Innovoil Issue 44 July 2016

OPTIMISE PRIMEThe latest production optimisation strategiesPage 17

LEARNING TO FLIWell-SENSE’s intervention revolutionPage 6

OIL YOU CAN EATHow oil-degrading bacteria help spill responsePage 12

Issue 44 July 2016

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Optimise primeThe latest production optimisation strategiesPage 17

Learning tO FLiWell-SENSE’s intervention revolutionPage 6

OiL yOu can eatHow oil-degrading bacteria help spill responsePage 12

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July 2016

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Inside

A note from the Editor 5 Pretty FLI for a fibre line 6Well-SENSE’s Dan Purkis on his intervention innovation A HUD for depths 9US Navy develops smart helmet On the Radar 10 Bacter the future 12Oil-eating bacteria fight spills PRODUCTION OPTIMISATION 17 Smartphone = smart plant 18Honeywell on industrial mobility NOV-olution 20The eVolve Optimisation service The waiting game 24US shale’s technical tactics Enhanced cognition 27IBM and Repsol team up The next quantum leap 28Lloyds Register on OTC Comms for Culzean 30Maersk’s Highlander rig EOG + EOR 32EOR in the Eagle Ford A better LabVIEW 35National Instruments for oil and gas News in Brief 37Contacts 43

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Environmental Risk Modelling

Corrosion and Materials Services

Technical Manpower Supply

Non-Destructive Testing and Inspection

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Asset Life Extension Services

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Collaboration

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Legionella Management

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Operational Permitting

July 2016 page 5

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A note from the EditorAS InnovOil headed to press, the energy markets were still coming to grips with the reality of a so-called “Brexit.”

Brent crude prices fell by around US$3 in the days following the June 23 vote, although they showed signs of a rebound by June 28.

London-headquartered super-majors such as Royal Dutch Shell and BP pledged to respect the vote (though both had been in favour of Remain), while many others preferred not to make any political statement whatsoever. Yet BP did appear to echo the feelings of many in the energy industry and beyond when it noted: “It is far too early to understand the detailed implications of this decision and uncertainty is never helpful for a business such as ours.”

Indeed, uncertainty is perhaps the key concern for oil and gas producers. The risk of another Scottish independence referendum is also likely to exert further pressure on the already-beleaguered oil hub of Aberdeen. Even with the promise of its recent City Region Deal, large investments may well be deferred until a clearer path emerges – surely not good news for Europe’s oil capital.

Industry sage Sir Ian Wood was quick to silence naysayers, telling Energy Voice: “We are at the beginning of a recovery, and the industry is undoubtedly in better shape than it was two years ago. Europe is not heavily engaged in our industry’s legislation and regulation, except in relation to safety and environment, and I believe this is unlikely to change.”

Generally, that analysis is correct. While analysts have acknowledged that poor short-term visibility represents an additional problem for those readjusting to fluctuating

oil prices, they are broadly assured that there will be few significant changes in the long term.

Though it does not spell the death knell of the industry, such uncertainty is not good news for innovation. Start-ups and new technologies may find it even more difficult to find industry support for disruptive ideas and confusion is already rising over future access to European markets. Perhaps more troublingly, it raises serious questions over the funding of UK academic research, the bedrock of much of the ground-breaking and fundamental work in the energy and technology sectors.

That work is important. In this issue, to take one example, we speak with Dr Tony Gutierrez of Heriot Watt University, whose recent research into the genetic code of ocean-dwelling bacteria could help disaster response teams tackle future oil spills.

Inside our supplement, we also look at some of the programmes, technologies and trends in Production Optimisation, speaking with NOV, Honeywell, Repsol and the University of Austin’s Professor Mukul Sharma.

Casting our eyes towards the disruptive end of the spectrum, Dan Purkis of Well-SENSE

Technologies outlines his revolutionary plans for intervention tools, and explains the potential of his Fibre Line Intervention (FLI) concept.

All this is featured, as well as a look at HUD-enabled diving helmets, the technology

behind Maersk Oil’s Culzean project, Lloyds Register Energy’s thoughts from OTC 2016, and

much more.Despite uncertain times, we wish all of our

readers a pleasant July and August. For now, the team and I are pleased to present

the July edition of InnovOil.

Andrew DykesEditor

Environmental Risk Modelling

Corrosion and Materials Services

Technical Manpower Supply

Non-Destructive Testing and Inspection

Pipeline Condition Modelling

Asset Life Extension Services

3D Laser Scanning Chemical Analysis

DSEAR Services

H2S Risk Management

Contaminants Testing

Waste Management

Contact us today to discuss your decommissioning needs

[email protected]

Decommissioning Solutions

Safe, efficient and environmentally responsible

Potable Water Testing and Management

Inspection For Reuse

CompEX and Other Training

Industry leading Assurance, Testing, Inspection and Certification, including....

Promoting

Collaboration

Circular Economy

Future-Proofing

Risk Management

Well Control and Risks Training

Microbiology Services

Equipment Certification

Dimensional Control Surveying

GIS Data Management

Environmental Impact Assessments

Legionella Management

Metocean Design

Seabed Survey

Operational Permitting

July 2016page 6

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InnovOil

BUILDING equipment that can survive downhole is hard. Dan Purkis is quick to remind me that “people think designing rockets

and spaceships is difficult, but that’s nothing compared to downhole tools!” Indeed, that simple truth alone adds years to development timelines, millions of dollars to budgets, and keeps service prices high. Purkis thinks that needs to end.

His solution is to use disposable tools that do not need to withstand the downhole environment – at least not for long. “One of the huge problems at the moment is the cost of the current solutions,” he explains by phone from Aberdeen. “The products and services that are offered are too expensive for the current market. That represents a huge opportunity to try and solve the problems using alternative technologies.”

Engineers spend years designing rental tools that must have long term high temperature reliability whilst being both serviceable and robust. It takes years to train engineers to be able to design to this level and it takes years to build, test and qualify such tools. “A tool has to be really reliable, corrosion-resistant, pressure-resistant, heat

resistant etc., and all that means the designs become very complicated and take a long time to come to market,” he continues.

The solution, in Purkis’ words, is “a new discipline.” The Fibre Line Intervention (FLI) concept is a range of dissolvable intervention tools, deployed into the well on a single fibre-optic cable, which could replace or compliment thousands of intervention

operations – from perforations to pressure, temperature and flow sensing – all performed faster and at a far lower cost than the industry is used to.

Dissolving expectationsPurkis is no stranger to designing downhole tools. Having worked at Petroleum Engineering Services (PES), a company which pioneered

some of the first intelligent completions, before being acquired by Halliburton, he went on to found Petrowell, where he designed a suite of RFID-operated completion and drilling tools. After six years in development the technology was sold to Weatherford. His latest venture, Well-SENSE Technology, was formed in July 2015 with the aim of “bringing technology from outside of the industry and redeploying it.” Purkis believes that the sector’s risk adverse approach to innovation means it overlooks

Pretty FLI for a fibre line

Andrew Dykes sat down with Well-SENSE Technology founder Dan Purkis to discuss FLI – an entirely new and disruptive approach to well intervention

solutions to problems which have already been explored by other industries.

His method when approaching new intervention tools was to ask: “What would Google or Apple do?” The answer, he posited, was unlikely to lie in the industry’s standard trio of coiled tubing, electric line or wireline, all of which have their own technical challenges, require large surface spooling equipment and multiple personnel to operate. Ultimately the tool designers end up with a downhole product that is a “20-foot long steel rental tool; again”

Disregarding the existing systems, he instead looked to the incredible strides made in consumer electronics and materials. “No-one in the market at the moment makes disposable tools,” he says. “Because with current approach to design, it would be too expensive and you can’t leave a tool down the well.” So he set about making some.

Taking inspiration from out with the oil and gas industry, the most revolutionary aspect of FLI is its ability to be discarded. With a housing based on a biodegradable polymers and water-soluble metal alloys, the tool is used and abandoned in the well, where it dissolves in a matter of days.

This tool is deployed into the well via a surface-connected fibre-optic line, allowing the FLI tool to “freefall into the well and be left there. You don’t get it back, and it doesn’t cause an obstruction.” One of the

“One of the huge problems at the moment

is the cost of the current solutions”

Dan Purkis

July 2016 page 7

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InnovOil

Pretty FLI for a fibre line

biggest risks in standard intervention jobs is becoming “stuck in hole” – but because FLI tools never need to be recovered, this risk never occurs, meaning no costly down time or fishing operations. “This would enable production optimisation operations to be performed on wells formerly deemed technically to risky or economically unviable,” Purkis says.

As its name suggests, the key component to FLI is a fibre-optic cable. Being strong and light – typically around 0.25mm in diameter – it is ideal for connecting small pieces of downhole equipment back to the surface. In

its bare format, it is also very cost effective, even at lengths of 4 to 6km, which is more than enough to reach the deepest sections of most wells. Moreover, it offers a revolution in data transfer speed. While wireline tools often employ data compression to send real time information back to the surface via copper wires, fibre optic cable can transmit data at 2.5Gb/s – more than 1,600 times greater bandwidth. That would allow users to deploy a camera tool, for example, and receive a live feed of up to 64 channels of HD, uncompressed video data.

Additionally, it requires virtually no

footprint on the surface. While other systems require a truck-mounted spool of cable, 10,000 feet (3,000 metres) of fibre-optic takes up the same space as a can of baked beans. Mounted inside the FLI tool itself, it unspools as the tool free falls into the well, with a depth reading provided by a laser range finder. When the FLI tool has completed its job, the line is either cut – leaving the tool and fibre to disintegrate in the well – or alternatively the fibre optic can be recovered using a reel at the surface.

One-stop opAs a single-use tool, the electronic components of FLI tools do not need to be robust enough to survive prolonged periods downhole. If a typical job lasts 30 minutes to an hour, Purkis adds, components only need to be heat and pressure shielded to survive that long before they disintegrate. That means they can be consumer-grade rather than military-grade, lowering costs and allowing designers access to the latest components on the market – e.g. the latest smartphone camera – instead of limiting parts to those which have been qualified for use in a well.

An hour of typical operation means that the power demand of a FLI tool is minimal. Instead of a 600-V power supply fed from the surface – coupled to a hefty power regulator in the tool – Purkis believes that small coin-cell batteries can provide adequate power for key components – essentially a sensor, an encoder and a fibre-optic transmitter – without the need for expensive, high-temperature Lithium Thionyl Chloride batteries.

All of which also circumvents another of the service industry’s cost burdens. To mitigate against electronic components

Far left: An early concept design for FLI

Left: Dan Purkis, Well-SENsE Founder and Technology Director

July 2016page 8

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becoming obsolete service companies routinely purchasing lifetime inventories to guarantee that tools can be built and maintained without having to requalify replacement parts. FLI tools use the latest release of electronic components available at the time, with minimal requalification requirements. That represents big savings on advance purchases which may never be used.

Ultimately, these concessions to disposability allow Well-SENSE to build a tool whose raw cost is thousands of dollars, rather than hundreds of thousand. Operated by “a technician and a suitcase, rather than a 20-tonne artic wagon and four personnel,” FLI represents a radical reduction in cost from industry convention.

Passive disruptionPurkis also explains his plans for two separate FLI disciplines: Active and Passive. An Active tool features electronics and components designed to relay information from downhole back to the surface. Passive tools use just the fibre-optic cable alone, no downhole tool, yet are capable of a number of impressive functions. These applications form the bulk of Well-SENSE’s current workload.

It is in conversation about recent advances in fibre-optic sensing – namely distributed temperature sensing (DTS), acoustic sensing (DAS) and pressure sensing (DPS) – where Purkis becomes very excited. Each technique involves sending laser light down a fibre-optic cable and analysing the backscatter to determine information from

every metre along the cable’s length. It is especially useful in oil and gas operations because it can offer asset managers fine-grain detail about the status of every point in a well. DAS in particular is “the talk of town,” Purkis notes, because it enables users to identify the exact location of leaks, monitor production and evaluate fracking operations in real time. This is where Passive FLI steps in.

Because all information processing is done via surface equipment, there are no components within the downhole tool itself, allowing Purkis to use the first commercial FLIs as a rapid, low-cost deployment system for DAS surveys. Currently DAS is either installed as a permanent system as

part of the well completion, or temporarily installed and retrieved by a truck mounted spooling system (similar to coil tubing and electric line). Both are expensive, largely because of installation time and/or capital equipment costs. A dissolvable FLI system would slash both, enabling DAS to be economical in a far greater number of wells.

Movement on these first surveys is promising, with trials now secured in Texas, Oklahoma and Alaska, as well as interest from some other small onshore operators. Following these, Purkis hopes to be able to take FLI-enabled DAS surveys to the wider industry.

While Purkis is bullish on the long-term potential of both Active and Passive FLI, he is aware that every FLI tool will require its own design and qualification – a Passive FLI tool used for DAS will be less complex

than an Active tool used for performing a directional survey. For that reason, Active applications will be slower to develop, though he hopes the uptake will be swift following the acceptance of Passive systems. In the meantime, however, the company is seeking participation with anyone with an interest in the technology, from well operators to component manufacturers – “Anyone who wants to make this successful,” he says.

Longer term, his vision for FLI development is anomalous in the industry. He concedes that: “FLI in itself isn’t that useful, it’s the applications you can put on it like a camera or a PLT or a gyroscope survey.” Lacking the expertise (and time) to design every possible system in-house, he wants to see the FLI system become an open-source platform for other developers to use, “in the same way that a smartphone provides a platform for all the thousands of apps developed by every and anyone.” In an industry notoriously protective of IP, that is indeed a revolutionary proposition.

Well-SENSE is confident that it has only begun to scratch the surface of what the FLI platform could do, even in a welcoming industry, it takes time to qualify such a radical departure from the norm. Yet throughout our conversation, Purkis has been evangelistic about changing industry perceptions and adopting new technologies. If anyone is driven enough to drag the intervention market into the next century, it could well be Well-SENSE. n

Contact: Well-SENSE Technology Ltd.Tel: +44 (0)1224 937 600Email: [email protected] Web: well-sense.co.uk

“A technician and a suitcase, rather than a 20-tonne artic

wagon and four personnel”

Dan Purkis

InnovOil July 2016 page 9

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ON the sea floor, seeing clearly is difficult. For divers working at depths of 100 metres or greater, every extra bit of information or

assistance can go a long way.With robots, ROVs and more

sophisticated equipment, it is easy to forget that human divers still have to perform a number of complex subsea tasks. While the industry’s focus on safety has undoubtedly improved over the past few decades, the pace of updating equipment and work processes has remained slower.

But with many new innovations aimed specifically at commercial divers, the pace seems to be changing. InnovOil has already featured Etro’s heated diving suits and Photosynergy’s Lightpath umbilical system – and June brought news of an intriguing new piece of kit from the US Navy.

Engineers at the Naval Surface Warfare Center Panama City Division (NSWC PCD) have devised a diving helmet with an in-built head-up display (HUD). The high-resolution Divers Augmented Vision Display (DAVD) is embedded directly inside the helmet and allows users to see far greater information and detail on their task, from a number of different sources.

This system is capable of displaying sector sonar – a topside view of the diver’s location and dive site – as well as text messages, diagrams, photographs and even augmented reality videos, and all in real time.

Stark comparisonThe addition of real-time operational data should help divers to work faster and safer, offering more information than pre-dive briefings alone. The HUD can help guide them to the worksite or a target, display details about the area or piece of equipment and help increase awareness of other potentially hazardous features around them.

All of this can be configured by each diver – e.g. the positions of each data feed – or they can simply turn off the HUD when it is not required.

The DAVD was devised by Underwater Systems Development Project Engineer Dennis Gallagher and his team. Gallagher added: “By building this HUD directly

inside the dive helmet instead of attaching a display on the outside, it can provide a capability similar to something from an ‘Ironman’ movie. You have everything you visually need right there within the helmet.” Tony Stark would indeed be proud.

Naval Sea Systems Command (00C3) is also developing enhanced sensors – such as miniaturised high-resolution sonar and enhanced underwater video systems – to enable divers to view higher-resolution images up close, even with almost no water visibility. In future, these underwater vision systems could then be fed directly into the DAVD HUD.

Commercialising DAVD or a similar system could have a major impact on divers in the oil and gas sector in particular. Given their need to locate and modify complex subsea equipment in difficult conditions, operators could improve the efficiency and safety of manned dives. As Reddit user and diver gnar-dar commented: “It’s about time! I worked as a commercial diver for 7 years wearing these exact Kirby Morgan dive helmets... So

US Navy engineers have developed a next-generation helmet, showing divers live information via a head-up display

much bottom time is wasted simply trying to find the worksite, with someone on a radio on surface watching you on a sonar feed and trying to relay it to you.”

So far, the engineering team has demonstrated the technology to more than 20 US naval divers. Although full deployment looks to be a year or two away, the team is now working on phase two, where components are being designed to include both helmet systems and full face masks. Divers are scheduled to conduct in-water simulation testing in October 2016.

Phase three is set to begin in 2017 to harden the system for expanded field testing with various US naval commands. n

Web: www.navy.mil/local/NSWC

A HUD of the pack

July 2016page 10

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InnovOil

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

On the radar

Easy to X-plane Having proposed the re-launch of its X-plane programme earlier this year, Nasa Aeronautics division has recently unveiled its latest innovation: the all-electric X-57.

Featuring 14 electric motors and nicknamed “Maxwell”, the aircraft will be based on a modified Italian-designed Tecnam P2006T twin-engine light aircraft. NASA’s Scalable Convergent Electric Propulsion Technology Operations Research project will replace the wings and two gas-fuelled piston engines with a long, skinny wing embedded with 14 electric

motors – 12 on the leading edge for take-offs and landings, and one larger motor on each wing tip for use while at cruise altitude.

In a press release, NASA noted that “distributing electric power across a number of motors integrated with an aircraft in this way will result in a five-time reduction in the energy required for a private plane to cruise at 175 mph.”

NASA Administrator Charles Bolden added that the “X-57 will take the first step in opening a new era of aviation.”

The US Naval Research Laboratory (NRL), Material Science and Technology Division, has been granted the first US patent for a method to extract carbon dioxide and hydrogen simultaneously from seawater. This single process provides all the raw materials necessary for the production of synthetic liquid hydrocarbon fuels.

The Electrolytic Cation Exchange Module (E-CEM), developed at the NRL, provides the Navy the capability to produce the raw materials necessary to develop synthetic fuel stock for the production of LNG, CNG, F-76 and JP-5 at sea or in remote locations.

Located at NRL’s Marine Corrosion Facility, Key West, Florida, the E-CEM has successfully demonstrated proof-of-concept for a simultaneous recovery process of carbon dioxide (CO2) and hydrogen from seawater. The carbon dioxide and hydrogen gas recovered from the seawater as feedstock are

Turning water into win

As it steps up efforts to assert itself in the South China Sea, China is reportedly accelerating plans for a manned, deepwater subsea research station.

The oceanic “space station” could be located at depths of up to 3,000m, according to a Science Ministry presentation seen by Bloomberg. Having examined the project, state authorities have apparently sought to speed up development of the station.

According to a separate ministry statement, the station would host dozens of crew who could work there for periods of up to a month.

Ostensibly the research station is meant to aid China in the hunt for seabed mineral deposits; however, the presentation also noted it would be movable and could be

used militarily – news which could mark an escalation in the diplomatic dispute over the region.

Nevertheless, some were quick to downplay the possibility. “To develop the ocean is an important strategy for the Chinese government, but the deep-sea space station is not designed against any country or region,” Xu Liping, a senior researcher for Southeast Asian affairs at the Chinese Academy of Social Sciences, a government-run institute, told Bloomberg.

“China’s project will be mainly for civil use, but we can’t rule out it will carry some military functions,” Xu said. “Many countries in the world have been researching these kind of deepwater projects and China is just one of those nations.”

10,000 feet under the sea

July 2016 page 11

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Shine on, nanodiamondsUniversity of Maryland researchers have developed a method to build diamond-based hybrid nanoparticles in large quantities, in a process which could aid the development of quantum circuits into consumer-level electronics.

By attaching other materials to the diamond grains, such as metal particles or semiconducting materials known as “quantum dots,” the researchers can create a variety of customisable hybrid nanoparticles, including nanoscale semiconductors and

magnets with precisely tailored properties.

The process uses nanoscale diamonds that contain a specific type of impurity: a single nitrogen atom where a carbon atom should be, with an empty space right next to it, resulting from a second missing carbon atom. This “nitrogen vacancy” impurity gives each diamond special optical and electromagnetic properties.

This nanodiamond could behave as a quantum bit (or qubit) at room temperature

– rather than the cryogenic temperatures needed for current systems – paving the way for further advances.

Matthew Doty, an associate professor of materials science and engineering at the University of Delaware who was not involved with the study, commented: “The UMD team’s new method creates a unique opportunity for bulk production of tailored hybrid materials. I expect that this advance will enable a number of new approaches for sensing and diagnostic technologies.”

Seeing infraredThe US’ Defense Advanced Research Projects Agency (DARPA) has awarded researchers at University of Central Florida a US$1.3 million grant to develop new infrared detection technology.

UCF researcher Debashis Chanda and associate professor Michael Leuenberger of the

NTC and UCF’s Department of Physics intend to base the detector on graphene, avoiding the need for cryogenic cooling.

“We came up with the idea that one can make graphene to strongly absorb light in the infrared domain and we showed that we can also tune the response electronically,” Chanda

said. “If you can take an infrared image in different spectral bands, you can extract much more information.”

The researchers are now looking to work with defence firms such as Northrop Grumman, Lockheed Martin and St. Johns Optical Systems for integration and packaging.

catalytically converted to hydrocarbons in a second additional synthetic process step.

“We are optimising both CO2 and hydrogen production and recovery, and [the] synthesis of hydrocarbons from CO2 and hydrogen,” said NRL research chemist Heather Willauer. “Since we will be producing enough feedstock in the near future, we envision integrating the two processes at our Key West facility to further evaluate how full-scale end-to-end production might evolve.”

The team hopes to have the two processes operating at Key West by late 2016.

Diagram of the Electrolytic Cation Exchange Module (E-CEM), developed at the U.S. Naval Research Laboratory (NRL)

July 2016page 12

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InnovOil

DR. TONY Gutierrez’ freezer is an interesting place. Deep in the bowels of the his laboratory at Heriot Watt University, under

lock and key, are samples of bacteria from locations across the world’s seas and oceans, many of which could hold the key to new surfactants, biopolymers and even how best to respond to future oil spills.

Some samples are particularly infamous. When the Deepwater Horizon rig explosion occurred at the Macondo prospect 2010, an estimated 4.1 million barrels of crude gushed into the Gulf of Mexico over 87 days. During that time, particular bacteria attuned to digesting hydrocarbons bloomed spectacularly, allowing researchers and the authorities to monitor their progress as they undertook a major clean-up operation.

Gutierrez is one of the leading experts on such oil-degrading bacteria. In 2010, he was working on postdoctoral research at the University of North Carolina, Chapel Hill, under a Marie Curie fellowship, and access to the Gulf of Mexico via research cruises meant he could conduct detailed microbiological research contaminated samples collected from sea surface oil slicks and in deep waters. “When the oil spill happened, colleagues at the University called me and said that this was a big spill, and that this was a huge opportunity to do

some really cool work and to investigate the microbiological response.”

As a microbial ecologist specialising in the marine environment, Gutierrez’ expertise lie in using sophisticated molecular biology techniques – DNA stable isotope probing and metagenomic tools, for example – to identify and study important roles that bacteria play in marine environments. In doing do, he has been able to discover new

species and families of bacteria, and in work outlined in one of his most recent papers, crack the genetic code of the species that played a key role in the biodegradation during the Deepwater Horizon spill.

Oceans of organismsThe bacteria Gutierrez and his associates have investigated, which eat oil, all occur naturally and are found throughout the world’s oceans, and at all depths. “If there’s no oil in a particular environment these organisms are in very low abundance – less than one cell per litre of seawater,” he explains. “But when oil enters

this environment these organisms will bloom and thrive, whilst other bacteria may die due to the toxic effects of the oil or they may survive by breaking down by-products from the breakdown of the oil. There are many different species of oil-degrading bacteria, but some have evolved over time to eat oil with a ravenous appetite.”

Some bacteria he describes as “generalists”

Bacter reality: the future of oil spill responseOil-eating bacteria are often the unsung heroes when it comes to oil spill response. We spoke with Heriot Watt Associate Professor Tony Gutierrez about his recent work cracking the genetic code of these intriguing organisms

– they can eat oil in addition to other food substances. But others consume the hydrocarbons in crude oil almost exclusively, eschewing any other potential food sources. “Their genetic capability has not evolved, or it has lost the ability to use sugars and other simple-to-degrade carbon sources, but if you give them oil they will thrive on it, it’s remarkable” he says.

That means that these particular organisms can play a vital role in clean-up operations. While response teams can work to localise the oil on the water’s surface or separate it from seawater to salvage it, “a lot of the oil that enters the ocean either stays there, or it is degraded and ultimately removed by the activities of these bacteria.”

This is the process that occurred during Deepwater Horizon. “Essentially the Gulf of Mexico was like a culture flask for us,” he says. “We went, sampled it and were able to analyse what was actually happening almost in real time over a period of almost 3 months that the oil continued to gush into the Gulf of Mexico.”

“Some have bacteria have evolved over

time to eat oil with a ravenous

appetite”Dr. Tony Gutierrez

July 2016 page 13

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InnovOil

Several years later, and having accepted his current role as Associate Professor at Scotland’s Heriot Watt University in Edinburgh, Gutierrez revisited some of the samples taken from the Gulf. With his colleague Brett Baker, an expert in genome reconstruction at the University of Texas, and postdoctoral researcher Nina Dombrowski at the Baker Lab, he proposed sequencing the genome of these particular oil-eating bacteria to discover more about the genetic pathways that allow them to degrade the various hydrocarbons in the Macondo oil that gushed into the Gulf.

Gene geniesCrude oil, of course, contains many different chemical hydrocarbons, from long saturated chains through to the more toxic polycyclic aromatic hydrocarbons (PAHs) and then heavier asphaltenes and resins. Through genetic sequencing, the researchers were able to identify pathways used by some of the key bacteria to break down oil during the spill, and in the case of some strains, to

successfully reconstruct almost complete genomes.

“What was interesting is that with some bacteria, like Marinobacter, we found complete pathways for the breakdown of long-chain saturated hydrocarbons. For others, like Alcanivorax, we did not identify complete pathways for the breakdown of PAHs – they had snippets of genes within a complete pathway. This suggested to us that these bacteria are not able to break down the toxic PAHs completely, but they played an important part together with the rest of the oil-degrading bacterial community in degrading these toxic hydrocarbons,” Gutierrez explained.

They also identified which bacteria appeared to work best at different depths. Unclassified members of the group called Oceanospirillales, they found, worked best at degrading alkanes in deep waters where a massive oil plume had formed at around 1,000-1,200 metres depth. Meanwhile, the reconstructed genomes of bacteria such as Rhodospiralles and Cycloclasticus were

responsible for degrading the more toxic polycyclic aromatics.

“We knew that certain bacteria will respond…but we didn’t know how this was co-ordinated. By reconstructing the genomes of these bacteria we’ve discovered [that] the bacteria work as a community to degrade the oil,” he said. “That was interesting. The results show that you can’t just say one bacteria was a major factor.” In their paper, Dombrowski compared the bacteria to an orchestra playing different sequences of a larger piece of music; Gutierrez likened the process to a bee colony, each organism playing its part in a functional hive.

That is not to say that the process is perfect, nor is it justification for a complacent spill response. The waxier asphaltenes and resins remain very difficult to degrade, even for these bacteria, meaning that these substances frequently wash ashore, or may eventually be buried in the sediment on the sea floor.

As with tackling asphaltene and paraffin deposits in industrial settings, there is no

Oil skimming boat collecting oil three miles

north of the source MC 252 (Mississippi Canyon

Block 252) site, Gulf of Mexico, Louisiana, U.S.

June, 20th, 2010

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InnovOil

easy solution for their removal after a spill. Gutierrez is less bullish on the possibility of introducing oil-eating bacteria as part of targeted attacks on these deposits, largely because the existing bacteria will always be better adapted: “Adding a microorganism in order to enhance degradation has been attempted in aquatic systems and on land before, and there have been times where this approach has been effective – but at the end of the day it is better to allow the indigenous microorganisms to do the job. They are already adapted to that environment, so it’s often a matter of trying to enhance their metabolic activities, such as by adding some nutrients, to speed up their biodegradation capabilities.”

Likewise, these bacteria are unlikely to offer any help in paraffin removal in a pipeline or refinery: “In cases like this, often prevention is better than the cure.”

Dispersing knowledgeDispersants pose another problem. Although these chemicals can help to break up hydrocarbons into smaller droplets, thereby increasing the surface area of the oil for the bacteria to attack, dispersants can often be toxic to marine life, including to oil-degrading bacteria. Indeed, the use of some dispersants such as Corexit – as was used in the Gulf – has been criticised because, while effective, its long-term effects are relatively unknown.

Yet Gutierrez noted that: “Our findings suggest that some of the bacteria that responded to the spill in the Gulf may be able to degrade the dispersant Corexit, potentially rendering it ineffective after having done its job.” If so, that may go some way towards mitigating concerns over the long-term impact of such dispersants. However, that may be disputed: another recent study by Samantha Joye, a professor of marine sciences in the US’ University of Georgia reported that in lab tests, Corexit did not aid bacteria as much as may have been thought, and even impaired the growth of oil-eating Marinobacter bacteria.

The potential hazards of dispersants like Corexit highlight the need for greener options. “One thing the oil and gas industry should consider as part of oil-spill contingency plans is the use of bio-based

eco-friendly dispersants. This is something we are working on in my research group,” Gutierrez added.

Gutierrez and his colleagues’ genome research now informs his latest work investigating potential bioremediation plans in the northeast Atlantic. Despite having been an area of oil and gas operations since the mid 1960s, there remains a distinct lack of information on the water column microbiology of the region – a “knowledge gap” identified in the preliminary assessment of the EU Marine Framework Directive. As oil exploration expands into deeper waters (>1,000m depth), such as in the Faroe Shetland Channel (FSC), Gutierrez explains: “My group has been working to produce a baseline of the water column microbiology for the FSC, including an understanding of the presence and activities of oil-degrading bacteria in this region.”

“We are compiling a spatial and temporal microbiological baseline for the FSC, which would be a first in UK waters,” he continued. “The FSC is an area with a very dynamic oceanography. In the advent of a deepwater oil spill in this area, a subsurface oil plume could form in the water column, similar to that which occurred during the Deepwater Horizon oil spill.”

As with the bacterial studies in the Gulf of

Mexico, the group will also be investigating the use and effects of dispersants in the FSC, which could potentially be employed in the event of an oil spill in this region of the Atlantic, with a view to advising UK authorities on those which prove to be most effective and have the least toxicological effects on the natural ecosystem. Gutierrez is a Principal Investigator of a 4.8 million euro EU project to discover novel types of bio-surfactants (aka bio-dispersants) for commercial applications, and he aims to develop his network towards the discovery of natural bio-based dispersants for combatting oil spills and that will pose less of a concern to the environment compared to their synthetic counterparts.

When it comes to oil spills, prevention undoubtedly remains better than the cure. Yet it is encouraging to find that bacteria in the Gulf of Mexico, the FSC and across the world may yet provide new insight into how hydrocarbons are broken down in marine environments, and how best to tackle a spill if it does occur. Indeed, Gutierrez may yet have a few surprising discoveries lurking in his well-stocked freezer. n

Contact:Dr Tony GutierrezEmail: [email protected] Web: www.tony-gutierrez.com

Marine Oil Snow (MOS) formed by the release of exopolymers produced by

oil-degrading bacteria in sea surface oil slicks at Deepwater Horizon. The MOS particulates were stained with

Alcian Blue and shown suspended in a sea of Macondo crude oil droplets

Picture: Tony Gutierrez

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PRODUCTION OPTIMISATION

GET EVOLVED

How NOV is optimising

drillingPage 20

MOBILE INTENTIONSHoneywell on how smart devices are changing operationsPage 18

THE WAITING GAMEHow choking and artificial lift are aiding US producersPage 24

SPECIAL SUPPLEMENT Pages 17-25





















July 2016page 18

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InnovOilPRODUCTION OPTIMISATION

MOBILITY has revolutionised the life of the average consumer, touching every facet of how we live and work. This is exemplified

by the emergence of the smartphone. The rise of these is easy to explain. Providing connectivity on the move in a simple, portable and affordable device, smartphones both embody and shape our modern working and social lives. Adoption is widespread and the smartphone ubiquitous, but in the industrial environment mobility is still an emerging technological force.

The fact that mobility has yet to take hold in the industrial world is, on the face of it, puzzling. After all, industrial environments seem ideally suited for the mobile revolution. There is a whole segment of field personnel such as operations, logistics, warehouse, inspectors, sales, etc., that will benefit hugely from mobile devices. Delivering solutions around those roles is where mobility will go industrial.

Mobility across the Hydrocarbon DomainThe geographical dispersion of upstream assets opens quite a few opportunities for mobile devices. Personnel can use GPS and online maps to locate and identify assets. Historical work order information, performance trends, calibration details and asset attributes are easily pulled in from the central office and served to the ‘connected’ worker. If data from the field need to be captured, it is usually faster and more efficient to do it electronically over a tablet or a smartphone. Moreover, digitally captured data is easily distributed and analysed.

Primary distribution use cases can be around digitising custody transfer workflows, inspecting pipelines, updating and recording inventories, viewing lifting schedules and more. Field personnel in these areas have to follow very specific workflows, capture readings and status, note vessel arrival/departure – and mobile devices should be able to provide valuable efficiencies.

Processing plants are increasingly getting

more complicated and regulated. This translates to a higher degree of inspections, rounds, checklists and traceability. Mobile devices are seeing widespread adoption in these areas, and paper records are quickly being replaced by mobile software. Augmented Reality algorithms are already in use on smartphones to “inform” and “train” on complex equipment and procedures. Mobility is taking the training programme out of the classroom and into the field.

Secondary use cases can be found in areas such as fleet logistics, warehouse management and point-of-sale operations. Distributed and large tank farms with complex receipt and delivery procedures are ripe for optimisation on mobile platforms. Mobile devices are keeping ERP systems updated in near real-time, giving traders invaluable insight into shop floor operations.

Benefits to Industrial UsersAt the level of individual personnel,

mobility is set to enhance capabilities and make life easier. Process engineers are prime candidates. They are not looking at screens

Putting the Smartphone at the Heart of Smart PlantsRohit Robinson, Director of Portfolio Innovation at Honeywell Process Solutions, explores how smart devices will be a necessity as plant and operator become more connected

all of the time and they need to receive and analyse information quickly. Often, process engineers are the first line that can drive work practices to a more efficient band of operations, rather than being within the broad and safe alarm limits. Solutions such as Honeywell Pulse™ can allow them to set their own “watch list” and get alerts on their phones, should a process excursion take place.

This is demonstrated by a recent incident, where a seal rupture was preceded by a 40-minute pressure variance. Amongst all the hundreds of variables being monitored, the odds that someone was looking at that particular one were minimal. However, with a mobile monitoring solution in place, the process team would have received alerts over those 40 minutes, no matter where they were in the world.

Shift and process supervisors, plant managers and HSE directors are groups of people that do not necessarily sit in front of computers, watching process data flow by. And yet, they are accountable for the safety and uptime of facilities. The mobile devices they

July 2016 page 19

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carry are invaluable platforms to keep them informed, in real-time. Once again, smart apps not only inform and provide visibility, but also allow personnel to take action remotely.

With so many potential uses and the value that mobility promises to industrial operations, the obvious question is why do not all personnel use mobile devices? The answer is multi-faceted, with one reason typically offered being the complex and robust nature of the environment in which industrial workers carry out their duties. Plant and process areas require intrinsically safe devices, meaning consumer technology needs to be specifically tailored. That, though, is only a small part of the issue.

Another role that has yet to see the full benefits of mobility is that of the control room operators. While you might not necessarily assume these workers need mobile solutions, being confined to a control room with plenty of capabilities and displays, it is worth highlighting the sheer size of many modern control rooms. It is not uncommon to see rooms so large that operators need mobile devices, such as a tablet, to maintain visibility into the process. In response to the shifting layout and nature of control rooms, systems are evolving accordingly and increasingly support mobile solutions.

Challenges to AdoptionWhile there are some challenges at a role-by-role level, there are deeper concerns that perhaps explain why the mobile way of working has yet truly to take hold in the industrial environment. Information

security is often identified as a major concern among leaders. Any mainstream technology, particularly mobile solutions, is viewed with a certain amount of distrust when it comes to industrial cyber security, while there is an idea that connecting more devices to a network brings with it increased risk. A common reaction may be to avoid bringing in mobile solutions entirely in order to secure assets.

However, such a response is in many ways self-defeating, ignoring the many significant benefits promised by a connected plant with truly mobile support, including cyber security. Of course precautions must be taken, but subscribing to cyber services, assessing risks and enforcing sound policies are some of the mitigating strategies companies can put in place. In response to these needs, Honeywell has established cyber security labs and offers full cyber services and solutions such as cyber security profiling, intrusion prevention, device hardening and continuous monitoring.

Getting Your Organisation MobileWhile establishing a mobility platform

within an industrial environment certainly has its challenges, both technical and organisational, a future where plants are more connected and workers more mobile is both an attractive and almost inevitable one. The benefits, both operational and at a business level, are too great for it not to be. However, the industry has been slow to embrace the idea.

Businesses can, however, look to early adopters for best practice, saving themselves many issues. Input from various departments, individuals, business and operations teams

should be solicited actively and time spent in establishing ROI.

The next generation of plant personnel has grown up able to access any information it wants, at any time, fluidly pinching and zooming its way through details on its smartphones. Soon this will be more than a benefit for employees; it will be an expectation. More than the many benefits this will deliver for workers, though, mobility is set to be an important factor in realising the vision of a connected plant and the Industrial Internet of Things (IIoT), where it is not just sensors, pumps, valves and other technology that are connected, but people too.

While the challenges should not be understated, particularly cyber security, they can be overcome. Meanwhile, the industry’s need to develop efficiencies and enhance performance means that such challenges must not be viewed as a reason to ignore or avoid mobility and connectivity. Any organisation that does so risks becoming a modern-day William Orton, President of Western Union, who in 1876 famously said: “This ‘telephone’ has too many shortcomings to be seriously considered as a means of communication.” nYou may contact the author using the details below, or via Honeywell Pulse. While there, feel free to participate in Honeywell’s Mobility Survey and request a copy of the consolidated results.

Contact: Rohit Robinson, Director for Portfolio Innovation at Honeywell Process SolutionsEmail: [email protected] Web: www.HoneywellPulse.com

July 2016page 20

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InnovOil

OPTIMIZATION is never about improving one thing. It should be a comprehensive process, and one which takes into account the

macro-view of an operation as well as a detailed, granular examination of how things can be improved. In drilling optimization, that also means putting together hardware, software, and a wealth of expertise, covering everything from analytics to tool design.

One firm pioneering new techniques for optimization and automation is National Oilwell Varco (NOV). The company has laid claim to being “the only firm in the world that can automate the entire drilling system in-house,” and it does so with some fairly impressive technologies. Offered by NOV’s Dynamic Drilling Solutions (DDS) business unit, the eVolveTM Optimization Service equips existing rigs, rig crews, and engineers with an advanced toolkit that delivers enhanced performance, allows improved real-time decision making, and provides advanced analytics capability.

The eVolve Optimization Service relies on a four-phase optimization approach to enhance drilling performance throughout a project’s life cycle. The process begins with a critical review of key performance indicators and drilling data to provide a better understanding of how to improve drilling system performance. After analyzing the data to identify risk and opportunity, NOV experts build a strategy to deliver on the client’s performance objectives.

Using offset well benchmarks, NOV experts develop a drilling plan, assist in bottomhole assembly (BHA) design, and create drilling parameter roadmaps, which are all supported by a suite of performance optimization software. After mobilizing tools and systems to the client’s rig, the plan

Optimization: The need to eVolveNOV profiles its eVolve Optimization service, which uses dynamic drilling systems and automation technology to improve drilling performance

is executed, incorporating enhanced data acquisition tools.

The DDS business unit is a result of an NOV reorganization in 2014, in which individual technologies and services with regards to drilling optimization and automation were integrated under the same umbrella.

The main contribution came from the Instrumentation, Monitoring, and Optimization business unit, which was previously a part of NOV Rig Solutions and included surface instrumentation like Martin Decker™ and MD Totco™ products for monitoring operations. BlackBoxTM services, which are memory, high-density downhole dynamics sensors, were added from the NOV Downhole business unit to provide the full picture of the drilling system. By adding high-speed telemetry drillpipe from the IntelliServTM business unit, real-time measurements from along-string and downhole tools can improve monitoring of weight transfer, rotation, torque, pressure, temperature, and vibrations. This will ultimately provide better data for a smarter decision-making process, increase efficiency, and reduce both operational risk and cost.

INFORMThe fundamental pillar supporting the eVolve service is data acquisition, and the service’s INFORM offering uses this to provide insight into existing assets. Using the proprietary RigSense™ rigsite information system, a range of sensors provide data on everything from electronic drilling recording to gas detection. In addition to automatically generated reports, NOV’s team can aid operators in analyzing trends, reporting, and data to determine how sites are performing and where improvements can be made, e.g. in

Lateral vibrations at the bit were improved from well 1 to well 2 when the recommended parameter changes were implemented.

Footage and ROP performance on well 2. NOV saved two bit trips on well 2, representing time savings of 3 days.

eVolve led to ROP improvements for an operator in Colombia


Innovation in actionA client operating in Colombia needed to identify and eliminate the source of drilling inefficiencies during their operations and develop parameters for use in subsequent wells. The eVolve team worked with the client to improve performance by using a combination of our products, software, and drilling dynamics expertise.

Using our BlackBox tools in the 12¼-in. section of two of the client’s wells, we discovered that significant damage to the drill bit in the vertical section of a difficult formation was reducing ROP in subsequent formations. Buckling in the drillstring in the tangent section was causing additional nonproductive time, adding two extra bit trips to total depth.

The data acquired from the BlackBox tools allowed us to define optimal parameters and BHA design in the second well. These recommendations led to reductions in equipment damage, MSE, and buckling, in turn improving ROP by 23%.

eVolve Optimization Service improves ROP by 23% in demanding Colombia application

TechnologyNOV’s eVolve™ Optimization Service delivers complete, integrated, and innovative drilling technologies to solve our clients’ complex drilling problems. The eVolve team delivered a solution from the ADVISE tier, a data-driven optimization service incorporating our BlackBox™ memory-mode logging tools, to optimize the client’s drilling operation and increase performance.

PerformanceOur BlackBox tools were run in the 12¼-in. section of two of the client’s wells for both the vertical and curve sections. In the vertical section of the first well, where a challenging formation was characterized by massive chert, the drill bits suffered significant mechanical damage, leading to low ROP on subsequent formations. The eVolve team used BlackBox tools at the bit and in the bottomhole assembly (BHA) to help identify the optimum parameters for drilling through this difficult section. Buckling in the drillstring was also identified as an issue on the tangent section, which led the eVolve team to recommend the use of a hybrid string to mitigate the dysfunction.

Results Upon completion of the second well, the client noticed that they were experiencing normal drill bit wear (Well 1: 0-4-BT-A-X-1-CT/LT-PR versus Well 2: 1-2-WT-S-X-I-CT-PR) while drilling the more difficult formation due to implementation of the eVolve team’s recommendations. Similarly, the mechanical-specific energy (MSE) in that formation was approximately 41.5% lower that in the first well. The push pipe significantly reduced buckling while rotating, and at the end of the section the client improved ROP by 23% and saved one bit.

Figure 1 – Lateral vibrations at the bit were improved from well 1 to well 2 when the recommended parameter changes were implemented.

Dynamic Drilling Solutions | eVolve™ Optimization Service Case History

Figure 2 – Footage and ROP performance on well 2. We saved two bit trips on well 2, representing time savings of 3 days.

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[email protected] nov.com©2016 National Oilwell Varco. All rights reserved. NOV-DDS-CH-1462-001

Innovation in actionA client operating in Colombia needed to identify and eliminate the source of drilling inefficiencies during their operations and develop parameters for use in subsequent wells. The eVolve team worked with the client to improve performance by using a combination of our products, software, and drilling dynamics expertise.

Using our BlackBox tools in the 12¼-in. section of two of the client’s wells, we discovered that significant damage to the drill bit in the vertical section of a difficult formation was reducing ROP in subsequent formations. Buckling in the drillstring in the tangent section was causing additional nonproductive time, adding two extra bit trips to total depth.

The data acquired from the BlackBox tools allowed us to define optimal parameters and BHA design in the second well. These recommendations led to reductions in equipment damage, MSE, and buckling, in turn improving ROP by 23%.

eVolve Optimization Service improves ROP by 23% in demanding Colombia application

TechnologyNOV’s eVolve™ Optimization Service delivers complete, integrated, and innovative drilling technologies to solve our clients’ complex drilling problems. The eVolve team delivered a solution from the ADVISE tier, a data-driven optimization service incorporating our BlackBox™ memory-mode logging tools, to optimize the client’s drilling operation and increase performance.

PerformanceOur BlackBox tools were run in the 12¼-in. section of two of the client’s wells for both the vertical and curve sections. In the vertical section of the first well, where a challenging formation was characterized by massive chert, the drill bits suffered significant mechanical damage, leading to low ROP on subsequent formations. The eVolve team used BlackBox tools at the bit and in the bottomhole assembly (BHA) to help identify the optimum parameters for drilling through this difficult section. Buckling in the drillstring was also identified as an issue on the tangent section, which led the eVolve team to recommend the use of a hybrid string to mitigate the dysfunction.

Results Upon completion of the second well, the client noticed that they were experiencing normal drill bit wear (Well 1: 0-4-BT-A-X-1-CT/LT-PR versus Well 2: 1-2-WT-S-X-I-CT-PR) while drilling the more difficult formation due to implementation of the eVolve team’s recommendations. Similarly, the mechanical-specific energy (MSE) in that formation was approximately 41.5% lower that in the first well. The push pipe significantly reduced buckling while rotating, and at the end of the section the client improved ROP by 23% and saved one bit.

Figure 1 – Lateral vibrations at the bit were improved from well 1 to well 2 when the recommended parameter changes were implemented.

Dynamic Drilling Solutions | eVolve™ Optimization Service Case History

Figure 2 – Footage and ROP performance on well 2. We saved two bit trips on well 2, representing time savings of 3 days.

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[email protected] nov.com©2016 National Oilwell Varco. All rights reserved. NOV-DDS-CH-1462-001

July 2016 page 21

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InnovOil

Optimization: The need to eVolve

communication, training, or well planning.INFORM is supported by NOV staff at the

RTTC. This is an advanced monitoring and advisory support centre for drilling, drilling optimization, and rig operations around the world. The RTTC provides remote support from NOV experts, who work around the clock proactively monitoring and analyzing real-time drilling data to optimize the drilling environment. The DDS business unit relies on the RTTC as its analytics hub for all drilling data. As a vital part of the eVolve Optimization Service, the RTTC stores and analyzes data while drilling to support operations. RTTC services vary with the different tiers of eVolve service, ranging from tools/systems information that facilitates more informed decision making to being actively engaged with rigsite personnel and drilling contractors.

This effective data acquisition produces results. For one Australian operator, using a combination of the RigSense system with an NOV technical team meant uptime was increased to more than 99%.

ADVISEThe ADVISE tier optimizes the drilling process using downhole data, with a particular focus on improving efficiency and reducing costs. Using NOV hardware and software in tandem to examine existing information and collect surface and downhole data, the project team can identify and address potential challenges.

NOV’s BlackBox enhanced measurement system (EMS) tools are central to the ADVISE tier. The BlackBox tool is based on a compact, flexible design, allowing measurements to be taken in the BHA or drillstring. The collar-based memory-mode logging tools can then capture a wide array of

measurements including multi-axis vibration, load, pressure, torque, and rotation.

Combining analysis on known rock properties and formation characteristics, the team can use data collected from the drilling equipment to provide formation and depth parameters, giving operators a roadmap for how, where, and how fast they should be drilling. In addition, they can make recommendations on BHA design and component use to ensure the process is fully optimized.

The analytical power of the RTTC and BlackBox data acquisition also supports full post-well analysis from the combined surface and downhole memory-mode measurements, allowing operators to compare against set benchmarks and ultimately reduce well costs.

For one client in Colombia, data acquired from NOV helped navigate a particularly challenging formation which had damaged the drill bit and reduced the rate of penetration (ROP). Data acquired from the BlackBox tools allowed NOV to set optimal parameters and redesign the BHA in a second well, leading to a reduction in equipment damage, less buckling and mechanical strain, and a 23% improvement in ROP.

CONTROLThe third eVolve tier uses NOV hardware and software to improve the accuracy and quality of drilling data, reduce drilling dysfunction, and streamline the process of drilling.

The StringSenseTM integrated drillstring measurement system (instrumented IBOP) provides measurements for direct drillstring tension and compression, drillstring torque, RPM, bending moment, and internal pressure immediately below the topdrive’s main shaft, transmitting the data wirelessly to a surface receiver system. Accurate drillstring tension

and torque data via direct measurements can help reduce the risk of parting strings, extend drilling envelopes through improved torque and drag models, and improve drilling equipment efficiency.

This high-density surface data feed could also enable NOV’s DrillSharkTM drilling application for optimized ROP or mechanical specific energy. The DrillShark service automatically and consistently adjusts drilling parameters by changing drawworks position and topdrive speed.

Data-driven control features can help mitigate some of the major problems faced by drillers, such as stick-slip oscillation. These are severe, self-sustained periodic fluctuations of drillstring torque and rotational speed, driven by downhole friction, which typically result in large variations in bit and BHA speed.

Another technology included in the Control tier is NOV’s SoftSpeed™ II stick-slip prevention service, which is an analytics platform that can automatically detect and prevent oscillations to optimize efficiency and reduce equipment wear. This passive system is activated on demand by the driller and continuously identifies, quantifies, and alerts the user of torsional vibrations. If the indicator on the driller’s control screen shows stick-slip, the SoftSpeed II system can be activated and the auto-tuning feature enables the speed controller to optimal damping.

In one Oklahoma drilling operation, an eVolve project team recommended the SoftSpeed II system. Using the SoftSpeed II system enabled the operator to increase ROP by an average of 61%. When compared to the two offset wells, this resulted in a cost savings of more than US$100,000.

AUTOMATENOV’s technical expertise culminates in the eVolve service’s foremost tier, AUTOMATE. NOV uses the world’s first application of closed-loop, downhole data to drive NOV’s rig control systems. The package links sensors, automated controls, hardware, and software via high-speed telemetry to manage optimal drilling efficiency.

One particularly powerful application is NOV’s IntelliServ network, a wired drillstring

The eVolve service begins a with critical review of key performance indicators and drilling data


July 2016page 22

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and component suite which combines data measurement, acquisition, and secure transfer. The wired drillstring’s high-speed data transfer translates into major time savings, transferring surveys, downlinks, and slide orientations in seconds rather than the minutes taken by conventional telemetry. High-frequency, low-latency data also allows more responsive control of directional control, well placement, and hole cleaning, all of which contributes to higher ROP.

As previously mentioned, NOV’s DrillShark automated drilling service also uses adaptive algorithms and remote monitoring to automatically adjust drilling parameters. When combined with rig instrumentation, a multiparameter autodriller, and an advanced rig equipment control interface for automated adjustments to topdrive setpoints, the Drillshark service optimizes energy use during drilling to reduce bit wear and BHA vibration. The input could be high-density surface data; however, with use of IntelliServ high-speed telemetry, the drilling application will run on data streaming live from downhole.

In one operation for a North Sea operator, the AUTOMATE service—in particular the BlackStreamTM and IntelliServ technologies, which gathered data and measurements along the string—enabled a far greater understanding of downhole conditions. While operators have typically relied on estimates of equivalent fluid density calculated via annular pressure measurements

and hydraulics models, the BlackStream tool provided accurate along-string data in real time, removing a great deal of uncertainty and enabling better decision making. This resulted in reservoir drains being extended due to improved downhole pressure control in narrow mud weight window application. Target production was therefore met after completing three oil producing wells instead of the planned four wells. Approximately 70 days of operation were cut from the drilling campaign with the cancellation of the fourth well.

As with the other eVolve tiers, the AUTOMATE offering is supported via real-time remote monitoring and expertise from the RTTC.

When it comes to hardware and software, technical solutions are continuously developed and improved to accommodate industry challenges. The increasing amount of real-time downhole data available confirms the need for a robust IT infrastructure as well as quick visualization solutions for an accurate overview of wellbore status updates. IntelliServ wired drillpipe telemetry allows for 57,600 bps data transmission. When compared to today’s mud-pulse telemetry at approximately 20 bps, the possibilities are significantly increased for “turning the light on” downhole as opposed to conventional models and their uncertainties.

The full closed-loop automation system is currently being run with good results in land operations. Significant savings

have been achieved by operators, which includes eliminating days in drilling time due to improved performance based on true downhole measurements. In addition to the “drill faster” concept, automation technology also delivers more consistent performance, easing the planning process for both equipment delivery and budgets.

For offshore operations, NOV is looking at a different approach—a “drill smarter” concept is introduced for improved value from improved geosteering and wellbore placement, leading to enhanced production.

The eVolve Optimization Service is currently supported throughout NOV locations worldwide, and the different levels of service are offered dependent on the specific application and its needs. Rig compatibility and scope of deliverables will therefore be a deciding factor to any service cost. However, the above examples from eVolve projects clearly show a gain in performance as well as cost savings greater than the investment. Different business models for OPEX or CAPEX are also available for all levels of services as the DDS business unit adjusts to client requests. n

Contact: Mats Andreas Andersen,DDS Services Director, EuropeNOV Dynamic Drilling SolutionsTel: (+47) 918 606 71Email: [email protected] Web: www.nov.com/Segments/Wellbore_Technologies/Dynamic_Drilling_Solutions.aspx

The CONTROL tier uses NOV hardware and software to improve the accuracy and quality of drilling data

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INTELLIGENT SOLUTIONS FOR OIL AND GAS PRODUCTION

km.kongsberg.com/offshoreproduction

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IN the beleaguered US shale industry, production optimisation techniques are being scrutinised more closely than ever. Yet technology which can aid the so-called

“waiting game” – holding production at certain levels until a rise is needed – is also catching industry attention.

Interest has grown in techniques which can flatten the production curve of shale wells. As well as improving ultimate recovery volumes, these can also help limit damage to the well, to local wells and to the reservoir, which can be depleted too quickly, especially with shale wells’ famously rapid rate of decline.

These techniques, such as the use of chokes to preserve pressure, can also allow a producer to leave oil or gas in the ground until commodities prices rise. This is especially useful if there is too little midstream infrastructure, such as in the Marcellus formation.

US oil and gas production may have decreased because of the oil rout, but that has been almost entirely offset by a very dramatic rise in per-well production in shale plays. In fact it has surely been what Andrew Grove, co-founder of Intel, would have described as a “strategic inflection point” – when a major change occurs in an industry’s competitive environment.

For example, in the Eagle Ford shale play in south Texas, production has risen by a factor of four in the last five years as a result of improved hydraulic fracturing completion practices, Professor Mukul Sharma of the Department of Petroleum and Geosystems

Engineering at University of Texas, Austin, explained to InnovOil.

Moreover, since 2014, there has been a 12% improvement in production efficiency because of high-grading – finding the best places to drill – and 10% because of in-field improvements, according to consultancy IHS. “So we are more efficient, though production may decline,” said Reed Olmstead, the group’s manager of North American supply analytics in plays and basins. “Had the industry not become more efficient, it would have either spent more money, or production would have declined more, or both,” he added. “US$100 oil covers a lot of mistakes.”

Hurry up and waitTwo in-field techniques that have received much recent attention in shale are artificial lift and choking. “Proper design of artificial lift and proper choke management can increase production by 50-100%,” Sharma estimates.

Artificial lift to maximise output and extend the life of wells has been employed for decades in conventional wells, but it is

Shale producers optimistic on optimisationStressed US shale drillers are finding solutions to precipitous production curves. Ros Davidson explores the latest choking, artificial lift and gas technologies which are helping them play the “waiting game”

no trivial matter to use it successfully in horizontal wells, he continued. The uneven flow in fracked wells tends to cause problems for artificial lift when it is installed after six to 12 months. Liquid can pile up, for example, if lift is not performed correctly.

Concerns over how to install pumps, what kind of lift techniques – e.g. gas lift or electrical submersible pumps – are vital, given the variation in geometry and volumes of fluid in a fracked horizontal well compared to a vertical well, Sharma explained. With pressing demand, he added that most service companies were apparently working on new downhole pumps, including Schlumberger, Weatherford and Halliburton.

There is an art to integrating artificial lift with well and reservoir design. A vertical

Professor Mukul Sharma


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section can be created at the “heel” of a horizontal well, for example, to create a sump so that liquids can be lifted more easily, Sharma said. About half a dozen companies, including the aforementioned service majors, are working on this specific issue.

One of the greatest challenges with artificial lift design is predicting multi-phase flow calculations, which can be so imprecise they are off by a factor of two to three, he noted. PipeFractionalFlow, a spin-off of Sharma’s research team at the University of Texas, has just commercialised software for multi-phase flow modelling that he claims can improve predictions to within 15-20%.

For some, artificial lift has been a port in a storm. Baker Hughes said that its artificial lift business was the “one notable exception”

to an oilfield services sector-wide slump in the first quarter of 2016, growing by 4% even as other shale-related revenues fell 10%. The economic argument is persuasive for shale drillers who can afford it – while drilling and fracking a new well can cost several million dollars, a US$250,000-500,000 artificial lift programme can push production back to 50-75% of its initial rate, Evercore ISI analyst James West explained to Reuters in a recent report.

Choke checkAnother method of flattening the curve is choking – essentially restricting hydrocarbon flow with control valves – a process used to some degree on most wells. A major realisation in the last two to three years

is that if a choke is properly managed, it “significantly” improves shale well production over the short and long term, Sharma said.

Yet choke management when well production is increased or brought back on line is tricky. Do you open it up quickly or gradually? Sharma’s team has developed Choke Manager, a combination of software and a general methodology designed to help determine the best choke strategy for a producer to maximise oil recovery. In the last few weeks, it has been made available for testing to two industry partners, who are operators, and it is now being marketed to service companies.

More aggressive choking has been employed in the Marcellus by Chesapeake, where the first-year well decline rate is


Gas rig in the Marcellus shale

Below: Baker Hughes’ CENesis PHASE multiphase encapsulated

production solution

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example, laterals have doubled in length, to say 10,000 feet (3,000 metres), compared to a few years ago.

There is also interest in increasing the use of microseismic data and 3D seismic data, said David Burnett, director of technology at the Global Petroleum Research Institute, Department of Petroleum Engineering at Texas A&M University, in an interview with InnovOil. In addition, there are even newer techniques such as two-screw multi-phasic pumping, which over the life of a field can help accommodate fluctuations in oil well viscosities, water cuts, gas-to-liquid ratios and gas volume fractions. Burnett listed Colfax Fluid Handling in particular as one provider of the technology.

Flowback water recovery is improving, and recycled frack water is being increasingly used in as many as 30% of wells, said Burnett. This has helped the economics of some gas fields in the eastern US, where water disposal is especially costly. One recent study suggests that, based on field data, only 2-26% of fracture fluid is recovered during flowback in Marcellus shale wells in West Virginia.

Flat lines, for taking water to the wellhead,

50-60%, says IHS’s Olmstead. Continental Resources is also using more aggressive chokes at three news wells in the STACK play in Oklahoma.

The Haynesville shale has an especially dramatic decline rate of 70-75% in the first 12 months. Aggressive choking there can be inferred from changes in an operator’s decline rates. Encana, which has gone from about 80 to 10 wells in the play, has changed its average decline rate from 68% to 28%, according to IHS data. Exxon/XTO’s has declined from 52% to 39% in the Haynesville, whereas BHP and Anadarko’s have stayed relatively flat, Olmstead added.

Lateral limitationsUnconventional well design is generally taking strides forward. Should it be toe up or toe down, should the bore tilt up or down and should it be drilled in the middle, bottom or top of the pay zone? How much fluid and sand should be used; should the fluid be more viscous or less so; how fast should the fluid be pumped? There are perhaps two dozen variables that can be adjusted.

In many ways, hardware, downhole tools and chemicals have been improved. There is the well-known use of longer laterals, more fracking stages and proppant loading, the use of slickwater – and thus there is less reliance on pricey chemicals and a better environmental outcome – and sliding sleeves during fracking, such as those made by Schlumberger.

“Wells continue to improve because of longer laterals and proppant loading. However, the rate at which they’re improving is starting to even out, as the industry is largely reaching the limits of the benefits from those practices,” said Olmstead. For

reaching up to half a mile per coil, are being used. Flare gases are being collected and monetised – and emissions are reduced – and there is a strong push to use liquid nitrogen and/or CO2 in place of water and chemicals for fracking. The technique has gained particular support from Air Liquide.

In addition, a dynamic gas-blending kit designed by Caterpillar Global Petroleum allows for the use of natural gas instead of substitution of diesel fuel during high-pressure pumping for fracking, with Burnett estimating that around 25% of companies are considering such an investment.

With prices under pressure but looking relatively stable for now, the focus on optimisation is unlikely to retreat in the short to medium term. With proven interest from service companies, one can be sure that a new wave of improved choking and lift equipment is already in trials, as producers pursue an even flatter shale curve. Indeed, as Deloitte Centre for Energy Solutions director Andrew Slaughter predicted in a recent Reuters interview: “The low price environment will give companies and operators a chance to take stock of the techniques that work… Production optimisation is going to be the next phase of the shale revolution.” n

Caterpillar Global Petroleum’s Cat Gas Blending equipment

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IN October 2014, Repsol and IBM announced an intriguing collaborative research programme linking digital cognition technology with oil and gas E&P.In a press release at the time, the two

firms noted that they would focus on the development of “two prototype cognitive applications specifically designed to augment Repsol’s strategic decision-making in the optimisation of oil reservoir production and in the acquisition of new oilfields.”

Speaking with InnovOil this month, Repsol exploration and production technology director Santiago Quesada explained their intention “to create a new frontier for our industry.”

Linking the work of IBM’s Cognitive Environments Laboratory (CEL) in New York with Repsol’s Technology Center in Madrid, the project aimed to improve the interaction between personnel and computer technologies by enabling faster and more efficient sourcing and processing of data. The objective was to develop a cognitive system which could search vast amounts of information – from seismic data and production reports to breaking news – in response to specific queries asked by E&P staff.

Using natural language processing, the computer is able to search documents and generate reports and simulations based on these queries, all of which should help the decision-making process become faster and more efficient.

Role modelThe system also enables interaction with Repsol’s existing digital technologies. Programmes such as Kaleidoscope – a seismic data-crunching system – and Excalibur – a predictive mathematics tool used for field optimisation – have proved transformative in recent years. Quesada added: “Repsol has a long tradition in the development of advanced geomodels and innovative tools for fluid prediction, especially with the

incorporation of uncertainty in the models. The value of the cognitive systems is centred in augmenting our capabilities for the technical development of these models and the proper characterisation of uncertainty and risks.”

Quesada suggested that this technology represented a great deal of change in terms of how personnel interact with big data and the process of E&P in general. These systems, he said, will “augment human capacity in a tremendous way”, though he stopped short of agreeing that it would represent a major change in how the company works.

When asked about any interesting or unexpected results, he was similarly partially drawn. “In R&D there are always surprises, unexpected results and also failures. A disruptive science like the Cognitive Science is being invented every day and running fast. Our project is alive and continuously adapting to all these new ideas and technologies.”

Smart thinking – cognitive computing with RepsolRepsol and IBM are jointly developing cognitive technology to aid E&P. We spoke with Repsol exploration and production technology director Santiago Quesada to find out more

And alive it is. With plans to roll out a number of pilots across all of Repsol’s operating regions during 2016, its commitment to cognitive potential is impressive. Quesada added: “In 2016 we are working on the implementation of early results of the cognitive research in our tools, and especially in the applications for the optimisation of our Field Development Plans. Simultaneously we are planning to extend our learnings to other areas of our industry like Downstream.” By the end of 2017 the company hopes to have a full cognitive system in place to help in the acquisition of new licences.

Most encouragingly, these are not vanity projects. Repsol’s focus on big data, modelling and analytics is set to continue despite low oil prices, and Quesada sees it very much as a core area in terms of the company’s future strategy: “We have no doubt about this. This science has come to stay and will represent one of the major drivers of the future R&D of our industry.” n

Repsol’s Kaleidoscope programme

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TOP and bottom, costs continue to exert pressure on company lines. Nevertheless, May’s OTC in Houston proved that innovation

is still alive and kicking in start-ups and services giants alike. Paying particular attention to the industry’s innovative mood was Lloyd’s Register (LR) which, alongside urging firms to re-think their approach to technical innovation, performance and safety, also surveyed conference delegates for their thoughts on how these cost pressures might be relieved.

Perhaps unsurprisingly, technology was a major factor in most strategies. As LR’s commercial development director, Duco de Haan, commented to InnovOil: “When a business has exhausted all the options to take out cost, technology is the only thing that can make quantum leaps in cost reduction… We are entering a new era where disruptive technologies can transform an industry in need of modernisation.”

The trends we observed in the oil and gas business and further afield are borne out by LR’s findings. More than 43% of its survey respondents considered the adoption of new technologies – including additive manufacturing (3-D printing) and the use of unmanned robotics – to be the primary issue facing the sector.

Unmanned aerial vehicle (UAV) or drone technology in particular is booming. Simplifying and reducing inspection times on offshore oil rigs, “A flood of new start-ups specialising in this work are entering the market and a host of oil majors are already using the technology,” de Haan pointed out.

Alongside adopting new technologies, 17% of respondents also noted the importance of bringing in technology from other industries, 16% saw increased collaboration to be most crucial and 13% believed that new data rationalisation and interpretation techniques were of greatest value. A smaller, yet encouraging 11% of those surveyed

still had their eye on the next generation of workers, pointing to the necessity of education initiatives for graduates and new industry entrants.

Industry executives, meanwhile, have not disregarded the need to find new sources, evidenced by the top three ranking of the necessity to “improve access to potential reserves.”

Yet given ongoing cost pressures, technology development has to be smarter too. LR global communications manager

Jason Knights added: “Collectively, we all need to look harder at technology to help solve many of the issues highlighted at OTC Houston. This is why we are beginning to see new mergers and joint ventures start to take shape, as the cost for innovating and creating new operational efficiencies can be shared.”

No shortage of ideasOne theme to emerge from Lloyds Register’s earlier 2015-16 Oil & Gas Technology Radar survey (taken last year), is that pure idea generation within the industry does not pose problems. Engineers and technologists are, thankfully,

full of novel suggestions. The greatest problem here lies in realising the results.

According to its survey findings, most

The next quantum leapLloyd’s Register Energy offers its thoughts on OTC 2016, and the current state of industry innovation

companies actually rate themselves as better than their peers at conceptualising and developing new technologies, yet many see themselves as average or below-average at deploying them. As a result, 67% of those surveyed felt that the challenges of deployment were a key barrier to innovation.

While the “race to be second” is nothing new, its effects are particularly felt during a downturn, when industry demands cost-reducing technology but seems reluctant to implement it. Addressing this deployment bottleneck will be vital if any progress is to be made.

To do that, we must understand the problem. Knights explained: “There is evidence of a disconnect between the ‘accepted’ solution and current practice. The increasing complexity around ‘idea generation’ through to ‘deployment’ can be risky, as these technologies can be both emerging and unproven on a large industrial scale.”

Some risk assessment and development methods – LR points to the Technology Qualification route – can help balance readiness against the investment needed, although the latter becomes even more difficult with the increased volatility of oil prices.

Collaboration presents major opportunities to dilute these risks, but the industry has still been slow to react. Knights added: “Collaborators share risk and resources, but they also share

“We are on the cusp of a

radically smarter, technically advanced industry”Duco de Haan

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intellectual property, competitive advantage and, crucially, returns. For these reasons, collaboration remains the exception rather than the rule throughout the sector, although there are recent examples that suggest this may be changing.” From InnovOil’s perspective, addressing these issues and working to pool resources and expertise better will be the only things which can help reduce deployment times.

De Haan is positive on this potential: “There are very positive examples of collaborations across the sectors, as joint industry projects and technology development tie-ups exist across the value chain. Collaborations are often between oil majors and service providers, but there are also instances of oil majors working together (for example, the Marine Well Containment Company, formed by ExxonMobil, Chevron, ConocoPhillips and Shell in the wake of the Macondo oil spill).”

Another example is Denmark’s Optimising Oil Production by Novel Technology Integration (OPTION). This 3.9 million euro (US$4.4 million) project, funded by the Danish InnovationsFonden, is focused on integrating and optimising reservoir and horizontal well simulation models to enhance oil production and recovery. This is valuable stuff – even a 1% increase in oil recovery from Danish fields would represent a value of around 8 billion euros (US$9 billion) to the Danish economy. “Imagine taking this concept to other fields,” Knights added.

Not invented hereIf the industry struggles to deploy ideas it creates itself, there are equal or greater issues in importing innovation from other sectors. So far, Knights said, these crossover technologies have gained “limited traction” but hold a wealth of potential, especially in surveying, modelling, drilling and monitoring. He went on to cite a number of areas of interest, including: “Imaging technologies, advanced lightweight and corrosion-resistant materials, remote inspection, nanotechnologies, data mapping, advanced data analytics, cardiovascular-type pump technologies, additive manufacturing, underwater autonomous vehicles, sensors, super insulation and carbon fibre.”

Encouragingly, InnovOil has seen more external innovation entering the oil and gas periphery. Better still, events such as OTC, Offshore Europe and others are recognising the need to bring in voices from outside the energy industry, seeking insight from the aerospace, automotive, ICT and medical industries as well as further afield.

“In the early stage of the downturn, there was less motivation to drive change because of the high financial risk of something going wrong,” de Haan explained. “But we are now on the cusp of a radically smarter, leaner, technically advanced industry driven by a growing change in mindset – and an understanding that excellence through shared innovation keeps development costs down”

“If the present conditions hold, then

efficiencies have to be looked at without downgrading on safety issues. Technology is an enabler and should be a constant focus. If you look at the business challenges we face today…you realise industry needs to embrace technology faster and sooner, and become smarter at improving ways of operating to remain competitive in today’s tough market.”

LR’s message at this years’ OTC was an urge to sharpen companies’ focus and to encourage them to share knowledge better. For many, that adjustment may seem alien, but it is a necessary change. De Haan added: “It will mean new ways of working, new collaborations and how we think about different disciplines. New technologies bring improvements, but many also bring new limitations, which require engineers to revisit accepted risk management techniques, develop their standards, procedures and methodologies, and apply their experience in new ways.”

Ultimately, the consequences of stasis are far greater than the risk of disruption. As de Haan concluded: “If we continue to do things exactly as we have been doing, we will fail to meet the challenges of today and tomorrow. After all, tomorrow is not more of the same, so we must find new ways to do things.”n

Contact:Jason Knights Tel: +44 (0)20 7423 1741Email: [email protected] Web: www.lr.org/en/energy

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DISCOVERED in 2008, Culzean is the largest gas field to be developed in UK waters since Marathon Oil’s East Brae field got the go-ahead in

1990. Located around 240 km off the coast of Aberdeen, the US$4.5 billion development was approved by the UK Oil and Gas Authority in August 2015, and is estimated to contain recoverable resources of between 250 and 300 million barrels of oil equivalent.

Production is due to start up at Culzean in 2019, and is predicted to continue for at least 13 years. When it reaches peak output in around 2020 or 2021 it could be producing enough gas to cover 5% of all the UK’s demand, with forecast plateau production put at 60,000 to 90,000 barrels of oil equivalent per day. Maersk Oil UK operates the field with a 49.99% stake, alongside its project partners BP (as Britoil, (32%)) and JX Nippon (18.01%).

The project reached a key milestone at the end of last month when offshore engineers Sembcorp Marine handed over the high-spec jack-up Maersk Highlander rig to Maersk Drilling. Singapore-based Sembcorp had originally begun building the new rig for Hercules Offshore at its Jurong Shipyard, but Maersk later acquired it in a deal worth US$190 million.

Based on the Friede & Goldman JU 2000E design, the Maersk Highlander is a heavy-duty offshore drilling unit that will be well suited for the harsh operating conditions that come as standard in the North Sea. It can operate in water depths up to 120 metres, and

drill down more than 9,000 metres. Other main characteristics include a 2 million pound (900 tonne) drilling tensile capacity, and a 28,000 kip (12,700 tonne) preload capacity for the legs.

What really sets the rig apart, however, are high-tech communication facilities that are designed to help it run more efficiently with a minimum staff. This in turn will reduce operational costs at a time of low oil prices when margins are being squeezed.

Safety firstOne major incentive for basing more staff onshore and fewer offshore is reducing the number of helicopter flights needed to ferry

workers to and from the rig. This will not only mitigate safety risks – helicopter transportation is often regarded as the single riskiest piece in the North Sea oil and gas jigsaw – but will also bring significant cost savings of its own.

Maersk said fully automating Culzean would not be practical, however. “Because of the nature of dry tree high-pressure, high-temperature

(HPHT) developments, [full automation] would come with a number of unique challenges, and regular human intervention is required in a number of areas, especially later in well life,” project director Martin Urquhart said. “As such, we have embraced technology that ensures we instead minimise the number of people offshore. This will allow positions that would traditionally have been on the platform to be onshore, working in a real-time collaborative environment.”

High-tech comms for Culzean rigAs Maersk Oil’s Culzean development starts to take shape, Tim Skelton looks at the technological highlights that will make this high-pressure, high-temperature (HPHT) mega-project one of the most advanced set-ups in the North Sea region

According to Maersk’s estimates, offshore operators spend up to 30% of their time looking through worksheets, specs and procedures in order to find the data required to perform each task. The company believes that introducing better data management to make this information available instantly will significantly cut down on this “lost time.”

The key is to use an already widely available technology. Radio Frequency Identification (RFID) tags will be attached to all critical equipment on the platform. When scanned using a regular handheld device such as an iPad or a tablet, the tags will provide the operator with access to all the relevant information associated with that piece of equipment, from manufacturing data and certificates to drawings and maintenance history – even a video simulation showing maintenance and operations activities. Routine maintenance work can be carried out by staff running through a checklist on their tablet, and completing the required

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“We have embraced

technology that ensures we

instead minimise the number of

people offshore”Maersk

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procedures as and when prompted.The platform will also be linked to the

mainland via a high-capacity broadband connection, which the company said would enable faster and better decision-making. “The volume of data our smart platform will generate demands a subsea fibre-optic cable, which allows for instant distribution of critical data. It will mean we can benefit from [both] our own and key equipment vendor’s global expertise without the need for these experts to be physically offshore,” Urquhart said.

Thanks to this high-speed communications network, any areas of non-compliance can be flagged up instantly and synchronised with a master data set onshore, and automatic notifications can be sent to the relevant operations support and management teams, both onshore and on the platform. When any piece of equipment encounters a problem, one of the platform workers simply has to take a photo of it with their tablet. At

a stroke the onshore maintenance team can then retrieve the entire history of the problem part, find out where and when it was made, and learn what previous maintenance has been carried out on it.

For more complex issues, a permanent video conference link will allow onshore and offshore teams to talk to each other face-to-face whenever needed. The onshore experts can then assess the best course of action more quickly, and can discuss this with both the equipment manufacturer and the offshore team. Any required actions can then be assigned a priority level depending on how critical the equipment is, and closure will be tracked using conventional reporting dashboards.

Integrated system“The aim is to tie everything together,” said Culzean’s Engineering Manager, Stuart McAuley. “One of the biggest challenges offshore today is that you spend a lot of time

finding the right data. What we plan for Culzean is that if something breaks or a valve needs replacing, you will have instant access to the data required whether you are on the worksite, office or the other side of the world.”

Not only can these technological tweaks allow more positions to be based onshore, but routine maintenance and the ordering of spare parts can also be planned far more effectively. As a result, Maersk hopes to improve efficiency by 20% in man-hour terms compared to other comparable developments. Cost-wise, it is looking to save more than US$10 million per year.

“The full potential is still being mapped out, but in terms of managing quality – just in terms of being absolutely certain that the critical component being ordered is exactly what you need every single time – that alone is going to reduce unplanned downtime and that means better production efficiency over the coming decades,” McAuley concluded. “And that cash flow really adds up.” n

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The Maersk Highlander rig

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EOG Resources said recently that it had completed the first commercially viable enhanced oil recovery (EOR) test in a US horizontal

shale reservoir. The Houston-based shale producer, like other shale drillers, is exploring ways to produce more oil at lower costs amid the prolonged slump in crude prices. EOG said it had used a proprietary gas injection system in the Eagle Ford shale, marking a milestone for EOR, which is typically deployed to boost conventional wells, usually by sweeping across contiguous reservoirs.

The EOR project represents a learning curve for EOG, and it remains to be seen whether the process will work in other shale formations, in ways that could change the production profile of the US.

EOG, which claims to be the top oil producer in both the Eagle Ford and in Texas more broadly, said in its first-quarter results update on May 5 that it had been injecting natural gas into mature horizontal wells in the play. The pilot schemes were reported as having generated significant increases in crude production at a relatively low cost. EOG revealed few details of the project, but said that over three years, internally developed testing at four successful pilot projects across 15 producing

wells had demonstrated consistent reservoir responses. EOG said it was planning to add another pilot project later this year that would include 32 producing wells, adding that the technique was not capital intensive but could increase recovery rates by 30-70%.

Costs are limited, as no drilling rig is required. Instead, the process involves the injection of associated gas in order to mix it with oil that has not yet been recovered. This builds sufficient pressure to push the oil mix to the surface. This oil is, at current prices, more valuable than the injected gas, which is cheaper than crude and carries low transportation costs, as it is produced from nearby wells.

The technique appears to be similar to that of companies like GasFrac and later Tioga Energy. The latter firm planned to use a mixture of gelled propane (LPG) and sand to frack wells in New York, circumventing the state’s ban on fracking using water. However, in these cases the technique was used for primary recovery, rather than EOR.

EOG added that production response among these pilot projects had occurred within the first 2-3

EOG turns to EOR in Eagle FordEOG Resources recently announced that it was successfully testing enhancing oil recovery techniques previously considered unsuitable for shale plays, writes Kevin Godier

months – which is not the case in typical secondary and tertiary EOR projects – and had remained steady for longer. This could be a favourable development given the high decline rates of shale wells.

Having a gasEOG’s management has not detailed precisely how the EOR process works in these projects, but it is anticipating a range of benefits from using the technique. According to the company, these include high incremental net present value (NPV) and rates of return on investment, low finding and operating costs, reduced severance tax

rates, lower production decline rates and increased reservoir recoveries.

Like its peers, EOG’s profits have been hit by the oil price since mid-

2014, which has forced companies to scale back drilling and seek cheaper, more efficient ways to produce oil. EOG reported a loss of about US$455 million for the first quarter, following a US$4.5 billion loss for the whole of 2015. Wells Fargo has estimated the company will lose a further US$1.4 billion in 2016.

EOG is attempting to change its course this year by shifting to what Thomas has called premium drilling –

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targeting only those wells that can generate at least a 30% return after taxes at US$40 per barrel oil prices. The company is aiming to become one of the world’s lowest-cost oil producers, capable of hitting triple-digit direct rates of return at a US$60 per barrel oil price. “If history is any indication we will continue to push the oil price needed for triple-digit returns even lower,” Thomas said in a May 6 conference call. He described the shift to premium drilling as a game-changer, adding: “We expect well productivity to improve more than 50% in 2016.”

Thomas added that the EOR work “extends our lead as the low-cost horizontal oil producer”. In the conference call, EOG’s executive vice president of exploration and production, Billy Helms, said that the structural attributes of the Eagle Ford’s “black oil window” – combined with the scale of EOG’s footprint in the play – had been crucial in facilitating the EOR pilots.

“We have long discussed barriers that encase the Eagle Ford and provide vertical containment for completions. This unique feature also plays a significant role in keeping the injection in contact with the targeted reservoir,” Helms said. “The injected gas is thus able to become miscible with the oil in the reservoir and subsequently drive incremental oil recovery.” He said that the

models to date had indicated that additional capital costs only average about US$1 million per well.

What next?Questions remain over whether EOG’s EOR work will give it an advantage over other producers, or drive a new trend in the shale industry, in which wells tend to yield only 4-8% of resources and generally lose 70% of their production in the first year.

Part of the company’s reported success lies in the nature of the shale play, with EOG cautioning that the new EOR method might not work in other formations with different structural properties. It commented: “EOG’s Eagle Ford shale acreage position possesses unique geologic properties ideally suited for the company’s proprietary EOR techniques. These methods require very strong geologic containment that may not exist in most horizontal oil plays.”

Helms, while acknowledging “a significant technical and economic breakthrough”, warned that “rolling out this effort will take time and is dependent on the pace of primary development drilling and field development”.

As yet, there is little clarity on how much of EOG’s shale acreage could benefit from the EOR technology.

The potential of EOR for boosting recoveries in shale formations has been talked up, but the consensus has tended to be that conventional methods do not generally apply to unconventional plays. However, advances in EOR technology may change this in the coming years. Little work has been done thus far by others apart from EOG. Last year it was reported that Statoil was due to test a carbon dioxide (CO2) EOR method in the Bakken play, but no results have been reported from this so far.

In the light of the financial pressure on the US shale industry, the concept of rigless recoveries – and the associated drop in production costs – could generate considerable interest in EOG’s experiment, on which the company is unsurprisingly releasing little information. While it may be the case that the Eagle Ford formation is far better suited to the use of EOR than the Bakken and other shale plays, there has rarely been an oil production technique that is entirely non-transferable.

And in an oil price environment that looks set to remain volatile for the indefinite future, the potential cost advantages of EOG’s initiative will provide some welcome relief to the company if they can be achieved as expected. n

EOG production with EOR

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MONITORING high-powered equipment in remote

locations is tough. If the environment does not present enough of a hurdle, operators have to find monitoring packages hardy enough to withstand transport, rig-up and use. You then need software capable of providing the accurate and timely data needed.

That was the problem faced by Houston’s Lime Instruments when designing and programming its controls and instrumentation technology for their oil well monitoring systems.

The company’s monitoring system is designed to analyse the performance of vital pump components during operation. One of its main product lines is focused on monitoring high-pressure fracturing pumps in well-stimulation applications.

Each fracturing unit typically has a high horsepower diesel engine and transmission mated to a triplex or quintaplex pump. Both the engine and the transmission come equipped with an electronic interface that monitors critical functions and provides diagnostic information as the unit is running. The engine and transmission send out the data they monitor via an SAE J1939 communication protocol.

Prior to Lime’s solution, pumps in the industry did not usually contain more than a couple of discrete sensors that monitored their critical operating parameters. Typically, discharge pressure, RPM, lube oil pressure and lube oil temperature are monitored, each of which is measured with an individual sensor and signal cable that goes back to the main control console.

Lime looked to create a system which

would monitor these functions as well

as several others and transmit that data back to the main control console via the same SAE J1939 controller area network (CAN) protocol. The monitoring system needs to look for data characteristics outside the normal operating envelope and failure conditions. With this real-time information, operators can determine if they should cease operation or continue based on real performance indications from the pump.

Ultimately, this system should reduce the number of pump failures as well as overall pump maintenance costs, saving time and money.

The road to RIOThe final system is based on National Instruments’ (NI) CompactRIO and NI Single-Board RIO hardware, with software designed using the company’s LabVIEW platform. This is used to program the real-time processor, field-programmable gate array (FPGA), and input/output (I/O) for the CompactRIO system. Lime Instruments’ CEO Robert Stewart commented: “Other hardware solutions we considered were not able to provide the high-speed I/O and analysis to catch the momentary pressure spikes and vibration indications of these oil well service fracturing pumps.”

CompactRIO also provides a robust hardware package – vital if fracking equipment is to be moved through rough

A clearer picture with LabVIEWNational Instrument’s LabVIEW is helping to power advances in vital monitoring equipment

and unforgiving terrain, even before it has to monitor pump vibrations.

In addition, the ability to develop the control software rapidly proved critical to Lime, especially in an oil and gas gas application. Stewart added: “We can develop software in LabVIEW faster than most other programming environments… What most C programmers take two years to do, we can accomplish in a couple of months. We can use [these] time savings to get to market quicker and capitalise on our competitors’ lag time.”

It also allowed Lime to work with a number of sensor packages, including pressure transducers, magnetic pickup sensors, digital encoders, temperature sensors, nuclear densitometers, magnetic flow meters and Correollis flow meters, all of which can be integrated into coiled-tubing fatigue and wellbore-simulation software.

In addition to successful work with Lime Instruments, NI has used its adaptive software and hardware offering in a number of other oil and gas applications. Mud-Gas separators, coil tube drilling control, condition monitoring and predictive maintenance have used platforms such as CompactRIO and InsightCM, to name but a few.

With a comprehensive track record within the oil and gas industry, NI will continue to innovate and develop product lines and support to fuel efficiency, effectiveness and game-changing new ideas. n

Contact: Gavin HillTel: +44 (0)1635 523 545Email: [email protected] Web: www.ni.com/oilandgas

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NI’s CompactRIO hardware

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Tech deals struck in St PetersburgFour companies have teamed up to create a new manufacturer of LNG processing equipment to serve Russia’s budding liquefaction sector. The head of Germany’s Linde and counterparts at Russian firms Power Machines, Salavatneftemash and Gazprom signed an agreement of intent at the St Petersburg International Economic Forum on June 17.

“It is planned to prepare a feasibility study and a business plan to identify the most efficient form of partnership, including a possible joint venture, by the end of 2016,” Gazprom said in a statement. “The feasibility study and business plan will take into account the technological demand for and the competitiveness of such equipment in Russia,” the statement continued. “Russian-made components will be used in the manufacturing process to the maximum extent possible.”

Munich-headquartered Linde already has a presence across Russia, producing industrial, food-grade, medical and special gases for the domestic market, while also working on LNG projects in Norway, Malaysia and Australia.

In January, Gazprom selected Linde as the licensor for its cryogenic gas separation

NEWS IN BRIEF

technology to be installed at the state-owned firm’s Amur gas-processing plant in Russia’s Far East.

Power Machines manufactures turbines for power plants in Asia and Russia, co-operating with state-controlled Rushydro. Salavatneftemash is based in central Russia and is one of the country’s largest producers of oil and gas refinery equipment, including truck pipeline infrastructure. The decision to form the quartet is part of Russia’s broader plans to quintuple annual LNG production to 53.6 million tonnes by 2035.

Novatek also struck a number of deals at the St Petersburg forum. The company announced partnerships with Saipem, Nuovo Pignone and Linde at the meeting, in addition to a co-operation agreement with Sberbank and the government of the Leningrad region. The agreement with Nuovo Pignone included a 25-year services agreement on the Yamal LNG plant. The company committed to ensuring safe operations in the harsh environment of the north and included provisions for the training of Russian specialists.

Nuovo Pignone signed a contract in 2013 on supplying turbomachinery equipment, produced and tested in Italy, for the three trains of the Yamal LNG project.

Further adding to the various deals in St

Petersburg, Gazprom announced an agreement with Russian Railways, Sinara Group and Transmashholding on June 17 on the use of natural gas in transportation. The deal covered the use of gas in “railway and motor transport, mitigating environmental impacts, facilitating NGV market growth, increasing domestic gas consumption, and fostering the national machine building industry”.

Gazprom committed to the construction of refuelling facilities in sites approved by Russian Railways and the provision of LNG to railway rolling stock. Russian Railways, meanwhile, said it would adapt various depots to accommodate the facilities and would provide training for engineers, technicians and train crews for gas-powered locomotives.Edited by Joe [email protected]

Engie gears up for new Norway wildcatEngie E&P Norge has been cleared to drill a new exploratory well, 36/7-4, in Production Licence 636 offshore Norway, by the Norwegian Petroleum Directorate (NPD).

The wildcat will be drilled approximately 55 km southwest of Floro and about 10 km northwest of the Gjoa field, which is one of the company’s flagship projects.

The wildcat area consists of a part of petroleum Block 36/7, which is operated by Engie E&P, and partnered by Idemitsu Petroleum Norge, Wellesley Petroleum and Tullow Oil Norge.

Engie E&P intends to use the Transocean Arctic drillship for the work as soon as the rig completes the drilling of another wildcat, 31/7-1 A, on behalf of Faroe Petroleum Norge in PL740.

The company has reported higher output from the Gjoa development, its first operated production on the Norwegian Continental Shelf (NCS).

The gas field, first discovered in 1989, sits about 60 km west of Floro and contains an estimated 40 billion cubic metres of reserves.

“Gjoa was originally designed to export 17 million cubic metres per day of gas. That we are currently producing 20 mcm per day of gas – 17.5% more than estimated – is a great achievement,” said Hilde Adland, head of operations.

Engie E&P Norge acquired a 30% interest in the field in 2003, with the authorities approving

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the development in 2007. This cleared the way for one of the largest offshore projects in Norway since Snohvit, in which the company is also a stakeholder.

Engie E&P also produces light oil and condensate from the Gudrun field in the North Sea, which commenced output in 2014, and the Njord field in the Norwegian SeaEdited by Ryan [email protected]

OneSubsea wins Zohr EPC workOneSubsea has won an engineering, procurement and construction (EPC) contract worth US$170 million for subsea work on the Zohr field, offshore Egypt. The Schlumberger unit announced the award from Petrobel, a joint venture of Eni and Egyptian General Petroleum Corp. (EGPC), on June 20.

“Zohr is one of the largest gas fields discovered in the Mediterranean Sea to date, and is also the world’s second longest step-out, a distance greater than 150 km. This step-out will be enabled by OneSubsea controls systems with fibre-optic communications technology,” said OneSubsea’s president, Mike Garding. “Our supplier-led approach to the field development,

NEWS IN BRIEF

coupled with our FasTrac programme capability, and our integrated offering that includes flow assurance, subsea production system and landing string capabilities, will help Petrobel meet their first gas commitment.”

OneSubsea worked on Zohr’s front-end engineering and design (FEED). The statement said the system would have to handle high gas volumes, while taking into account reservoir characteristics and subsea equipment specifications.

The contract covers six horizontal SpoolTree subsea trees, it said, with intervention and workover control systems, landing string, tie-in, high-integrity pressure protection system, topside and subsea controls and distribution, water detection and salinity monitoring provided by the AquaWatcher water analysis sensor, and installation and commissioning services.

OneSubsea’s FasTrac programme is intended to allow a fast and flexible means by which to configure a production system to meet customers’ needs.

Aker Solutions announced, in a statement on June 6, that it had won work on the umbilicals system at Zohr. The award was worth US$122.3 million, it said, and would cover the delivery of 180 km of steel tube umbilicals, which would connect the development to an offshore control platform. Aker’s umbilicals are due to

be delivered by mid-2017. The project is the company’s largest ever of umbilicals.

The Zohr field was found in August 2015, on the Shorouk concession, and Eni intends to bring it into production by the end of 2017. The company began appraisal drilling at the start of 2016 and took the final investment decision (FID) in February.Edited by Ed [email protected]

CGG completes Gabonese pre-salt shootEarly results from state-of-the-art seismic covering the acreage offered in Gabon’s 11th deepwater licensing round indicates numerous pre-salt prospects, CGG said last week.

In a June 1 statement, the Paris-headquartered company said initial seismic imaging results suggest the existence of key intervals of a pre-salt petroleum system – namely syn-rift and sag sequences below the salt – and “many exciting prospects” that extend beyond the borders of the survey.

CGG claims that understanding of the area’s geology is being revolutionised as a result of its

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survey, which captured more details below the salt than have previously been seen. This should provide “dramatic” improvements to subsalt imaging in the final dataset.

Covering 25,000 square km of newly available and licensed blocks in Gabon’s South Basin, the multi-client 3-D shoot aimed to “image potential prospective structures at base salt level without compromising the shallower post-salt image quality”, CGG said.

An onboard preliminary ultra-fast-track dataset seen by a major oil company interpreter was described as “way beyond expectations”, the statement noted.

The survey’s fast-track pre-stack time-migrated (PSTM) dataset is already available, as is sample pre-stack depth reverse time-migrated (RTM) data for one area, with the final RTM for the complete area due this summer.

CGG said its fast-track PSTM showed “clear uplift over the existing data” with fast-track pre-stack depth migrated data highlighting the full benefits of advanced velocity modelling and depth-migrated modern broadband 3-D seismic.

The dataset provides insights into the area’s subsurface, it said, and this will be further improved following the acquisition of additional data covering the more complex geology of the area’s southeast. This includes the F14 block and, adjacent to the border with Republic of Congo (Brazzaville), the F15 block, CGG said.

This data forms the centrepiece of an integrated geoscience project that will allow analysis of the basin’s deep structure and its key wells in order to reduce exploration risks, the statement added.

Encouraged by recent Gabonese pre-salt discoveries, including Diaman, Leopard, Ruche and Tortue, the bid deadline for Gabon’s 11th deepwater licensing round closed on May 31, having attracted “considerable interest” from international companies and minnows alike, CGG said.Edited by Ed [email protected]

YPF plans efficiency driveArgentina’s YPF is pushing ahead on projects to improve efficiency for cutting shale drilling costs, increasing heavy crude output and developing a recent conventional gas find.

“We have to find ways to be more competitive, efficient and innovative,” YPF chairman Miguel Gutierrez said in a statement

during a visit to the provinces of Mendoza, Neuquen, Santa Cruz and Tierra del Fuego.

In Neuquen Province, the state-run company will this year bring on line infrastructure to raise output from the giant Vaca Muerta shale play, whilst also reducing drilling and completion costs. This includes a 50,000 barrel per day crude-processing plant that can be expanded to 63,000 bpd, the company said.

The plant is being built in Anelo, a town at the heart of the Vaca Muerta oil window where YPF is working with Chevron on the country’s largest shale development. They are producing 50,000 barrels of oil equivalent per day from the Loma Campana block.

Also in Anelo, YPF is building a sand treatment plant with capacity to process 140 metric tonnes per hour. The facility will provide 100% of the natural sand YPF needs for fracking, and will be equipped to start producing resin-coated proppant in 2017. This will save the companies 50% on the cost of the product by replacing imports, and will make it possible for it to sell the surplus proppant to competitors.

In Mendoza, YPF will fire up a US$62 million oil treatment plant on its Malargue block, replacing one that burned down in 2014.

The plant will allow it to process more heavy crude, which has surged 46% to 1,300 bpd on its Llancanelo block over the past year, Gutierrez said. YPF wants “to provide more scale for this development,” the company said.

Further south in Santa Cruz, the company is building a new water-injection plant to cut costs in secondary recovery projects, whilst it is also planning to develop a new conventional gas project.

The company found conventional gas reserves on its Los Perales-Las Mesetas block in 2014 after drilling deeper than the maturing formations that are currently producing about 15,000 bpd of oil and 980,000 cubic metres per day of gas. The find will add 370 bpd of crude and 200,000 cubic metres per day of gas.

The projects come as the company seeks to sustain oil and gas production this year at 2015 levels even as it cuts capital expenditure by 20% to 25% in response to low global oil prices and the impact of an economic recession on energy demand in Argentina.

YPF produces 44% of the country’s 530,000 bpd of oil and 30% of its 120 mcm per day of gas.Edited by Ryan [email protected]

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Pemex seeks partners for Trion deepwater projectPemex last week announced its first farm-out for deepwater acreage in the Gulf of Mexico. The terms of the contract have not yet been revealed, with bidding guidelines due to be published in July.

The company and the Energy Ministry have approved a process to migrate the contract to develop the offshore Trion block from one that would see Pemex work on the project alone to a joint operating agreement (JOA) with one or multiple partners.

The state-run Mexican company said it wanted to establish a joint venture with between one and three partners for the project, which requires investment of around US$11 billion over the next 15 years.

Mexican Energy Minister Pedro Joaquin Coldwell said a farm-in process would expedite development, as companies that partnered with Pemex would provide investment and technology and thereby reduce the amount of capex necessary from the overstretched national oil company (NOC). Pemex is undergoing a fiscal retrenchment, as it looks to become a more nimble and effective player in Mexico’s newly liberalised energy sector.

Pemex has been developing Trion since 2012. The block is located in water depths of around 2,500 metres in the Perdido area of the Gulf of Mexico, some 200 km off the Mexican coast. It has estimated reserves of approximately 485 million barrels of oil equivalent.

Though the exact terms of the JOA will not be published until next month, it is anticipated they will reflect those on offer in Mexico’s deepwater bid round, which is due to be held in December and which will involve ten blocks. Trion is adjacent to several of the blocks on offer.

The farm-out opportunity will also be tendered via an international bidding procedure, in line with the terms on offer by the National Hydrocarbons Commission (CNH) for the December auction. Technical information on Trion has been made available by the National Centre of Hydrocarbons Information (CNIH), a division of the upstream regulator.

The establishment of partnerships between Pemex and international oil companies (IOCs) is viewed as critical to Mexico reviving its oil

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production. Output is currently down by over 1 million barrels per day from the 3.4 million bpd recorded in 2004, as shallow-water fields mature. Production from deepwater fields is viewed as being the best way to offset declines at fields closer to shore.

Chevron, ExxonMobil, Repsol, Royal Dutch Shell, Statoil and Total have all been tipped as potential participants in the December deepwater auction. They could also be interested in the Trion farm-in opportunity. Edited by Ryan [email protected]

Eni cleared for Barents Sea drillingEni Norge has received clearance from the Norwegian Petroleum Safety Authority (PSA) for an exploration well at PL 226 in the Barents Sea.

The well, designated 7222/1-1, will target the Aurelia prospect at water depths of around 424 metres. Drilling will be performed by Saipem’s Scarabeo 8 semisubmersible drilling rig, which is designed according to the Moss CS-50MkII template. The rig is capable of operating in heavy winter conditions, and can reach depths of between 70-3,050 metres.

Eni holds a 60% operative stake at PL 226 alongside partners Edison and E.ON with 20% interest each.

Work is expected to last at least 58 days, with previous reports suggesting an 82-day operation if Eni makes a discovery.

The Italian major marked a milestone for

the region in March when it launched Goliat, the first producing oilfield in the Norwegian Barents Sea.

Eni will have gained expertise by negotiating the harsh Arctic climate at much-delayed Goliat, which is expected to peak at 100,000 barrel per day output from 12 production wells.

Norway’s Barents Sea, the northernmost part of the country’s continental shelf, is estimated to hold 7.6 billion barrels of oil equivalent of undiscovered hydrocarbon potential.

Explorers have made four discoveries of more than 100 million boe in the Norwegian Barents over the last five years, and roughly 100 wells have been drilled at its basins since 1980.

Oslo had high hopes for the Barents after Statoil launched its Snohvit gas field in October 2007, but exploration has slowed with the collapse in crude prices.

Explorers have become increasingly sceptical at the high costs of production and technical challenges prevalent in the world’s northernmost reaches.

Oslo suffered a setback in April when Royal Dutch Shell announced it would withdraw its application for Barents licences offered in the 23rd licensing round.

Norway needs to unlock fresh reserves to replace output, which has halved since 2000. Oslo hopes to regain some momentum with the latest awards, which included acreage in the southeast previously inaccessible because of a long-running maritime dispute with Russia.

On May 18, Oslo announced it had awarded three licences in the south-eastern region. In total, Norway awarded ten licences to 13 firms, with Statoil and Lundin securing the most blocks.Edited by Ryan [email protected]

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ANT Telecom says the Internet of Things can only get betterThe practical application of connectivity tools is all around us. Immersive technology is connecting factory machines to alert engineers when a unit malfunctions. In healthcare settings, smart technology monitors refrigeration to keep high-value medicines at regulated temperatures - and informs healthcare professionals when potential problems arise. In hazardous remote environments or manufacturing plants, intuitive technologies are being connected to Alarm Messaging Applications to protect lone workers, accelerate response and mitigate risk.

These applications are long established and use simple and cost-effective everyday technologies. They don’t require sophisticated IoT architecture, painful implementation programmes or significant investment. And they work.

Make no mistake, IoT is an exciting prospect that will transform the way we work. Its central promise – ubiquitous connectivity – will undoubtedly deliver major gains. But for businesses seeking to safeguard their workers, improve productivity and find greater operational efficiencies, connectivity is not the issue.

The challenge for companies is to move beyond connectivity and focus on the much more critical aspect of escalation. Whether you’re using technology to improve lone worker protection, maintain business continuity or alert mechanical failure, the most effective systems are those that are built to include robust and responsive processes for escalation management and audit capability. Connectivity is only the starting point.

The development of intuitive systems to protect operations and human resources does not require a technological revolution or wholesale investment in the Internet of Things. But it does require taking a considered, pragmatic and holistic approach to designing the most appropriate solution to suit individual business needs. The most successful organisations will be those that work with an experienced and trusted communications partner to help them join up the dots. In a world of connectivity, that’s one connection that really is worth making.ANT TELECOM

Hilong bags Indonesian service contractHilong Petroleum Offshore Engineering has won its first offshore services contract outside Chinese waters, sealing a deal to install jackets at a gas development in Indonesia.

Timas Suplindo awarded the contract – which will see Hilong use the Hilong 106 pipe-laying derrick barge at the HCML Madura MDA-MBH project – earlier this month, Shanghai-headquartered parent Hilong Group said on June 17. The group added that the deal was very significant, as it laid a “firm foundation” for further development of its offshore engineering services arm, in addition to being the subsidiary’s first offshore lifting operation contract.

Most of the work will involve lifting and upending jackets underwater in the Madura Strait, off Java, with an expected start date of mid-November and completion anticipated by the end of February 2017, the statement said.

Hilong Group’s vice president and Hilong general manager, Xiao Long, attributed the award of the contract to the service provider’s “innovative transportation and installation technology”, as well as the “inclusive construction solutions” offered by Hilong 106.

Madura MDA and MBH are two of seven shallow-water gas and condensate fields with significant exploration potential within the East Java Basin, covering a total area of 2,805 square km.

The development project is a joint venture between field operator CNOOC Ltd and Canada’s Husky Energy, each with 40%, and Indonesia’s Samudra Energy with the remaining 20%.

In April, Husky said that when the project was fully ramped up in 2018-19 it would provide combined net sales volumes from the BD, MDA-MBH and MDK fields of

approximately 100 million cubic feet (2.83 million cubic metres) per day of gas and 2,400 barrels per day of associated liquids.Edited by Andrew [email protected]

HHI clinches deal for two new LNG carriersShipbuilder Hyundai Heavy Industries (HHI) has clinched a deal to build two LNG carriers, industry sources said on June 2. The deal is estimated to be worth US$400 million. The sources said the South Korean-based company had won the order from SK E&S, a South Korean LNG importer, to build the two vessels, which can each carry 180,000 cubic metres of LNG. The vessels will be built at HHI’s shipyard in Ulsan and are scheduled to be delivered at the start of the first half of 2019.

International Shipping News said the vessels, designed according to the new IGC standards published in 2016, would be equipped with GTT’s Mark III Flex membrane technology. The report said Mark III Flex was well-suited for the highly efficient XDF propulsion system installed on SK Shipping’s LNG carriers, as the technology offers a high level of insulation performance.

HHI and its local rivals such as Samsung Heavy Industries (SHI) have been struggling to win new orders amid a protracted slump in the global shipbuilding sector, which has been hit by lower oil prices. South Korea is the world’s second largest LNG importer after Japan, but LNG demand growth in the Asia-Pacific region has declined over the past two years. The Korea Times said that in the first quarter of the year, HHI’s new orders had passed US$1.74 billion, down from US$3.02 billion a year earlier.

HHI recently received approval from its creditors to implement a new self-structuring plan. The company claims that under the plan it can save or raise up to 3.5 trillion won (US$2.94 billion). South Korea’s Yonhap news agency said that under the shipbuilder’s plans, which have been temporarily approved by its creditors, led by KEB-Hana Bank, it would cut stock holdings, sell non-core assets and cut its workforce. This should reduce its debt-to-equity ratio to below 100% by 2018. Maeil Business News Korea said the LNG carriers would be transporting LNG supplies from US shale supplies in which SK has been working.Edited by Ed [email protected]

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CUCBM to use drones in remote surveysState-run CBM developer China United Coalbed Methane Corp. (CUCBM) is reportedly planning to use small aerial drones to collect survey data in remote and difficult terrain.

Drones, also known as unmanned aerial vehicles, are becoming commonplace in China for numerous commercial uses, including delivering parcels.

The use of drones is much more liberal in China than in most other countries such as the US where restrictions or bans are in force. Drones weighing less than 7 kg do not need a licence from the Civil Aviation Authority of China, said E&P magazine.

CUCBM is now controlled by national oil company (NOC) China National Offshore Oil Corp. (CNOOC) and is exploring and developing numerous potential CBM blocks in northern China, often in remote mountainous terrain.

Initially, drones will be deployed by the firm to collect data from wells already sunk in blocks in difficult terrain, Interfax China said. Despite having confirmed reserves of 36 trillion cubic metres, growth in CBM production has been slow.

The National Energy Administration (NEA) has set a national production target of 30 billion cubic metres per year for 2020. The sector produced 18 bcm in 2015 but less than 50% was put to use, and the rest was allowed to escape into the atmosphere, the NEA said.

CUCBM operates or has stakes in blocks in Shanxi Province, Inner Mongolia and the rugged northwest Xinjiang region.

Meanwhile, the Ministry of Environmental Protection has authorised the resumption of three coal-to-gas (CTG) projects that had been suspended for over a year over concerns about their environmental impact and commercial viability, Fenwei Energy said.

The three projects, with a total capacity target of 4 bcm per year, are in the coal-producing regions of Shanxi, Xinjiang and Inner Mongolia.

“China has pledged to reduce its coal dependence,” Fenwei said. “However, policymakers are also trying to secure a soft landing for a sector that employs more than 5 million people, and coal-to-gas has the potential to be a new opportunity for mining firms.”Edited by Andrew [email protected]

NOV to buy Trican’s well completion tools divisionHouston-based National Oilwell Varco (NOV) has unexpectedly agreed to buy Trican Well Service’s well completion tools business for almost US$41 million in cash and stock.

Trican designs and sells patented downhole tools for multi-stage fracturing and multi-zone completions in North America and select international markets, including Russia and Norway.

The purchase positions NOV to expand its onshore presence and could be seen as evidence of the appeal of the unconventional market.

It is a “wonderfully strategic deal”, said investment banking firm Tudor, Pickering, Holt & Co. (TPH). “Via its wellbore technologies business – drilling fluids, drill pipe, downhole tools, drill bits – NOV touches more wellbores during the well construction process than any other company,” said TPH.

“We’d argue that NOV’s Completion & Production Solutions product offering has been more surface/subsea-centric vs. downhole-oriented until now,” it added.

“This transaction represents an exciting step for NOV in expanding the breadth of our completion and production related product offerings,” said NOV’s chairman, president and CEO, Clay Williams.

“The transaction allows NOV to leverage our best-in-class manufacturing and global supply chain to expand sales into new markets and meet our customers’ demands for cost-effective, innovative and high quality completion tools,” he added.

NOV, a rig manufacturer and oilfield services provider, will continue to develop additional downhole completion technology to help customers reduce their cost of supply, Williams said. The company will retain Trican’s team.

Trican, an oilfield services company based in Calgary, said it would use the proceeds to reduce its outstanding debt. Closing of the transaction is expected on or around June 30, 2016

The deal comes as a boost to NOV, which has recently announced job cuts and closures.

“We have closed or are closing 200 facilities since the downturn began, and we reduced our workforce by nearly 6,000 employees during the first quarter of 2016,” said Williams on an analyst call in April.Edited by Anna [email protected]

USAID to conduct another Pakistan shale studyThe US will help Pakistan study its shale oil and gas reserves further, officials have told the Pakistani Express Tribune newspaper. The US Agency for International Development (USAID) will conduct and fund the study.

This is not the first time that the US has pioneered studies overseas, given that the country is the leader in shale development and US companies are interested in investing overseas – at least when the economics are favourable. The US Energy Information Administration (EIA) has studied shale reserves globally.

The initial study in Pakistan was also conducted by USAID, but it did not cover all of the country, including some parts of Balochistan, Sindh and Khyber-Pakhtunkhwa, reported the Express Tribune. It is unclear why these regions were not covered.

The initial USAID assessment indicated that Pakistan had deposits of 2.3 trillion barrels of shale oil and 10.159 quadrillion cubic feet (287.7 trillion cubic metres) of shale gas. Risked technically recoverable resources were estimated to be 14 billion barrels of shale oil and 95 trillion cubic feet (2.7 tcm) of shale gas.

The EIA’s numbers are different, with the agency first finding in 2011 that Pakistan had 206 tcf (5.8 tcm) of shale gas in the Lower Indus Basin alone, of which 51 tcf (1.4 tcm) were recoverable. In 2013, EIA increased the estimate to 586 tcf (16.6 tcm), of which 105 tcf (3.0 tcm) were technically recoverable.

If the initial USAID figures are confirmed or even increased, Pakistan could overtake Mexico, which is currently thought to have the world’s eighth largest shale oil and condensate reserves at 13 billion barrels. But it is not clear if the methodology used to assess these reserves is comparable.

Once the USAID’s new study has been completed, and the cost of the drilling assessed, the Pakistani government will create a policy framework for developing the resource, reported the Express Tribune, which is affiliated to the New York Times. nEdited by Andrew [email protected]

NEWS IN BRIEF

July 2016 page 43

N E W S B A S E

InnovOil

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

For more information on Well-SENSE Technologies, or the Fibre Line Intervention (FLI) system, contact Dan Purkis on +44 (0)1224 937 600, via

email at [email protected] or visit www.well-sense.co.uk/

To learn more about Dr Tony Gutierrez’ work in bio-surfactants, bio-polymers and oil-degrading bacteria, contact [email protected] or

visit www.tony-gutierrez.com

National Instruments’ LabVIEW system can aid software writers and engineers in oil and gas and beyond. Contact Gavin Hill on +44 (0)1635 523 545 or email [email protected] for further information.

If you would like guidance or insight on how industrial mobility can support your operations, contact Rohit Robinson at Honeywell Process

Solutions via [email protected]. You can also participate in Honeywell’s Mobility Survey at www.HoneywellPulse.com

Repsol and IBM’s cognitive technology programme is changing the way operators engage with IT in E&P. For more information

visit www.repsol.com.

NOV is pioneering some of the most advanced automated drilling and optimization technology. If it could help you in your drilling programme,

contact Mats Andreas Andersen DDS Services Director on +47 918 606 71, or email [email protected]

To discuss how Lloyd’s Register Energy can help your business innovate and collaborate better, contact Jason Knights on +44 (0)20 7423 1741 or

email [email protected]

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UNLEASHING

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The IChemE highlights its new

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Scottish Carbon Capture &

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GAME OF

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Are UAVs the future of

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Cold Temperature

Demulsifiers from

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QUESTIONSOur Q&A with

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Monitoring corrosion

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SIXTH SENSE

Lumasense’s flare

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InnovOil asks the

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GATHERING INTEL

AGR’s iQx™ software

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Modular Subsea

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VERSATILE

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Shared idealS

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Heat and ligHt

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Halfwave’s ART Scan tool for in-line inspection

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extra 141 billion barrels in low-productivity fields?

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An in-depth look at asset

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Zn

Zn

Zn

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ntegrity

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EYE ON BATTERIESHotter batteries could

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EELUME-INATING

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Norway’s subsea snake ROVs

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FINDING THE SOURCE

GPUSA’s Distributed

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HUMAN OR ROBOT?

The latest advances

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September 2015


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Down tools

Utility ROV Services’ unique subsea equipment

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sustainable supply

AkzoNobel’s take on the future of the chemical oilfield

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A new era in

completion

fluiDs hAs

arriveD … Page 14

N E W S B A S E

w

oilfiel

D chem

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siDe

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9-21

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Our supplement

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DEEPER.An in-depth

look at Nautilus

subsea connectors

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November 2015


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OCEAN OF

SAVINGSFoundOcean

discusses offshore

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RETURN OF

REFRACKA look at the

companies and

technologies

leading the US

trendPage 12

NON- FRICTIONSiemens’

magnetic

oil-free

steam turbine Page 20

N E W S B A S E

w

UNCONVEN

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SPEC

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7

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OCEAN OF SAVINGSFoundOcean discusses offshore cost-efficiencyPage 9

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NON- FRICTIONSiemens’ magnetic oil-free steam turbine Page 20

N E W S B A S E

w

UNCONVENTIONALS

SPECIAL SUPPLEMENT INSIDE

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December 2015


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BETTER

WITH BIOWe look at

Cosun’s Betafib®

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MERCURY

FALLING

Johnson Matthey’s

PURASPECJM

technology for

mercury removalPage 24

SEISMIC SHIFT

Prof. Maarten de Hoop on

how deep learning could

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N E W S B A S E

DRILLIN

G/SEIS

MIC

SPEC

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PPLE

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SIDE

Pages

9-23

DECOM

DEVELOPMENTS

P&A solutions,


Page 15

EYE ON

BATTERIES

Hotter batteries could

power downhole

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Page 26

EELUME-INATING

THE DEPTHS


Page 9

Issue 43

June 2016

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AUV-IPSNew research on

AUV missions

Page X

BLITZKRIEG

ON BOPSGE and Diamond

make an new

partnership

Page X

QUESTIONING

INTEGRITY

A look at asset

integrity solutions

Page X

Issue 42

April 2015

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DECOM

DEVELOPMENTS

P&A solutions,


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EYE ON

BATTERIES

Hotter batteries could

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EELUME-INATING

THE DEPTHS


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June 2016

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