems related to asphaltenes and hydrates, all of which are areas in need of new innovation. But with regulations becoming stricter, and a global push to develop oilfields that are more difficult to reach and demand unconventional approaches to develop, chemistry companies have once again the opportunity to lead from the front and be part of the solution. “Our portfolio of products allows our customers to select the solution that best fits their specific needs in any particular oilfield application. In addition, we have a long track record of partnering with our customers to work on exclusive innovations for specific challenges,” says Zuberbühler. AkzoNobel has global experience and the expertise to enhance the oilfield industry’s production, drilling and stimulation processes – using chemistry solutions that don’t compensate performance for sustainability. n Contact:

Adrian Zuberbühler, Regional Sales Manager Oilfield EMEIA Tel: +41 41 469 6948 Email: adrian.zuberbuehler@akzonobel.com Web: www.akzonobel.com/oilfield

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September 2015

OILFIElD CHEMISTRY EDITION

Drilling deeper, going greener SIPDRILL base oils from speciality oil and fluid marketer SIP are helping the industry move to new frontiers

IP is an independent marketer of speciality oils and fluids and has supplied the global oil and gas industry for over 20 years. With a particular focus on offshore exploration and the drilling sector, its products are used in Europe, Africa and the Middle East. It markets, supplies and blends an extensive range of base oils for formulating fluids used in international offshore drilling and production operations. These include low-viscosity and sheen-free base oils with trace aromatic levels, high flash points and low pour points – all of which have very low toxicity to marine life. A focus on innovation and the state of technological advancement is key to SIP’s approach to product development.

As operators move to new frontiers and more challenging production profiles, their needs have changed, leading SIP to develop low-viscosity, SIPDRILL base oils – specifically for deep water, high-pressure high-temperature (HPHT) and horizontal drilling operations. The SIPDRILL range are known for their very low aquatic toxicity, rapid biodegradation and zero bioaccumulation. With low intrinsic viscosity, tight distillation range and relatively low final distillation point, these oils will not thermally crack and are easily stripped from drilled cuttings via mechanical or thermal recovery units – requiring far less energy than higher viscosity, higher-density fluids, and ultimately resulting in lower costs. SIPDRILL base oils are available NEWSBASE

in a range of viscosities from 1.7 to 3.9 centistokes (at 40°C). Depending on the nature of the oil, they can also be highly biodegradable, with purity certified to meet the US FDA 21 CFR 178.3620 (b) standard for incidental food contact products. As a member of the European Oilfield Speciality Chemicals Association (EOSCA), SIP is now working in close collaboration with various partners to develop a range of synthetic biodegradable fluids from 100% renewable and fully sustainable feed stocks. n Contact:

Glen Cockroft Tel: +44 (0) 20 7717 0100 Email: enquiries@sip.com Web: www.sip.com

September 2015

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OILFIElD CHEMISTRY EDITIONw

The power of Zero

U.S. Water has recently launched PhosZero™, a corrosion and scale inhibitor without the aquatic toxicity concerns of older technologies

n anticipation of the tightening restrictions on phosphorus, and many of the metal-bearing compounds currently used in industrial cooling treatment, water management expert U.S. Water has developed a “green” corrosion and scale inhibition technology. This contains no phosphorus, and provides corrosion and scale control performance at least equivalent to traditional cooling water treatment. The recently launched PhosZero™ with E-FeX™ Technology is a new step in sustainable chemistry for cooling water treatment. U.S. Water’s latest generation of PhosZero contains E-FeX™ Technology, a synergistic blend of ingredients that replaces the most common uses of phosphorus in cooling water applications. The PhosZero family of cooling water treatment products are designed to provide both scale and corrosion control, similar

to “traditional” phosphorus-containing chemistries, but without the discharge or aquatic toxicity concerns of older technologies. The new formulation offers maximum protection against corrosion and scale, ensuring high heat transfer and maximum equipment efficiency. PhosZero also offers greater environmental sustainability via its aquatic toxicity profile, reducing the environmental footprint of operations. By eliminating phosphorus discharge to the environment, PhosZero ensures

NEWSBASE

regulatory compliance and the eradication of costs associated with phosphorus removal from waste streams. Plant safety is also improved, reducing the need for acid use and storage on-site, helping to reduce HazMat reporting, insurance costs and chemical-handling mistakes. n Contact: Jon Amdursky Tel: +1 866 663 7633 Email: jamdursky@aol.com Web: www.uswaterservices.com

Chemistry in the Oil Industry XIV Chemistry: Challenges and Responsibili:es

2nd – 4th November 2015 at the Hilton Manchester Deansgate Hotel, UK Registra:on now open! log onto www.rscspecialitychemicals.org.uk for further details Special Events this year include: Keynote Lectures by Cuadrilla and the Environment Agency

Student Lectures, Posters and Exhibi:on

•

The focus will be on Unconven:onal Resources and New Chemistry to enhance the proﬁtability of new ﬁelds or to extend the economic life of mature wells. The industry’s responsibility to do this safely whilst protec:ng the environment is paramount. •

Geology and Geochemistry

•

Hydraulic Fracturing (new ﬂuid design •  & remedia4on technologies)

New and Green Chemistry

•

Drilling

•

Enhanced Oil Recovery (EOR/IOR)

•

Scale & Corrosion Inhibi4on

•

Regula4on and Economics

Chemistry applied to Unconven4onal Resources

This interna:onal symposium is organised by the Royal Society of Chemistry Speciality Chemicals Sector and the European Oilﬁeld Speciality Chemicals Associa:on

September 2015

InnovOil

Sixth sense

page 23

Distributed Acoustic Sensing from Fotech Solutions is a valuable down-hole sensing tool which can help to improve production efficiency

etter production efficiency relies on having real-time intelligence on well activity. This includes the adoption and deployment of the latest sensing technologies to plan and monitor completion and production activities. One of the key sensing technology breakthroughs that can offer this new level of insight is Distributed Acoustic Sensing (DAS) from Fotech. DAS works by converting a single fibre-optic cable, which runs either in the casing or inside the production tubing, into the equivalent of tens of thousands of highly sensitive individual vibration sensors. By detecting vibrations in this noise “backscatter,” caused by acoustic disturbances at each point along the fibre, engineers can “visualise” and record what is going on down-hole at every point of the well, in real time. These acoustic disturbances can be caused by everything from complications in a completion process to changes in flow dynamics. By adding a new dimension of knowledge to the extraction process, DAS gives engineers more clarity that ever before. Unconventional challenges These challenges are perhaps most prominent in unconventional plays: during the fracturing procedure, operators have limited visibility of the process. By providing a real-time log of the operation, DAS can provide oversight of the fundamental processes, such as ensuring that the perforation gun fires as expected, that the packer is set properly and that the frac ball is seated correctly. DAS also gives far more sophisticated insight during the operation to help engineers to optimise the frac fully. With an accuracy of 1-2 metres, DAS can not only assure engineers that the process is being carried out safely and efficiently, but also confirm if there are any down-hole events that need to be addressed. For example, DAS can help engineers see where integrity issues are causing crossstage communication issues, opening up previously fracked stages to frac fluid and

DAS technology in action

potentially wasting significant amounts of resource. This could be the result of a breakdown in cement integrity, or a ballfailure event in a slide-and-sleeve operation. Although the impact on the operation will depend on the severity of the integrity issue, it is obviously not desirable to be wasting water and proppant on stages that have already been fracked. DAS can alert engineers as soon as these cross-stage communication issues occur, enabling them to adapt immediately and maintain an effective operation. The right combination DAS is capable of being deployed at new wells and retrofitted to existing wells. As well as the advantages in fracturing, the technology can also enhance a range NEWSBASE

of other down-hole operations such as borehole seismic, gas lift, flood front monitoring and well integrity monitoring. That said, DAS is not a replacement for existing monitoring tools. In fact, the sensor is most successful when used in conjunction with other technologies such as in combination with a DTS system to give a multi-dimensional and dynamic profile of well conditions. Ultimately, the additional information that DAS can deliver is vital to removing the “guesswork” from down-hole activities. By providing accurate intelligence to well operators, DAS delivers a valuable insight into both completion and production issues and can be used to maximise operational efficiencies, increase safety and enhance real-time decision-making. n

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September 2015

Miraah, haariM

GlassPoint Solar’s Miraah EOR project in Oman is set to be the largest of its kind in the world. InnovOil caught up with the company to discuss its plans for the future

y all accounts, GlassPoint Solar is an unusual renewable energy developer. The company sits with one foot firmly in the solar energy sector and another in the tricky business of enhanced oil recovery (EOR). “I’m quite certain that we’re the only solar company in the world that employs petroleum engineers and does reservoir simulation,” vice president of business development John O’Donnell quipped in conversation with InnovOil earlier this month. GlassPoint’s proposition has been well covered in recent years. The Californiabased company uses concentrated solar power (CSP) to generate steam for thermal EOR. Thin curved mirrors, protected under glasshouses, track the sun throughout the day and use its rays to boil water. The resulting steam is then injected into the reservoir to raise the permeability and lower the viscosity of heavy crude. Despite ample sunshine, much of the Middle East has lagged in terms of solar power development, mainly thanks to the availability of enormous hydrocarbon resources. While many have concentrated on harnessing solar photovoltaics (PV) for electricity production, GlassPoint’s industry-focused application of CSP has allowed it to make a beachhead – in both the oil and renewable industries – where others have failed.

As a case in point, it is telling that the company’s latest project – Miraah, a 1,021-MW thermal facility currently under construction at the Amal oilfield – will be the region’s largest solar plant of any kind and one of the world’s largest solar facilities. Full steam ahead Announced in July, the new US$600 million Miraah development follows the success of a 7-MW pilot scheme, also at Amal, and began producing steam in 2013. While very little changes in the deployment of the technology, its footprint is obviously of an entirely different scale. “It’s a little more than 100 times larger than the pilot,” O’Donnell enthused. When complete, it will deliver an average of 6,000 tonnes a day – about 38,000 barrels per day – of steam, throughout the year. Structurally, steam will be delivered from 36 massive greenhouses, built and commissioned in blocks of four. Meaning “mirror” in Arabic, Miraah cements years of co-operation between GlassPoint and Petroleum Development Oman (PDO), the Sultanate’s governmentbacked joint venture with Royal Dutch Shell. Indeed, according to O’Donnell: “When [PDO managing director Raoul Restucci] announced Miraah, he said that in Arabic it means ‘mirror,’ and in Latin it means ‘wonderful.’” NEWSBASE

The willingness of PDO and Shell to look at alternative technologies has been a major factor in getting the project off the ground, not least solar EOR. “We’ve seen international partners bringing technology of many different kinds and Oman has really been a leader in harnessing it,” O’Donnell said. Oman’s quest for invention is driven by necessity. Despite large heavy crude reserves, it lacks the domestic gas supplies necessary to drive large power and EOR projects. Having previously exported gas to Qatar and the UAE via the Dolphin pipeline, Oman saw production fall until pipeline flow was reversed, with supplies now being sourced from Qatar’s worldclass gas deposits. Gas is now imported, with more than 20% of the country’s gas used at the oilfield. It is for this reason that O’Donnell argued: “Solar energy can deliver steam at a significantly lower price point than LNG and also contribute to energy independence and energy security.” According to PDO estimates, Miraah will allow the country to save around 157 million cubic metres of natural gas per year. Neither is there a shortage of demand for more thermal projects. He notes that another operator, Occidental Petroleum (Oxy), “came in very aggressively at the Mukhaizna field and took a field at around

September 2015

8,000 barrels per day and now it’s closer to 150,000 bpd, using a giant steam project.” Such results are impressive, but require massive amounts of capital investment and fuel. Economies of scale Part of the reason solar EOR is deployable at Amal is its remoteness. Located 500 km from the capital Muscat – and “about a 200-mile [320-km] drive from anywhere” – investing in and constructing infrastructure, generation facilities and the fuel supply lines to support them is costly. But the higher CAPEX of a solar project is returned relatively quickly over its lifetime, and acts as a partial hedge against the vicissitudes of the gas spot market. Additionally, the concept is now firmly proven for other potential clients. “The pilot was designed so as to prove everything at scale, so that when [GlassPoint] undertook larger projects, they would be copies of that,” O’Donnell explained. This involved working with equipment and manufacturing suppliers, as well as those in construction and fabrication, so producing a highly efficient supply chain. GlassPoint calculates its price competitiveness based on a “fuel breakeven cost.” A 2014 SPE paper illustrated the price of solar steam against gas-fired

InnovOil

once-through steam generators and cogeneration steam projects. It suggests that at a gas price of US$6 per million British thermal units, solar generates steam at US$17 per tonne – around US$3 less per tonne than the co-generation facility and US$10 less than once-through steam generators. O’Donnell said that even with lower gas prices, GlassPoint was competitive, with the company and its clients now looking at a breakeven price of around US$3 per million Btu. “We dramatically cut the cost of making steam from sunshine, so that we’re below the fuel price,” O’Donnell says. “With that economic drive, even at a time of low oil prices, I think it indicates how significant solar technology is, because in today’s environment, no-one is sanctioning nice-to-have projects – they’re sanctioning must-do projects.” Hurry up and Kuwait With the first tranche of Miraah expected on line by 2017, GlassPoint already has its eyes on new markets. Nearby Kuwait is another promising lead. “Kuwait has announced plans to go much further than Oman, with many times larger steam projects. Earlier this year it sanctioned the first days of commercial development at the first of a series of thermal recovery projects.” With an office established in NEWSBASE

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the country in 2014, GlassPoint is ideally positioned to move in. Beyond Kuwait, the sky is very much the limit. With heavy crude accounting for an estimated 2.3 million bpd of production in 2013, there is no shortage of targets. Venezuela, western China, North Africa and much of the Middle East are in need of thermal EOR for heavy oil projects. Yet GlassPoint’s medium-term ambitions are closer to home. “We see the California market opening up very significantly,” O’Donnell said. In the light of new restrictions on emissions, he suggested: “Solar steam can deliver compliance with carbon regulations at much lower cost than other projects and contribute substantially to refinery profitability as well as steam producer profitability.” The result is that GlassPoint is increasingly being brought in as an early-stage consultant on thermal EOR projects, in order help operators model and understand the process of setting up facilities. The potential is enormous, O’Donnell said. “We’re working with customers, who aren’t just looking to get 5% of their steam from sunshine; they [want] 50% or 80% from sunshine.” “The oil industry is really the next major market for the solar industry,” O’Donnell concludes. “We see a really very substantial market opportunity.” n

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September 2015

COMMENTARY

The future is robotic Sophie Davies reports on TWI’s newly-opened London South Bank Innovation Centre (LSBIC), and the robotics which could shape the future oil and gas industry

n June, UK-based technology company TWI announced the creation of the London South Bank Innovation Centre (LSBIC), aimed at pioneering new research in the development of robotic and automated non-destructive testing (NDT) methods. Located in new 25,000-square metre premises just outside Cambridge, the LSBIC I is tasked with developing automated and robotic NDT technologies for a range of industries “wherever there is a demand for more effective, less costly inspection,” TWI says. In particular, the new Centre will concentrate on technology for use in environments where manually deployed NDT techniques are hazardous or impractical. Their potential clients include a wealth of companies working across the upstream and downstream oil and gas industry, as well as storage tank operators and process pipelines in the petrochemicals industry. The quest for greater robotic and intelligent automation comes as working environments become harsher. Many of these inspection techniques can offer greater crew safety, and often better results. Accidents at oil and gas facilities still claim lives. Between 2003 and 2010, a total of 128 people in the US died while working at offshore operations, according to the US Department of Health. That represents a fatality rate that is seven times worse than for the average worker in the US, it said. As, TWI points out, studies have shown that human error in manual inspection can miss major defects in safety systems and structures. Extreme conditions In the first five years of its life, the LSBIC will house 14 researchers and support eight TWI-funded PhD degrees. As one of Europe’s largest research organisations, the direction of the Centre’s work will be determined by TWI’s 700 industrial member companies. Professor Tariq Sattar, who was

previously head of London South Bank spite of the “complex nature” of robotic University’s Mechatronics, Robotics and NDT compared with its automated Non-Destructive Testing Research team equivalent, developments are progressing (MRNDT), will lead the new centre. rapidly, spurred by the already-high MRNDT has already developed a demand. number of robots, including wall-climbing Indeed the automated robot industry is and amphibious prototypes, many of already advanced, and continues to grow which can be applied to the oil and rapidly – particularly in Asia. gas industry. In particular its work has In 2013 the UK government identified produced units to carry out inspections “robotics and autonomous systems” as of the walls and floors of oil and one of eight main technologies in which petrochemical tanks. the country has the potential to become a “Our applications are usually world leader. challenging and complicated,” Professor But it remains far behind its rivals in Tat-Hean Gan, Associate Director of terms of robot development. The Chinese TWI, told InnovOil. government, for one, is pushing for rapid These applications can development of its own be used for inspections in industry which is already extreme conditions, for one of the world’s biggest, instance in high temperature and backed up by major environments and high collaborations and joint pressure pipes, he said. ventures with international They can also be applied in partners, such as Zurichaggressive environments for based ABB. deep water risers and very In 2014, global demand for small inaccessible areas. industrial robots reached a “Through the record of more than 200,000 collaboration with London units sold, the FrankfurtSouth Bank University, “All the oil and based International we are able to bring our of Robotics (IFR) gas companies Federation technology to the next level said earlier this year. that we have of innovation that will benefit The strongest drivers of our worldwide members,” he growth last year were the approached have added. automotive industry followed provided positive by the electronics industry. feedback” Early adopters According to preliminary Gan expects most of these Professor Tat-Hean Gan, statistics on industrial robots, technologies to be first Associate Director of TWI a total of around 225,000 adopted by oil and gas units were sold in 2014, up companies wanting to improve safety in 27% compared to in 2013. Europe and the West, before spreading to The IFR estimates that robot the Far East. installations will increase by 12% on Unlike automated NDT, robotic NDT average per year between 2015 and 2017, has not yet been fully commercialised. with the most growth in Asia-Pacific, Automated NDT, which has been applied followed by Europe and the US. in many industries, is already used in Robots are seen as a way to reduce costs production lines. Many manufacturing and solve labour shortage problems in firms use automated NDT robotic arms China’s manufacturing industry, allowing that are capable of working independently companies to maintain a competitive edge. and together. Gan is convinced that, in Currently China and South Korea use NEWSBASE

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COMMENTARY

the most industrial robots globally. In China alone, around 56,000 units were sold in 2014, more than double the volume sold in 2013, according to IFR statistics. As well as solving safety issues, oil and gas companies may also see similar benefits to using robotic NDT technologies. Borne free TWI already has some experience in the robotics and autonomous inspection field, through projects funded by the European Commission. Most of these reached Technology Readiness Level (TRL) 6, meaning “the robotic inspection systems had been demonstrated in industrially relevant environments,” Gan said. These included systems to inspect marine structures, wind turbines, pressure vessels, nuclear nozzles, mooring chains and FPSO ship hulls. The establishment of LSBIC allows TWI to take its research up a notch – enabling the company to develop those same systems to TRL 9 level, meaning that it can enhance the technology making it able to perform in operationally complex environments, said Gan. “So far all the oil and gas companies that we have approached have provided

positive feedback on the new initiative,” he said. “The industry is looking into reducing the cost of performing inspections at sites that are remotely located on large structures and/or in hazardous environments and hence not easily accessible to humans,” he added. “Some companies highlighted that drones could be the future for inspections, replacing humans in life-threatening tasks such as inspections of offshore wind turbine blades or offshore platform towers,” he noted. Others have highlighted the need for robotics and automated inspection for time-consuming manual tasks involved in Floating Production Storage and Offloading (FPSO) vessels. In particular, Gan said, they could be used within FPSO hull structures and offshore mooring chains, helping to reduce human errors in detection of defects. In the oil and gas industry, automated and robotic NDT technologies may take an “autonomous free movement” approach, Gan said. The “autonomous free movement” approach would refer to when the robot is autonomous i.e. it makes its own decisions on its motion trajectories and is free to NEWSBASE

move in any direction that it chooses. He gives the example of a robot on a large flat surface that could rotate on the same spot before heading off at any angle. These robots could take the form of wall-climbing robots using vortex machines, permanent magnet adhesion and flux concentration techniques – magnet systems in which the magnetic flux lines are shaped to point in a particular direction, so that most of the flux passes through the object to which the climbing robot is to be attached, Gan explained. “This dramatically increases the adhesion force,” he added. In all cases, these robots would be guided via the use of lasers or magnetics, he added. The rising demand for robots across several industries, combined with governmental backing for new research in the UK, means that real progress could be seen in the development of robotic NDT technology in the near future. Though challenging and complex to develop, the broad potential of NDT makes it an area that is ripe for innovation –and InnovOil expects to see many more hydrocarbon industry operators join the movement in the next few years. n

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Propane – no gain? A new proposal to use gelled propane for hydraulic fracturing in New York has attracted widespread attention. Ros Davidson investigates the viability and appeal of the technology

S news outlets exploded in July as a proposal was unveiled to use gelled propane to frack for natural gas in a New York State shale play. While the industry’s response was decidedly more muted, the proposal raises some interesting questions about the viability and appeal of the technique. New York currently bans high-volume fracturing with water – defined as any “stimulation of a well using 300,000 or more gallons of water as the base fluid for hydraulic fracturing for all stages of well completion, regardless of whether the well is vertical or directional” – limits which essentially act as a de facto ban. The measures were implemented amid a furore over fracking, and with the backing of an array of pressure groups which claimed that the procedure could taint the state’s water supply. The key point for drillers, and one which has been hinted at since the law was introduced, is that gelled gas fracturing would allow them to circumvent the State’s regulations. But gas fracking, typically using propane or butane, has only been used in a thousand or so wells in North America. And there has been little published independent research on the technique. Of the drillers that have tested it, few have reported details. Notably, a pioneering firm behind the technology – Calgary-based GasFrac Energy Ohio Services – filed for US and Canadian bankruptcy reorganisation in January 2015. At

the time, observers said the move followed years of financial stress, the indication being that the technology did not have killer appeal to the US shale market. GasFrac’s technology was since bought by another Canadian company, Step Energy Services, which did not respond to a request for an interview. Unconventional alternative It’ s still early days for the group of New York landowners leasing 53 acres (0.21 square km) in the Southern Tier to site operator Tioga Energy Partners. The company plans to use to use a mixture of propane gel and sand in a well that would be drilled through the Utica and then horizontally into the Marcellus shale formation. The application, listing Tioga as the operator, is now being reviewed by the state Department of Environmental Conservation. But, lawyer Adam Schultz of Couch White law firm, who represents Tioga, confirmed to InnovOil that: “The technology will be similar to that t… used by GasFrac.” On paper, gas fracking appears fairly viable.

New York Tioga County Pennsylvania

MARCELLUS SHALE

Maryland

West Virginia

Kentucky Virginia

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In comparison with the potential environmental footprint of conventional fracking, and the need to dispose of millions of gallons of wastewater, it can offer some significant benefits. Water can also lessen the potential production from wells, especially those producing oil, a problem not encountered with miscible gas. With drought gripping much of the western US, in many places gas may well be a more plentiful alternative to water. GasFrac is on record as having touted its technique for using a gas that is widely available because it is a by-product of the hydrocarbon industry. The propane used can also be recaptured and re-used again and again, or even resold. GasFrac has also said that unlike water, propane – which is non-reactive – leaves behind salts and naturallyoccurring radioactive materials, rather than dissolving them. “We leave the nasties in the ground, where they belong,” the company’s then-CTO Robert Lestz was quoted in 2010. Water solution “In theory [the technique] has a smaller environmental footprint, and wells completed with this technology would offer better performance,” said David Burnett, director of technology at the Global Petroleum Research Institute and a member of the Department of Petroleum Engineering at Texas A&M University. “In the future, we will need a more environmentally sustainable shale well completion technology, [and] one option is to find a substitute for water,” he told InnovOil. With conventional fracking, production is decreased when water reacts with clay. According to Penn State Marcellus Centre for Outreach and Research hydro geologist, David Yoxtheimer, water can also block a particular flowpath when an oil well is being fracked. Oil and water are not

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COMMENTARY Natural Gas well in the Marcellus Shale, Pennsylvania

miscible, he notes, whereas natural gas can flow more easily through gelled propane. But Yoxtheimer told InnovOil that in deeper wells, propane works less effectively because more pressure must be built up. In contrast, water is almost virtually incompressible and so allows the driller to increase pressure more easily. Because of this, he says, gas fracking would likely be more commercial at shallower depths of 1000 metres, rather than 2-3000 metres. GasFrac personnel have previously disagreed, claiming that depth is not an issue, and that they have fracked at depths of more than 3000 metres. At the proposed New York site however, the Marcellus is relatively near the surface. With liquid petroleum gas (LPG) fracking, there is an approximate 50% reduction in the volume of truck traffic to a well site owing to the lower volume of propane (versus water) needed to complete the stimulation, says Tioga. LPG is also a more effective carrier of proppant (such as sand) based upon its ability to hold the sand in suspension for longer periods of time, the company adds. This results in more sand entering and remaining in the rock fractures. At what cost? The cost of gas fracking, however, remains an issue. Hydraulic fracturing with gas is generally thought to be about 25% more expensive than with water, gauges Burnett. Because the technology is still relatively new, it is also pricier getting the surface equipment appropriate for handling propane gel. Well testing after a gas fracturing will have to accommodate larger portable well test separators to handle the increased volume of the hydrocarbon. The propane also has to be brought in, stored, and afterwards put into a pipeline or trucks. Itâ&#x20AC;&#x2122;s simply more expensive NEWSBASE

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Commentary Gas drill bit

to bring in large volumes of LNG to a fracking site, says Yoxtheimer. Yet if propane is already plentiful in an area – e.g. because of existing hydrocarbon production – then fracking with gas makes more commercial sense. In New York state, for example, a major propane pipeline already runs through the Southern Tier. From a safety perspective, propane is also explosive, and must be handled accordingly. But proponents note that the industry is well-used to handing liquid gas, and that propane has been handled safely by communities for decades. In the right place What is apparent from these claims and counter-claims is that the technique is not widely used. In 2012, Chevron reported that LPG was used in a pilot project, in multiple-staged fracture treatments in Colorado’s Piceance Basin. This led to “significantly increase[d] production while minimising water usage,” said the supermajor shortly afterwards. Chevron declined to comment further on the test results, citing confidentiality. A Chevron spokesman also told InnovOil that, as of mid-August 2015, the company had not used propane in hydraulic fracturing since the Colorado test. The same year, Quicksilver Resources reported on its use of the process in Colorado’s Sandwash Basin/Niobrara formation. The company “completed the first 3 vertical wells with oil fracs and the second 3 wells, 2 vertical and the horizontal, with a different style gas frac,” said CEO Glenn Darden. “This technique has shown significantly better results,” he told analysts in an earnings call. According to the company results, the horizontal well fractured about 1,500 feet (450m) of a 4,500-foot (1,370 m) lateral and had a 45-day production average of 230 barrels of oil equivalent per day, primarily oil. Darden added that: “The

2 vertical wells completed in this manner are steady producers, with the best well averaging 120 barrels of oil equivalent per day, again mostly oil, over the same 45-day period.” Yet despite the implied advantages of gas fracturing in some locations, experts do not see the niche technique catching on widely any time soon. “This pause in drilling is allowing companies to sharpen their technology – but gas fracturing is speculative,” said Burnett. “It’s a Mars shot, a long shot.” NEWSBASE

Yoxtheimer agreed that more field research is needed to know how widely applicable the technology is. “Right now, companies are not looking to put too much money into experiments,” he said. The technique has a lot of promise in the right formations, namely where NGLs are produced, where oil is being sought, and perhaps where water is in short supply. “[But] it’s a bit of a boutique technology.” For the time being at least, it would seem that gas fracturing is set to remain the exception, rather than the rule. n

0% e 1 as ve WP s B s a PC ew n N c a o de s er g c ad in re us

The meeting place of Europeâ&#x20AC;&#x2122;s shale gas and oil industry

Now in its 6th year, Shale World Europe is the largest gathering of the unconventional oil and gas industry outside of North America, with over 600 registered attendees in 2014. This year, we aim to attract the key stakeholders across Europe and North Africa. Collaboration, partnering, advancing technology, influencing stakeholders and sharing experience are essential for developing this burgeoning industry. This is what Shale World Europe achieves, as operators look to efficiently acquire, explore, develop, and produce. Shale World Europe has become the event for the European unconventional oil and gas industry.

2015 key speakers include:

Georgii Rudko Chairman State Commission of Ukraine on Natural Resources

Chris Faulkner CEO Breitling Energy

Marcin Zieba General Director OPPPW

David Alameda General Director Shale Gas EspaĂąa

Janus Snyders Communication Researcher Tshwane University of Technology

Peter Britze Head of Department Geological Survey of Denmark and Greenland (GEUS)

6th annual

Full programme online terrapinn.com/shale-NewsBase 17-18 November 2015,

Hilton Hotel and Convention Centre, Warsaw, Poland

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Schlumberger launches industry-first deepwater seismic survey Schlumberger today expanded its Gulf of Mexico multiclient wide-azimuth seismic data portfolio by launching a new survey in the Campeche Basin. The acquisition of the industry’s first multiclient wideazimuth survey offshore Mexico will cover 80,000 sq km using two fleets of WesternGeco vessels, including Amazon Class, the world’s first purpose-designed 3D seismic vessels. “Building on our experience in the US Gulf of Mexico, we are focused on collaborating with customers to understand and prioritize the hydrocarbon potential in the Mexican waters of the Gulf,” said Maurice Nessim, president, WesternGeco. “We have begun acquisition of high-quality seismic images of the Campeche Basin, which when combined with advanced modeling and

interpretation, will help our customers identify new exploration opportunities and minimize risk.” Subsurface challenges in the Campeche Basin—including near-salt and subsalt structures, complex faulted structures, and deep-thrusted structures—are overcome using a suite of wide-azimuth, long offset and broadband seismic surveys. In such complex geology, where illumination of the subsurface is challenging, wide-azimuth acquisition and broadband imaging technologies deliver advanced data to support identification of subtle structural and stratigraphic traps, provide better delineation of fractures, and improve reservoir characterization. Following completion of the seismic acquisition program in early 2016, customers will have access to high-quality images to support future appraisal campaigns in this frontier play. The Mexico multiclient wide-azimuth survey was designed and modeled based on customer interest and input to the program. Additional Schlumberger multiclient projects in Mexico include reimaging of the Campeche and Perdido basins. n SCHLUMBERGER

NEWSBASE

Amec Foster Wheeler wins Hassi R’Mel contract Amec Foster Wheeler has won a contract to supply consultancy services for the de-bottlenecking of Algeria’s Hassi R’Mel gas field, one of the largest resources in Africa. The consultancy work will support Sonatrach’s aim to operate Hassi R’Mel well into the future, helping Algeria to remain a major exporter of gas. The value of the consultancy contract, to be delivered by experts in the oilfield services company’s Reading, UK-based office, has not been announced. “The engineering design services involve a major flow assurance exercise using Amec Foster Wheeler’s proprietary software to identify future bottlenecks in the gas field gathering network,” the company said in an August 12 statement. “In addition, the team will undertake detailed pipeline design, compression studies and the multidisciplined specification of the additional infrastructure required to allow continued production,” it added. Located 550 km south of Algiers, Hassi R’Mel was discovered in 1956 along with the Hassi Messaoud field. Production started in 1961 and output is around 100 billion cubic feet (2.8 billion cubic metres) per year of gas from the Triassic formation. Amec Foster Wheeler’s group president for the region, Roberto Penno, said: “We are delighted to be working with Sonatrach again on this major development using our considerable upstream and pipelines expertise, and hope to further build the relationship by supporting them with their future plans in the region.” The company’s previous experience in Algeria includes a joint venture with Tecnicas Reunidas, which built a gas compressor station and receiving station near Beni-Saf for the Medgaz pipeline. Sonatrach has recently outlined an ambitious set of gas production plans, to cope with a 41% domestic gas demand increase that is predicted by 2019 and to optimise export revenues. Sonatrach hopes to increase its 2014-19 gas production by 13.5%, including bringing onstream 14 new gas projects with a capacity of 42 bcf (1.19 bcm) per year. While the state-backed company intends

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to scale-up production, the country is seen as a tough place to work and domestic demand is rising, putting pressure on exports. n Edited by Ed Reed edreed@newsbase.com

Training sessions announced for Teledyne Marine Technology workshop Building upon Teledyne RDI’s long-standing ADCPs in Action (AiA) Users Conferences and Teledyne Marine Acoustic Imaging’s Underwater Technology Seminars (UTS), the newly expanded Teledyne Marine Technology Workshop (TMTW) will allow attendees from around the globe to experience the expanded range of applications, products, and technologies that represent the nineteen Teledyne Marine brands that will participate in the workshop. While the scope of the workshop has grown, customers will continue to enjoy the one-onone focus and industry camaraderie they’ve come to expect from the original conferences. TMTW, which will be hosted in San Diego, California on October 4-7, 2015, has now accepted over forty industry speakers spanning four concurrent morning tracks focused on the utilization

of marine technology for offshore energy, oceanography / hydrography, civil engineering / water resources, and defense / security. Each afternoon will be comprised of eight concurrent training sessions focused on company-centric product and software training, tips, and technology, as well as live product demonstrations. The event will commence with a keynote speech from Zdenka Saba Willis, Director of the U.S. Integrated Ocean Observing System (IOOS®) Program. “We are excited about this newly expanded users’ conference” said Earl Childress, Executive Vice President of Sales and Marketing for Teledyne Marine. “The addition of our subsea vehicle, harsh environment interconnect, and state of the art sensor technology will allow attendees to see the full range of solutions that Teledyne can apply to resolve their specific challenges.” Participating Teledyne Marine product brands include: Teledyne AGG, ATLAS Hydrographic, Benthos, BlueView, Bowtech, CDL, DGO, Gavia, Impulse, Odom Hydrographic, Oceanscience, ODI, Optech, RD Instruments, RESON, SeaBotix, Storm Cable, TSS, and Webb Research To register for TMTW 2015 and view the full list of speakers and training sessions, visit tm-techworkshop.com. Additionally, a new mobile app containing full event details is available at www.guidebook.com/g/tmtw. Once you install the Guidebook app on your mobile device, search for the Teledyne Marine Technology Workshop event guide. n TELEDYNE MARINE TECHNOLOGY

Sakhalin Energy, the Gazprom-led consortium, is gearing up to settle the question of whether to expand its LNG plant on Sakhalin Island.

NEWSBASE

Sakhalin Energy plans third train Sakhalin Energy, the Gazprom-led consortium that is developing the offshore Sakhalin-2 block, is gearing up to settle the question of whether to expand its LNG plant on Sakhalin Island. Its draft schedule for the project calls for making a final investment decisions (FID) in the second half of 2017 and then launching the new production train in 2021. “Currently, Sakhalin Energy is in the process of preliminary planning operations for the construction of the third [production] line. It is expected that the first stage [of this process] will be completed in September of this year, [meaning that] the company will be ready to begin the second stage, which includes the feasibility study,” the consortium said in its corporate publication. Sakhalin Energy’s schedule for the third LNG train is similar to the projected timeline for launching development operations at a new gas production base – namely, the Kirinsky and YuzhnoKirinsky sections of the Sakhalin-3 block. The group will reach the FID stage for the project in the second half of 2017 and hopes to start production in 2021. The consortium’s gas liquefaction on Sakhalin Island is so far the only such plant in Russia. It processes gas from the Sakhalin-2 block, which includes the

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Piltun-Astokhskoye and Lunskoye fields. Equity in the scheme is split 50% plus one share to Gazprom, 27.5% minus one share to Royal Dutch Shell, 12.5% to Mitsui and 10% to Mitsubishi. Construction of the third line will lift the production capacity of the Sakhalin LNG plant to 15 million tonnes per year, a rise of about 50% on current levels. The expansion project will require the existing pipelines that carry gas from Sakhalin-2 to the LNG plant to operate at almost 100% of their current capacity. These pipelines currently have a capacity surplus of 8 billion cubic metres per year, equivalent to 5.6 million tonnes of LNG. The move to reserve spare capacity for gas from Kirinsky and Yuzhno-Kirinsky is likely designed to help Gazprom at the expense of a rival – Rosneft, which is working to beef up its gas output. Rosneft had previously sought access to Sakhalin Energy’s pipeline in order to transport 8 bcm per year of gas, but its request was denied. n Edited by Jennifer De Lay fusogm@gmail.com

ONGC approves plans to redevelop ageing Neelam field

is anticipated to raise output at the maturing field to 55,600 barrels per day of oil and 4.79 billion cubic metres per year of gas by 2034-35. ONGC’s west coast offshore fields, which include Neelam, Mumbai High, Heera and Bassein, have served as the company’s traditional resource base, although production at these mature fields is now waning. To offset this, the company wants to invest around US$7 billion to develop eastern offshore fields, including those in the KG-DWN-98/2 (KG-D5) block, in order to raise future output levels. The company also announced an increase in revenues and profits in the April-June quarter. The encouraging financial results were partly owing to the decline in crude oil prices, which meant the company was burdened with less subsidy discounts which it usually makes to Indian refiners in order to limit the prices of kerosene and LPG. The Indian rupee also weakened 5.8% against the US dollar, causing the company’s sales to inflate in rupee terms n Edited by Andrew Kemp andrew.kemp@newsbase.com

BP to spend US$1bn on North Sea fields BP is to invest around GBP670 million (US$1 billion) to extend the life of its Eastern Trough Area Project (ETAP) fields in the North Sea until at least 2030. The news has been welcomed as a major boost for the sector. “These are challenging times for the industry and we are having to make hard choices,” said BP’s North Sea regional president, Trevor Garlick. “Nonetheless, we remain committed to improving the competitiveness of the North Sea and to maximising economic recovery from our fields.” He added that BP’s main areas of focus for investment would be to the West of Shetland (WoS) and the central North Sea, where the company is funding new developments and extending the life of existing ones. ETAP consists of nine fields with a combined production of 120,000 barrels per day, six of which are operated by BP and the other three by Royal Dutch Shell. Since the downturn in oil prices, BP has Speaking to Aberdeen daily the Press and Journal, UK Energy Minister Andrea Leadsom praised the move

India’s state-run Oil and Natural Gas Corp. (ONGC) will shortly kick-start redevelopment of the giant Neelam field off the country’s west coast after its board recently approved the project. As part of the 28.29 billion rupee (US$432.55 million) plan to increase oil and gas production at the GK-28/42 field, 14 new wells and 13 sidetracks will be drilled along with the addition of new facilities, including: a process platform, two well-head platforms and three clamp-on facilities for wells on existing platforms, as well as associated pipelines, modifications and other operations. The Indian major said it expected the installation of facilities to be finished by August 2018, with the overall project being completed by March 2023. This NEWSBASE

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with about 375,000 people employed, and it’s vital for our energy security and for keeping our bills down.” But she also called for “a lot more investment” in the region. “We think there’s a bright future and there’s a lot more that can be done to ensure that gas recovery remains at high levels.” n

shed hundreds of jobs in the North Sea region, with a US$1.5 billion restructuring programme under way. Late last month, the company announced a loss US$6.3 billion despite saving US$1.5 billion in costs during the first half of the year. No figures regarding the breakeven price for ETAP were provided, although previously the company has said that it expects the cost of crude to remain depressed for some time, while the average North Sea capex is estimated to stand at around US$30 per barrel. With this in mind, BP appears to taking a long-term approach to the development, although it may be also be encouraged by its recent cost-saving innovations and lower rig rates for a project that requires the drilling of numerous wells. Speaking to Aberdeen daily the Press and Journal, UK Energy Minister Andrea Leadsom praised the move, saying that during a visit to ETAP following the announcement the mood among workers was positive. “It did feel as though people who are working out there see a future for themselves in the industry, which is great. It’s been a difficult time, but you could really sense the optimism out on ETAP,” she continued. “It’s a vital sector for the UK economy,

Edited by Ryan Stevenson ryans@newsbase.com

LUKoil tenders for engineering job at Iraq’s West Qurna-2 oilfield Russia’s LUKoil has floated a tender for master engineering services at the estimated US$2.5 billion second-phase development of Iraq’s giant West Qurna-2 oilfield. The news comes as a welcome sign for Baghdad that investment in expanding production is proceeding despite the government’s problems in paying the

Bismil

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Mushorah Sufaya Ayn Zalah

Butmah Gusair Alan Demir Dagh Sasan Mosul Erbil Qalian Ibrahim Bay Hasan Atshan Taq Taq Adaiyah Kirkuk Miran Jawan Qasab Qara Chauq Kirkuk Najmah Al Qayyarah Chamchamal Sadid Sulaymaniyah Khubbuz

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international oil companies (IOCs) who are developing the major southern fields. The Russian firm blamed its own slump in profits during the first quarter on unpaid dues from Iraq and agreed to reduce planned capital expenditure at the field for this year at the Iraqi Oil Ministry’s request. However, LUKoil executives have also repeatedly emphasised their long-term commitment to the project, and the firm was among the chief beneficiaries of the introduction of a new heavy crude grade in June, allowing output from the first phase of development to reach full capacity during that month. The tender for master engineering services covers the next phase of development, called Mishrif Full-Field, aimed at adding 150,000 barrels per day of capacity to the 400,000 bpd now being produced from the so-called Early Oil Mishrif first phase – both targeting the Mishrif reservoir. Submissions are due by September 17 and prospective bidders are required to be capable of carrying out engineering consultancy throughout field development, including pre-front-end engineering and design (pre-FEED), FEED, detailed design and production planning. Movement towards the second phase has suffered delays, with the engineering, procurement and construction (EPC) contract for the central processing facilities (CPF) tendered in early 2014 and yet to be awarded. South Korea’s Samsung Engineering was the EPC contractor for the Early Oil CPF. Selections are also pending for contracts covering water-injection and oil-gathering facilities. Australia’s Worley Parsons was appointed project management consultant (PMC) in late 2012. A third and final phase of development of West Qurna-2 is due to add 650,000 bpd from the deeper Yamama reservoir to take output to the 1.2 million bpd plateau stipulated under a 2013 amendment to LUKoil’s Development and Production Service Contract (DPSC) – reduced from the 1.8 million envisaged in the original 2010 deal while being extended in anticipated duration from 13 to 19.5 years. The estimated 13 billion barrel field lies in the south, around 65 km northwest of Basra. LUKoil holds a 75% stake in the licence, alongside government-owned North Oil Co. (NOC). n Edited by Ian Simm ians@newsbase.com

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September 2015

News in brief

Thirty-nine firms signed up for Brazil auction Thirty-nine companies have signed up to participate in Brazil’s 13th bid round of exploration blocks, which is due to take place in October. Though the companies have paid the requisite fee to participate, this does not necessarily translate into bids for exploration blocks. But in light of the fallout from the corruption scandal at Petrobras, the poor showing in the recent Mexico bid round and ongoing low oil prices, this level of interest will provide some relief to beleaguered Brazilian officials. The authorities will now examine all applications, with those companies authorised to bid being approved by September 2. The auction has been overshadowed by the collapse in the oil price and the Petrobras scandal, which has raised questions about the fundamentals of Brazil’s expensive deepwater offshore industry. The bid round has already attracted the ire of the oil lobby in Brazil, which is angry at the stringent national content requirements in the country. The Brazilian Petroleum Institute recently slammed the 13th auction’s terms as “the worst ever”, in the latest sign of exasperation at the government’s influence in the oil industry. The institute warned the auction could fail if the government insisted on going ahead with clauses that restricted concession holders from seeking extrajudicial arbitration. The terms also envisage that operators will have to pay fines for local content violations before all appeals are settled. The auction is shaping up to be a major test of the attractiveness of Brazil’s oil industry in light of the collapse in the oil price and the subsequent slashing of investment by international oil companies (IOCs). The industry lobbied to have Brazil’s onerous national content requirements eased ahead of the auction, arguing that Brazil’s industrial base was unable to compete on price with foreign suppliers and incapable of delivering orders on time.

This could delay projects and also push up their costs. But while promising future relief, the government said any changes would not come in time for the 13th round. Brazil’s government hopes to raise up to US$800 million in signing bonuses from 269 blocks up for grabs. Concessions in the Rio Grandes do Sul and Amazonas Basins are among those available, though no presalt assets will be offered. The assets in the 13th round contain a mix of onshore and offshore blocks, with both mature and new frontier areas included. The highlight of the round will include blocks in the Sergipe-Alagoas Basin. In recent years a series of finds have led to the basin being labelled the most promising oil frontier in Brazil outside the subsalt polygon. There will also be 51 blocks on offer in the Pelotas Basin in the south of Brazil. These assets will be close to the maritime border with Uruguay, which has attracted companies like Tullow Oil and Total in recent auctions of blocks in its waters. n Edited by Ryan Stevenson ryans@newsbase.com

NEWSBASE

Report: Some Bakken wells profitable below US$30 per barrel The break-even price for some Bakken shale counties could be under US$30 per barrel, according to new research by Bloomberg Intelligence analysts William Foiles and Andrew Cosgrove. This is lower than previously thought. The estimated break-even in the Bakken shale – a point at which there is profitability – in late 2014 had been over twice as high at US$65.2066.70. “Many industry experts … failed to adequately convey the broad range of variation within plays,” said the analysts in a presentation. With low commodity prices, shale drillers have retreated to core areas where they can make most gains, and they have lowered their well completion costs.

InnovOil

September 2015

page 37

News in brief

URAGUAY

Mouth of the Solis Grande RIver

Buenos Aires Rio

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Montevideo

ARGENTINA

An analysis of unconventional wells in McKenzie County, North Dakota, calculated a median break-even realised price of US$29.42 per barrel, when half of wells will generate returns exceeding 10%. The county has the lowest costs in the formation, said the researchers. McKenzie County also leads in well completions and horizontal rig counts, said Bloomberg Intelligence. These findings came despite the fact that the North Dakota Industrial Commission has said wells in McLean and Dunn counties have better economics. A Bloomberg Intelligence well economics model also revealed two small pockets in North Dakota, both close to the Missouri River, that showed a higher propensity for strong returns. Operators with acreage in these areas include ConocoPhillips, Hess and Continental Resources. Refracturing technology may be young, but when the analysts looked at over 80 wells in the play, they found that refracked wells’ initial production (IP) rates had climbed by over 30% in the first month after recompletion compared to their original completion years earlier. Whiting Petroleum is experimenting with enhanced well completions virtually everywhere across its Williston Basin acreage. The enhanced completions, which use larger sand volumes, are boosting production by 40-50% in the first several months, at well costs of US$6.5-7.5 million, they noted. By increasing output per well, enhanced completions effectively lower Whiting’s break-even oil price.

Oasis Petroleum, meanwhile, is continuing with its high-grading strategy, drilling and completing wells in areas that have the best economics and infrastructure available. In the second half of 2015, its completions will be in the Indian Hills and Alger areas of McKenzie and Mountrail counties. Using high-intensity completions – involving slick water and high-volume proppant – Bakken wells there have seen a 36-54% boost in early production. The combination of highgrading and high-intensity completions is therefore proving effective in lowering breakeven prices. n Edited by Anna Kachkova annak@newsbase.com

Uruguay budgets for import terminal Uruguay has released details of its planned investment in a US$1.1 billion LNG regasification terminal over the next four years. A July 27 announcement from Uruguayan President Tabare Vazquez allocated US$390 million to the scheme, within a larger allocation of US$12.37 billion for infrastructure projects between 2015 and 2019. Montivideo has contracted GNLS, a joint venture of France’s GDF Suez and Japan’s Marubeni, to build and operate the 10 million cubic metre per day terminal, which has an option to extend to 15 mcm per day. The project is earmarked for NEWSBASE

completion by 2016, and will be located offshore Montevideo, where the Solis Grande River empties into the Rio de la Plata. The facility will supply gas to Uruguay’s first combined cycle power plant, at Punta del Tigre, and could sell any surplus capacity to Argentina and Brazil. Uruguay has already spent US$710 million on the scheme, where civil works have been delayed for some five months owing to the withdrawal in February of Brazil’s Constructora OAS from a contract with GNLS to build a breakwater and wharves for the terminal. OAS reportedly ran into financial problems. With new subcontractors in place, the project remains on track, according to mid-July comments from the state-owned Gas Savago, including the construction of a regasification vessel in a Korean shipyard, the construction of storage facilities and a pipeline, and dredging works near the port of Montevideo. Gas Savago is a joint venture between Uruguayan state-owned Ancap and stateowned utility UTE. Argentina’s state power firm Enarsa previously pulled out of Gas Savago, citing a need to prioritise investments at home. GDF Suez signed a 15-year build, own, operate and transfer (BOOT) contract with Gas Sayago in October 2013. It brought in Marubeni as a 50% partner in February 2014. When complete, the new terminal will help Uruguay to diversify its energy supplies, reducing its dependence on oil imports and hydropower. n Edited by Ed Reed edreed@newsbase.com

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September 2015

InnovOil

What next …?

To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections The RSC’s Chemistry in the Oil Industry XIV event will be held on November 2-4 at the Hilton Manchester Deansgate Hotel, Manchester UK. For more information, visit the RSC website, www.rsc.org If your deepwater or HPHT operation could benefit from TETRA Technologies’ CS Neptune completion fluid or the SafeDEflo UDW filtration system, contact Vice President Sales and Marketing, Barry Donaldson on +1 281 364 2254, or email bdonaldson@tetratec.com To learn more about Armohib CI-5150, Witbreak GT, or Armoclean – or any of AkzoNobel’s range of oilfield chemicals – please contact Adrian Zuberbühler, Regional Sales Manager Oilfield EMEIA, on +41 (0)41 469 6948, or get in touch at adrian.zuberbuehler@akzonobel.com If Clariant Oil Services’ flowback aid HOSTAFRAC® SF interests your company, please get in touch with John Schulte on +1 281 296 3244, or email john.schulte@clariant.com. For base oils used in deep water, high-pressure high-temperature (HPHT) and horizontal drilling, please call SIP’s Glen Cockroft on +44 (0) 20 7717 0100 or contact enquiries@sip.com If solar steam EOR could revolutionise production at your oilfield, enquire with Kaitlyn Finegan at kaitlyn@antennagroup.com for more information about GlassPoint Solar If Utility ROV Services could provide the innovative tools needed for your subsea operation, visit www.utrov.com for more information, or get in touch with Craig Roberts at enquiries@utrov.com For more information on Fotech’s Distributed Acoustic Sensing (DAS), please contact Jhanvi Gudka at jhanvig@wildfirepr.com

NEWSBASE

page 39

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InnovOil, from the NewsBase group, is a technology-driven, monthly magazine which aims Andy Hill, Group Marketing Manager to provide a platform for innovators and engineers to share to share their ideas and expertise. IPU Group Our publication remains a trusted, solicited information source for technology news across the complete spectrum of the upstream, midstream and downtream oil andwith gas the sectors. “We were pleased

immediate interest that our article attracted.”

“The article on Kongsberg Oxford Catalysts Group Maritime’s Munin AUV is excellent” Mark Hampton, Manager of Exploration and Technology, Shell Exploration and Production Inc. Published by

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