Underwater Technology 34.4

Vol. 34 32 No. No. 432 2017 2014 Vol.

UNDERWATER TECHNOLOGY

147

A Personal View...

Downturns and the deep

Bil Loth

149

Protection of submarine optical fibre cables on the coral reefs of the Maldives

Muneez M, Vinesh T and Nai-Shyan L

157

Investigation of slug mitigation: self-lifting approach in a deepwater oil field

Adefemi IO, Kara F and Okereke NU

171

Technical Briefing Development of data layers to show the fishing intensity associated with individual pipeline sections as an aid for decommissioning decision-making

ISSN 1756 0543

Sally Rouse, Andronikos Kafas, Peter Hayes and Thomas A Wilding

179

Book Review Popularizing Science: The Life and Work of JBS Haldane

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UNDERWATER TECHNOLOGY Editor Dr MDJ Sayer Scottish Association for Marine Science Associate Editor G Griffiths MBE Autonomous Analytics Associate Editor Subsea Engineering LJ Ayling Maris International Ltd Assistant Editor E Azzopardi SUT Editorial Board Chairman Dr MDJ Sayer Scottish Association for Marine Science Gavin Anthony, GAVINS Ltd Dr MA Atamanand, National Institute of Ocean Technology, India LJ Ayling, Maris International Ltd Commander Nicholas Rodgers Prof Ying Chen, Zhejiang University

Society for Underwater Technology Underwater Technology is the peer-reviewed international journal of the Society for Underwater Technology (SUT).

SUT is a multidisciplinary learned society that brings together individuals and organisations with a common interest in underwater technology, ocean science and offshore engineering.

It was founded in 1966 and has members in more than 40 countries worldwide, incIuding engineers, scientists, other professionals and students working in these areas. The Society has branches in Aberdeen, London and South of England, and Newcastle in the UK, Perth and Melbourne in Australia, Rio de Janeiro in Brazil, Beijing in China, Kuala Lumpur in Malaysia, Bergen in Norway and Houston in the USA. SUT provides its members with a forum for communication through technical publications, events, branches and specialist interest groups. It also provides registration of specialist subsea engineers, student sponsorship through an Educational Support Fund and careers information.

For further information please visit www.sut.org or contact: Society for Underwater Technology 1 Fetter Lane EC4A 1BR London UK e info@sut.org t +44 (0)20 3440 5535 f +44 (0)20 3440 5980

Jonathan Colby, Verdant Power Neil Douglas, Viper Innovations Ltd, Prof Fathi H. Ghorbel, Rice University G Griffi ths MBE, Autonomous Analytics Prof C Kuo FRSE, Strathclyde University Dr WD Loth, WD Loth & Co Ltd Craig McLean, National Ocean and Atmospheric Administration Dr S Merry, Focus Offshore Ltd Prof Zenon Medina-Cetina, Texas A&M University Prof António M. Pascoal, Institute for Systems and Robotics, Lisbon Dr Alexander Phillips, National Oceanography Centre, Southampton Prof WG Price FRS FEng, Southampton University Dr R Rayner, Sonardyne International Ltd Roland Rogers Dr Ron Lewis, Memorial University of Newfoundland Prof R Sutton, Plymouth University Dr R Venkatesan, National Institute of Ocean Technology, India Prof Zoran Vukic´, University of Zagreb Prof P Wadhams, University of Cambridge Cover Image (top): zoonar.com/syrist Cover Image (bottom): Steve Crowther Cover design: Quarto Design/ kate@quartodesign.com

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Scope and submissions The objectives of Underwater Technology are to inform and acquaint members of the Society for Underwater Technology with current views and new developments in the broad areas of underwater technology, ocean science and offshore engineering.

SUT’s interests and the scope of Underwater Technology are interdisciplinary, covering technological aspects and applications of topics including: diving technology and physiology, environmental forces, geology/geotechnics, marine pollution, marine renewable energies, marine resources, oceanography, salvage and decommissioning, subsea systems, underwater robotics, underwater science and underwater vehicle technologies.

Underwater Technology carries personal views, technical papers, technical briefings and book reviews. We invite papers and articles covering all aspects of underwater technology. Original papers on new technology, its development and applications, or covering new applications for existing technology, are particularly welcome. All papers submitted for publication are peer reviewed through the Editorial Advisory Board. Submissions should adhere to the journal’s style and layout – please see the Guidelines for Authors available at www.sut.org.uk/journal/default.htm or email elaine.azzopardi@sut.org for further information.

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in more than 40 countries worldwide, including over 190 Corporate Members of the Society.

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The Society for Underwater Technology also encourages Underwater Technology authors to make their papers available online on their personal and/or institutional websites for Open Access. Through this arrangement, the Society supports the Open Access policy not only in the UK (the Research Councils UK (RCUK) policy) but also the drive towards Open Access in other countries.

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Underwater Technology is also available in electronic format via ingentaconnect as Open Access. To subscribe to the print version of the journal or for more information please email Elaine Azzopardi at elaine.azzopardi@sut.org

Publication and circulation Underwater Technology is published in March, July and November, in four issues per volume. The journal has a circulation of 2,400 copies to SUT members and subscribers

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A Personal View...

doi:10.3723/ut.34.147 Underwater Technology, Vol. 34, No. 4, pp. 147–148, 2017

Downturns and the deep A strong aversion to meetings and a generally philosophical view of periodic downturns in the subsea oil business are the legacy of 50 years as a subsea engineer. Meetings are always boring but usually you can see the end. The downturns are always painful, but you can normally look forward to a bonanza when the price goes up. I’m not so sure this time. In previous downturns, the menace of shale oil and gas hadn’t existed.

Deepwater wells are prolific and, in the end, the cost per barrel of recovery may not be dissimilar than that for shale oil and gas. The problem is that deepwater projects require a large financial commitment, take a long time to execute, and drilling and installation are costly. This means that payback time and investors’ rate of return are unfavourable compared to a land well, which costs a small fraction of the deepwater well and is producing in less than six months after spudding. It might be a long time before the bonanza returns for the subsea engineer.

What happens to the oilman in these downturns? It can be an unpleasant experience. El Presidente gets sold in the Oil and Gas Journal, and time is kept with a Swatch or Timex. The Moet & Chandon, Dom Perignon and white truffles turn into Fruity White and button mushrooms from a discount supermarket (albeit still carried in the old Fortnum’s bag so the neighbours don’t know), the Bentley Brooklands turns into a clapped out Ford Kia, the three bedroom flat on the Riviera morphs into a bedsit in Bognor Regis. Absolutely

ghastly but you can still tell the time, drive to the store, get a nasty hangover and enjoy jellied eels in Bognor. You are alive, and when the bonanza comes it will be all the sweeter.

Same thing for the deepwater subsea development. Laying around feeling sorry for ourselves isn’t the answer. As always, the answer lies in the areas of risk and technology.

Let’s look at risk. Some things are sacrosanct. There is no changing our attitude towards safety and the environment.

There are two aspects of risk that could be considered, however: financial risk and personal risk (career threatening, but not life-threatening). Contingency allocations ought to be a target.

Contingency planning is vital, but to simply add bits and pieces without conducting probabilistic economics is simply second-rate engineering. Although, as others have pointed out, subsea equipment has suffered from a ‘ratchet’ effect, where once a widget has been added it never goes away, and the fact that what should be a simple collection of valves has morphed into complex monstrosities, nickel-and-diming subsea equipment isn’t the answer. It doesn’t cost enough to make the difference needed.

What is required is a more comprehensive consideration of manufacturing times, installation requirements and a realistic long-term operating expense.

The other risk of concern is the pervasive fear of the multitude of specialist engineers working on projects. Everyone is afraid of making the wrong call and takes the ‘safe’ route of using ‘field proven’ technology. That is a

Bil Loth Bil Loth took advantage of a downturn in the early 60s to get a job with Humble Oil & Refining Company (shortly to become Exxon) who were getting pretty short of engineers. The initial task, conducted in Humble’s Production Headquarters, Esso Production Research Company, and Exxon USA was to develop and install the first multiwell subsea system complete with separation, boosting, and closed loop electrohydraulic control system. Then, seconded to Shell Exploration and Production in the UK, he spent ten years developing subsea systems including the Central Cormorant Underwater Manifold Center and Gannet. When the big downturn in the mid-80s came along, the severance package was irresistible and he used the proceeds to start a consulting company, WDLCO, designing and prototyping lower cost subsea and wellbore equipment. With the advent of the downturn at the end of the century, the company’s technology was sold to Halliburton.

Becoming weary of writing progress, or lack thereof, reports he retired to an academic life at the National University of Singapore and then to Newcastle and Robert Gordons University lecturing on, what he hopes is not legacy technology, subsea engineering.

misnomer in itself. It has to be field proven on the last six jobs they did. The fact that a less expensive approach was used for 20 years before that escapes their attention and nobody up the

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Loth. Downturns and the deep

ladder seems anxious to make the call because of the ‘risk’ involved.

The truth is that we are in a risk business and the old adage ‘no balls, no blue chips’ has been forgotten. Technical failure is a lot less likely to damage your career than messing with the expense account. We have to revert to proper oilfield risk appraisal rather than risk aversion. This point is crucial to the revival of our business as will be emphasised in the remainder of ‘my view’.

Saving half of the cost of the subsea equipment isn’t going to make the difference. The big targets have to be drilling and installation. We don’t need new technology. What we do need is a more comprehensive knowledge of the tools and techniques that have been historically proven. Admittedly, this is rather more easily said than done in an industry populated by bright young engineers left to solve serious problems in the absence of patient mentors and with risk adverse leadership.

Slim hole drilling is nothing new. The concept of tubingless (also called multiple cased or cemented completions) has been around since the 1940s, used in recent years by parts of major operators and proven to save approximately 50 % of drilling and completion costs. If anything, its use is enhanced by improved drill bits (longer runs on smaller bits), look ahead seismic, and

logging while drilling techniques.

There is a risk of running into a high-pressure zone and being unable to run another string of casing in a small diameter hole, but when you are saving that much on every well, junking the odd one isn’t the end of the world. The problem is more unfamiliarity with the technology, especially by project planners, than the technology itself. If you can save that much on drilling and completion, you have gone a long way to survival.

A second area that deserves consideration is the relative utility of template and cluster wells.

The template offers significant advantages in reduction of wellhead fatigue and flow assurance, but has suffered from a long-term perception of delayed drilling schedule waiting on template fabrication. Do you have to wait until a platform is installed before drilling wells? Of course not, you drill through a simple template and install the platform over it.

Our legacy actually includes this concept, and designs have been done for very large multi-well deep-water templates. The problem here is less the technology than the fact that people are content to do what they have always done, the same as the last job.

Having absolved the subsea equipment and sorted the drilling, we can move on to the other cost centre: installation.

Installation of large components

in deep water is not a trivial task – especially if you are committed to using shallow water lift and lower techniques in many thousands feet of water. Called by various names (keelhauling, swing under, to pendulum installation), it has the advantage of requiring only relatively mundane equipment, barges, anchor handlers etc. rather a sophisticated (and admittedly truly wonderful) heavy lift vessel. This retrotechnology has benefited from improved materials and computational capability to the point where its utilisation should be considered. It does look scary at first glance, but it’s rather like watching a magician. Once you know the secret (actually do the calculations), it is disappointingly risk free. The potential for savings far exceeds what could be saved by reverting to simple ‘only what we really need’ designs for subsea equipment.

Is there realistic prospect of deep-water subsea competing with shale oil and gas? There certainly is, and we won’t have to wait as long as the electric car folks have had to. Good and necessary technology can, and should be, nurtured until the bonanza returns. We don’t have to just sit, wait and hope. We have – perhaps in the dusty old bags – the tools and techniques which, when polished up a bit, will ensure a comfortable level of activity in our survival mode.

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doi:10.3723/ut.34.149 Underwater Technology, Vol. 34, No. 4, pp. 149–156, 2017

Technical Paper

www.sut.org

Protection of submarine optical fibre cables on the coral reefs of the Maldives Muneez M*, Vinesh T and Nai-Shyan L Faculty of Computing, Engineering and Technology, Asia Pacific University of Technology and Innovation, Kuala Lumpur 57000, Malaysia Received 28 February 2017; Accepted 1 August 2017

Abstract Submarine optical fibre cables are critical infrastructure that warrant a high level of protection. This paper addresses protection of cables deployed over coral reefs in the Maldives.

Data were collected through an online survey, as well as through conducting structured and semi-structured interviews with telecommunication experts. Descriptive analysis of the data showed that cable burial was expensive and not environmentally sound on Maldivian coral reefs. However, there is also potential for an efficient and environment-friendly technology to be feasibly deployed on coral reefs. Several challenges, including the difficulty in cable protection in the surf zones, were overcome by anchoring articulated pipes and/or Uraducts to the reefs. Few previous studies have addressed protection of submarine cables over coral reefs.

Keywords: submarine cable protection, efficiency, environmental impact, coral reefs, submarine optical fibre cable

1. Introduction Telecommunication cables have been laid on the seabed for over 160 years (Glover, 2016). After the first Atlantic crossing of a submarine optical fibre cable (SOFC) in the 1980s, copper and coaxial cables began to be replaced with fibre optic cables (Hecht, 2004). Optical fibre offers high-speed data transmission, unmatched by any other transmission medium, enabling provision of broadband internet services (Muneez, 2016). Improvements to data speeds over SOFCs continue to add bandwidth to existing infrastructure. Additionally, the development and easy access to mobile and wireless broadband applications have fuelled exponential growth of bandwidth requirements, resulting in deployment

* Corresponding author. Email address: mohamed.muneez@apu.edu.my

of additional SOFC systems (Asia Pacific Economic Corporation (APEC), 2012).

Over 1 185 000 km of SOFCs are active globally, and the combined length of these cables will be 2 million km by 2018 (Coffey, 2014; TeleGeography, 2017). Submarine cables are laid through the Great Barrier Reef, in the Caribbean and through other coral reef ecosystems – such as the Maldives with two domestic and international SOFCs (Zahir, 2012).

Typhoons, earthquakes and other natural disasters have caused extensive damage to SOFCs, and oftentimes such damage results in simultaneous faults (Coffey, 2014; Geisler et al., 2015). Mankind is the greatest threat, however, as fishing and anchoring contributes to nearly 60 % of the faults, while less than 12 % of faults have been attributed to natural causes. Interestingly, it has been impossible to discern the exact cause of one-quarter of all SOFC faults (Carter et al., 2009; Green and Brooks, 2011).

Over 200 SOFC faults are reported annually (Hantover, 2014), thus an SOFC fault is reported once every other day, worldwide. Cable faults have reduced internet access or disrupted services for weeks in many countries (Coffey, 2014). Repair of SOFC faults is tedious, taking on average 20.6 days (Geisler et al., 2015). Delays to repairs at sea are the result of (among others): non-availability of repair ships, as a limited number of repair ships attend to a large geographic area; foul weather; difficulties in locating the damaged area of the cable; and challenges in retrieving buried cables.

Once located, the faulty section of the SOFC is retrieved from the seabed for repairs on board the repair ship. The repaired cables are subsequently re-buried for protection (KIS-ORCA, 2015; Geisler et al., 2015). Disruptions cause huge loss of revenue,

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Muneez et al. Protection of submarine optical fibre cables on the coral reefs of the Maldives

Table 1: International and domestic SOFC systems in the Maldives Network name

Organisation/s

Landing points

Length of SOFCs

Total cost (USD)

WARF Submarine Cable (WARF)

Reliance Infocomm (India) Ooredoo Maldives and Focus Infocom (Maldives) Dhiraagu Maldives (85%) Sri Lanka Telecom (15%)

Hulhu-Malé, Maldives Thivananthapuram, India Galle, Sri Lanka Hulhu-Malé, Maldives (& 4 other islands) Mt. Lavania, Sri Lanka Maldives (inter atoll – 10 landing stations)

1800 km

26 million

1100 km

27 million

930 km

21 million

Maldives (inter atoll)

1200 km

25 million

Dhiraagu Submarine Cable Network (DSCN) Dhiraagu Domestic Submarine Cable Network (DDSCN) Ooredoo Maldives Nationwide Submarine Cable (OMNSC)

Dhiraagu Maldives

Ooredoo Maldives

with average repairs costing USD$1.36 million and up to USD$6 million lost on a fault (APEC, 2012; Geisler et al., 2015). Therefore, it can be estimated that over USD$500 million will be spent annually on damages, thus justifying the requirement for a very high level of protection for such a vital infrastructure.

Burial Protection Index (BPI) determines an optimum burial depth (OBD) on different types of seabed (Mole et al., 1997). The OBD was later analysed by several researchers (Allan, 1998; McGinnis and Williamson, 1998; Hoshina and Featherstone, 2001; Allan and Comrie, 2004; Jonkergouw, 2007; Rapp et al., 2010). Threat lines were incorporated to OBD by Jonkergouw (2001) and enhanced by the Cable Burial Risk Assessment Methodology (Carbon Trust, 2015). But, none of these seminal works addressed trenching on coral. To the best of the authors’ knowledge, no academic studies exist on deployment and protection of SOFCs on ecologically significant coral reefs. This paper endeavours to contribute to the knowledge base on SOFC protection over tropical coral reefs.

1.1. The Maldives and the importance of coral reefs Located in central Indian Ocean, the Maldives is completely surrounded, protected and sustained by living coral (Coleman, 2000). Naseer and Hatcher (2004) argued that the Maldives is the historical prototype of a coral reef province that offers important test environments for models of responses of reefs to marine ecosystems.

Coral reefs exist in 101 countries and territories, including 80 developing nations, and about 850 million people live within 100 km of a coral reef and gain some benefit from the sea (United Nations Environment Programme (UNEP), n.d.; UNEP 2013). Coral reefs cover 284 300 km2 of the ocean, and have a huge impact on the earth’s shape, atmosphere, ocean chemistry, and bio-geographic distribution of life and on diversity of life (UNEP, n.d; Birkeland, 2015). Dependence on and subsequent

vulnerability due to loss of coral reefs are very high among people living near coastal areas and on coral island nations, like the Maldives (UNEP, n.d.).

1.2. Submarine optical fibre cable systems in the Maldives There are four SOFC systems in the Maldives (Table 1).

The telecommunication service providers (TSPs): Dhiraagu and Ooredoo Maldives (Ooredoo) partially own the two international SOFCs connected to the Maldives. The Dhiraagu Submarine Cable Network (DSCN) connects Colombo, Sri Lanka to Hulhu-Malé, Maldives and the WARF connects Thiruvananthapuram, India to Hulhu-Malé (Ibrahim and Ahmed, 2008), with a branch connection to Sri Lanka. The two domestic SOFCs in the archipelago are: Dhiraagu Domestic Submarine Cable Network (DDSCN), which was commissioned on 12 December 2006; and Ooredoo Maldives Nationwide Submarine Cable (OMNSC) deployed by Ooredoo on 7 January 2017. All SOFCs in the Maldives transmit data at 10 Gbps, except the OMNSC, which offers 100 Gbps connectivity. Hence, OMNSC provides 10 times the data speed compared to the other three SOFCs.

2. Methodology Data were obtained through document analysis, online survey (19 respondents), structured interviews (21 respondents) and semi–structured interviews (9 respondents) in the Maldives. Purposive sampling was applied in the selection of executives and engineers from both TSPs. Semi–structured interviews were conducted among seven senior executives and two experienced divers/environmentalists. Additionally, structured interviews were done with network engineers from the TSPs. Microsoft Excel was used for the statistical analysis. Furthermore, this study took the four-step approach to analysis advocated

by Lofgren (2013), which includes reading, re–reading interview transcripts, line-by-line analysis, coding, generating themes, developing an overarching

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Underwater Technology Vol. 34, No. 4, 2017

theme and finally further abstract analysis. The following are the findings and analysis of the data.

Percentages for total respondents 70.0

62.2

60.0

3. Results and discussion

50.0

Cable protection proposed by contractors included burial using water-jetting. However, water-jetting was adjudged to trench a large area of coral and therefore cable burial was rejected by Maldivian TSPs. Contractors also proposed horizontal direct drilling (HDD), but this was difficult to implement not only because of possible damage to coral substrate but most importantly because of high costs, with an additional USD$3 million per cable landing station (CLS) (Zahir, 2012). This would add an extra USD$30 million to the investment of DDSCN, which was both above the budget allocated for the project and would have required drilling with HDD, specialised cable deploying ships and equipment.

Hence, HDD was also abandoned and approval was obtained from the Maldivian government to use cast-iron articulated pipes over coral reefs.

The semi-structured interviewees claimed that trenching is done in shallow areas where threats are high, especially from humans. This is comparable to the findings of Geisler et al., (2015) that SOFCs are buried in shallow waters, 1 m under the seabed, wherever possible. Geisler and colleagues continue to say that, in water depths above 2000 m, cables are protected with steel armour. Nevertheless, armouring may consist of up to three layers with additional insulation with each extra layer of armour increasing the costs, to up to USD$10 000 per km of cable (Allen, 1998: Carter et al., 2009). In deeper waters, single-armoured SOFCs were used, while in shallow areas in the Maldives the cables were protected inside articulated pipes.

Almost three-fifths of the structured interviewees and online survey respondents ranked SOFC burial as the most reliable protection, and just under onethird of the respondents contended that the use of articulated pipes/Uraducts would be most reliable.

While the remaining respondents (over 1/20) considered cable armour to be reliable, no respondent felt that placing metal sheets or rocks/boulders over the cable would offer reliable protection (Fig 1).

Similar findings have been reported in other studies (Gooding et al., 2012; Geisler et al., 2015; Al-Lawati, 2015).

Although burial is universally used to protect SOFCs in shallow waters, nearly all the interviewees agreed that cable burial was not required in the Maldives and had fears of large environmental footprints of trenching, potential costs and minimal human threats (less anchoring, lack of trawl fishing, etc.). Therefore, SOFCs were placed inside articulated

40.0

32.4

30.0 20.0 10.0

5.4

0.0 Cable armour

Articulated pipes/ Uraducts

0

0

Metal sheets

Rocks/ boulders

Burial of cable

Fig 1: Ranking of cable protection techniques with regard to reliability of submarine optical ďŹ bre cables

pipes and surface-laid over coral reefs in the Maldives. Despite several problems in the installation and maintenance of SOFCs over tropical coral reefs, these challenges or risks have, thus far, been mitigated through many promising possibilities.

3.1 Challenges in laying and protection Selection of an SOFC protection measure depends on several factors. While environmental impact and cost seemed to be the key criteria in determining SOFC protection in the Maldives, threats to cables and seabed geology and terrain also contribute to suitability of a cable protection technique (International Cable Protection Committee (ICPC), 2011).

Because of concerns of severe environmental impact, it was not possible to trench coral reefs with currently available trenching technologies, even though SOFC burial offered the most secure protection (Al-Lawati, 2015).

3.1.1. Threats due to the environment Around the world, humans have caused the majority of faults, yet executives unanimously agreed that the greatest challenge to protecting SOFCs in the Maldives were environmental threats (Coffey, 2014).

Prior to deployment of SOFCs, marine surveys were done to assess the currents, the seabed profile and gradient of continental shelf, where the coral reef ends and there is a sharp drop into the deep ocean.

It is difficult to lay cables in this area, not only because of the limitation of minimum bending radius of cables, but also because taking care of suspended cables is key to reduce strumming of cables against the reefs and damage to articulated pipes, cables and the corals.

Despite popular belief that environmental damage due to cable deployment is temporary and only occurs during installation, ‘the presence of a telecommunications cable across a reef may be a permanent and

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Muneez et al. Protection of submarine optical fibre cables on the coral reefs of the Maldives

continuing source of environmental degradation’ (Sultzman et al., 2002). Moreover, some cables in the Maldives were suspended as much as 1 m away from the reef, leaving the SOFCs susceptible to strumming especially in the surf zones (Zahir, 2012). This is in line with studies of Beindorff et al.

(2012), who claimed that cables exposed on the seabed can also be damaged.

and expensive in the Maldives. Delay in the repairs were mainly caused by the difficulty of getting a repair ship. Fault repair at sea is normally outsourced to cable-repair companies that usually take one to four weeks to complete repairs (Coffey, 2014). As such, it took a fortnight to repair the DSCN. Hence, the challenges in SOFC protection due to difficulties in repairs, were significant.

3.1.2. Potential costs Submarine networks are massive financial undertakings requiring months or years to deploy (Coffey, 2014). For example, the four SOFC systems in the Maldives cost USD$99 million. As such, it was difficult for the Maldivian TSPs to obtain the required capital expenditure. Furthermore, the need for a quick return on investment (ROI) was crucial for the multi-million-dollar SOFC systems. A SOFC fault can cost nearly USD$6 million and revenue losses during faults are estimated at USD$1.5 million per hour (Matis, 2012; Geisler et al., 2015). Hence, reliable protection of SOFCs is critical. According to experienced divers, the annual video surveys would be roughly USD$10 000 per CLS. As such, video surveys at 10 CLSs could be estimated at USD$100 000 per annum.

Furthermore, replacements of articulated pipes/ Uraducts are recurring costs for TSPs in the Maldives.

There has been a steady reduction in deployment costs of SOFCs to an estimated USD$ 40 000 per km, yet, the deployment, operations and maintenance of SOFCs still remain huge investments (APEC, 2012).

However, in the Maldives, the situation is different.

It can be deduced from Table 1 that surface-laying cables was a lot cheaper than SOFC burial, since 5353 km of cables have been surface-laid at the rate of USD$8494.30 per km. This justified surface laying of SOFCs, where human threats are extremely low.

3.1.5. Hitches due to other factors On the requirement for fast deployment of SOFCs, the increase of bandwidth requirements of customers justified the roll-out of broadband across the Maldives which required a domestic SOFC network.

The result was the deployment of DDSCN from the north to the south of the archipelago (Zahir, 2012).

While efficiency is critical to cable deployment, there are limits to speeds at which SOFCs can be deployed at sea. This is to ensure cable deployment is done properly, along the designated route. Speed of cable deployment is also limited because the speed of the cable-ship is pre-agreed during the contractual stages.

3.1.3. Difficulties in cable protection Cable protected with articulated pipes was inadequate owing to high tide and surf (wave) action.

Although all the articulated pipes have had to be replaced with Uraducts at every CLS, in the last three years, annual video surveys have continued at exorbitant costs. Executives still felt the need for more time to determine whether Uraducts could be a viable solution. Therefore, cable protection was a challenge that created the need for alternative protection over tropical coral reefs and especially in the surf zones.

3.1.4. Difficulties in repairs Maintenance of SOFCs is slow and expensive, taking on average 20.6 days and up to USD$6 million could be lost on one fault (Geisler et al., 2015). Similarly, maintenance of SOFCs on coral reefs was challenging

3.1.6. Socio/political issues Socio/political factors that were challenges in protecting SOFCs in the Maldives included: the need for cable relocation owing to the building of a new harbour in Dhangethi Island (South Ari Atoll) and building of a foundation pillar of a bridge from Malé to the international airport. For the DSCN, the Sri Lankan government had declared that all CLSs to be cable safe zones. Hence, socio/political issues were important in the protection of SOFCs deployed.

3.2. Challenges to protection of submarine optical fibre cable systems in the surf zone Different protection measures were explored during SOFC deployment. Off the coast of Sri Lanka, attempts were made to use boulders in shallow waters but high currents in the area required very heavy boulders. But, the size of boulders that can be used is limited, as too heavy a weight may crush the SOFCs. Hence protection of SOFCs using rocks/boulders was found to be unsuitable. Therefore, SOFCs were placed inside articulated pipes and surface-laid.

Since the SOFCs were commissioned, initially bi-annual and later annual, video surveys have continued to this day to check the status of the cables in the surf zones. These surveys, costing an estimated USD$100 000 every year, showed that, currents and waves have strummed the articulated pipes against the corals, grinding the articulated pipes and nearly damaging the SOFCs, inside. The replacement of

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damaged articulated pipes is a recurring cost that compelled TSPs to seek advice from contractors.

3.3. Possibilities that could be capitalised on To minimise the strumming of articulated pipes, the contractor recommended anchoring articulated pipes to the coral substrate using steel bolts.

However, the consensus among executives was that this provided insufficient protection, especially in surf zones. Once again, the contractor was contacted and the highly expensive Uraducts, similarly anchored to the coral reef, was proposed. The contractor assured that this would be more resilient, especially for moving cables. To meet these challenges, several possibilities were available to TSPs in the Maldives.

3.3.1. Provision of sufficient redundancy There is inadequate redundancy, as the TSPs solely depended on the microwave and satellite communications as backup. These means of radio communications offered insufficient redundancy, agreed the executives, which tallies with the finding of Coffey (2014). Moreover, the largest stretch of water in the Maldives – the One and a Half Degree Channel – is beyond the limits of microwave communications, and so satellite transmissions were costly and inadequate as redundancy, contended the executives.

Furthermore, the two domestic SOFCs run parallel to each other, increasing the risk of damage to both cables at the same time. As such, except in Huvadhoo Atoll, the DDSCN and OMNSC land on the very same islands in the Maldives.

During faults, TSPs rely on alternative SOFCs to re-route their services. However, the domestic SOFCs in the Maldives mirror each other, except when they cross the One and a Half Degree Channel.

Therefore, it is unlikely that adequate redundancy can be provided through these cables. Extra SOFCs with diverse routes are required to provide sufficient redundancy in the Maldives and this would also better protect the SOFCs that are already surface-laid.

3.3.2. Recommendations of contractors The Maldivian TSPs are new and small players in the submarine cable industry and had to rely on the advice of contractors. Telecom executives in the Maldives consistently referred to having obtained recommendations from contractors in decisionmaking on SOFCs. Thus, it was the recommendations of contractors that offered possibilities in protecting SOFCs over tropical coral reefs.

The SOFC protection measures that evolved were guided by the contractors with articulated pipes that were initially surface-laid. Due to strong waves and currents, the articulated pipes strummed against the

reefs and so, on the contractor’s advice, articulated pipes were then anchored to the reefs using steel bolts to reduce cable movements. However, this protection measure was also found to be insufficient, especially in the surf zones. Later, the contractors proposed the use of Uraducts similarly anchored to the reef substrate.

3.3.3. Collaboration with competitors The Maldivian TSPs share capacity on each other’s international cables during faults, offering limited redundancy. This was practically achieved when Dhiraagu experienced cable damage off the Sri Lankan coast, when Ooredoo shared their capacity for Dhiraagu traffic. Both TSPs also share dark fibre between the islands of Malé and HulhuMalé. Dhiraagu is planning to share capacity once the OMNSC is in service. Therefore, collaboration between the Maldivian TSPs was found to offer possibilities for both organisations.

3.3.4. Risk mitigation The benefit of having a repeater-less system is that the signal regenerators are on land, usually inside CLSs, offering easy access for repairs. This mitigates the risk of long delay in repairs if the repeaters are at sea. Hence through using a repeater-less system, Dhiraagu has removed the likely points of failure as well as provided easy access for maintenance in case of a fault. Further risk mitigation measures include: marking cable locations on all maritime maps and annual video surveys near CLSs. Replacement of the articulated pipes with Uraducts is also a risk mitigation measure that offers possibilities for better protection of SOFCs over the coral reefs in the Maldives.

The reduced threats to SOFC are evident, as there has been no incident of a cable cut in the Exclusive Economic Zone (EEZ) of the Maldives in over 10 years.

Compared to the Maldives, threats to SOFCs off the coast of Sri Lanka (where the DSCN lands) were entirely different with a heavy shipping lane crossing the cable path. After the cable route was declared a cable protection zone by the Sri Lankan government and surveillance of vessel traffic in the area became continuous, the SOFC was cut by a ship’s anchor. Since tropical corals rarely grow below 50 m, cable burial to this depth would have saved the SOFC, as the cable was damaged at 40 m.

3.3.5. Customer demand Demand for higher bandwidth has fuelled the need for SOFCs, especially in Asia and in Africa (APEC, 2012). Recently, enormous amounts of business and personal information are in the cloud, increasing user dependency on high bandwidths. Resort hotels in the Maldives require bandwidths that are

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not possible through radio communications. Furthermore, the customer demand for 24/7 connectivity has also increased the need for reliable protection of SOFCs. Hence, customer demand for faster connectivity and higher bandwidths justifies investment in additional SOFC systems and creates the possibility for more secure cable protection in the Maldives.

3.3.6. Prospects Burial is far more expensive than surface-laying SOFCs (Zahir, 2012), yet cable burial is mandatory in locations where threats are high. Additionally, regarding the feasibility of using a technology that can bury cables 50 % faster than current trenching tools on land, more than two-thirds of the respondents agreed that, such a technology should be trialled. While one-quarter were undecided, 1/20 of the respondents believed that such a technology may not be applicable on coral reefs (Fig 2). Furthermore, any technology that reduces the time or complexity of SOFC installations would likely be adopted.

This indicates that although cable burial is expensive, it is more cost-effective in the long run, as argued by Al-Lawati (2015). Thus, there is increased possibility of cable burial on coral reefs, provided that the technology that can bury SOFCs faster is viable.

3.3.7. Potential benefit of other protection measures Several advantages could be obtained from a technology that is less environmentally disruptive than current technologies available for cable burial at sea.

As such, a trenching technology that offers a possible 50 % to 60 % reduction in the environmental impact of burial on land should be adopted by the submarine cable industry. Furthermore, most participants in the semi-structured interviews believed that, if it can be proved that a burial technology with less environmental impact is available, it will be

Total respondents' percentages 5 27.5 67.5

NO UNSURE YES

Fig 2: Total respondents’ percentages on whether a technology with 50 % improved efficiency of burial of cables on land will contribute to the feasibility of using the technology on tropical coral reefs

Total respondents' percentages 12.8 28.2 59

NO UNSURE YES

Fig 3: Total respondents’ percentages on whether a technology with 50 % to 60 % reduced environmental impact compared to current trenching technologies on land, will be feasible on coral reefs

highly popular. This is because reduction of environmental footprint is in any organisation’s corporate social responsibility policy.

Removal of benthic communities and seabed sediments were observed in an area 2 m to 3 m on either side of buried cables (Bald et al., 2014). Hence, most respondents agreed that a technology with a potentially reduced environmental footprint compared to common burial tools on land will make the technology feasible on coral reefs. Although, more than onethird were uncertain, over one in ten believed that such a technology may not be feasible on tropical coral reefs, as illustrated in Fig 3. Thus, potentially reduced environmental impact is a possibility that could be obtained from a trenching technology not yet employed at sea. Therefore, there seems to be prospects for SOFC burial on coral reefs, if a technology could also potentially reduce its environmental impact.

4. Conclusion In summary, burial of SOFCs was unsuitable in the Maldives due to fears of extensive damage to corals and high cost. The reasons for not burying SOFCs in the Maldives include: the requirement for additional equipment for trenching increasing the cost above the budget allocated for the SOFC projects.

From the interviews it seemed that cost was a major consideration in the selection of cable landing sites as well as in deciding the protection measure for SOFCs over the coral reefs.

Unlike the rest of the world, the threats to submarine cables due to human activities are minimal in the Maldives. The fishing technique used is rod and line, and no trawl fishing is done. In addition, the threat of heavy anchoring in Maldivian seas is low. This is because the vessels plying the waters of the country are smaller, and most vessels use small anchors that are usually manoeuvred manually. Hence, the major threat to SOFCs was due to the environment, and

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thus the deciding factor to surface-lay cables was the potential environmental impact of burial.

The most cost-effective and environmentally friendly protection on the coral reefs in the Maldives is to place SOFCs inside articulated pipes or Uraducts, and surface-lay over the coral reefs. From the beach manholes to areas where the threat of damage due to strumming is lower, articulated pipes could be used.

Where the cables may strum against the seabed (e.g. surf zones), Uraducts bolted to the reefs reduces the strumming and high maintenance costs. The SOFCs, from the end of the reef to the deep ocean, can be single armoured cables. Although Uraducts have offered better protection compared to articulated pipes, some Uraducts have also been damaged.

Thus, it remains to be seen whether this will be a long-term solution.

If higher burial speeds are achieved and the environmental impact of present trenching methods is reduced or an alternative solution is found, there are prospects for cable burial on coral reefs. Burial on the coral reefs of the Maldives could be to water depths of 50 m, which would be the extent of healthy coral growth, and the undersea currents and waves are not strong at these depths. In addition, the width of trench produced by microtrenching is slightly wider than a double armoured cable. Therefore, compared to burial technologies on land and at sea, it would offer other efficiencies apart from the reduced damage to the reef. Cable burial would also eliminate the costs of video surveys and replacement costs of articulated pipes/ Uraducts. Therefore, for commercial reasons and for better cable protection resulting from increased efficiency through higher burial speeds and a smaller environmental footprint, micro-trenching technology should be trailed on tropical coral reefs by the SOFC industry.

Acknowledgment The authors acknowledge the guidance, help and discussions from: Dr Thomas Patrick O’Daniel, Faculty of Computing. Engineering and Technology, Asia Pacific University of Technology and Innovation, Malaysia; and Dr Aishath Mahfooza, Chief Physiotherapist, Indira Gandhi Memorial Hospital, Maldives.

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doi:10.3723/ut.34.157 Underwater Technology, Vol. 34, No. 4, pp. 157–169, 2017

Technical Paper

www.sut.org

Investigation of slug mitigation: self-lifting approach in a deepwater oil field Adefemi IO*1, Kara F1 and Okereke NU1,2 1 Oil and Gas Engineering Centre, Cranfield University, Bedfordshire, UK 2 Chemical and Petroleum Engineering Department, Afe Babalola University, Ado-Ekiti, Nigeria Received 6 January 2017; Accepted 17 August 2017

Abstract Slug flow is a flow assurance issue that staggers production and, in some cases, ‘kills the flow’ of the well. Severe slugging, a type of slugging which usually occurs at the base of the riser column, causes large amplitudes in the fluctuation of pressure within the riser column and consequently damages equipment placed topside. An adaptation of a novel concept to slug mitigation: the self-lifting model, is presented.

This model presents variations to the internal diameter of the self-lift bypass to produce effective mitigation to severe slugging.

Keywords: slug, severe slugging, self-lift, riser base pressure, OLGA

1. Introduction An understanding of the multiphase flow phenomenon (a flow characterised by the gas and liquid phases), as well as the overall potential effects to the processing facilities, is required in the design of multiphase flow pipelines (Al-Kandari and Koleshwar, 1999). Al-Kandari and Koleshwar (1999) also argued that under or over-design of the piping can be counterproductive and may significantly affect process plant operability as well as the mechanised part of pipeline system. Therefore, the paper emphasizes the understanding of flow assurance and severe slugging in multiphase flow.

A major flow assurance issue in multiphase flow is the slugging phenomenon. The formation of slug arises from the flow regimes commonly found with the liquid and gaseous phases of hydrocarbon (crude oil and gas) in transit (Al-Kandari and Koleshwar, 1999). Shotbolt (1986) defined slugging

* Corresponding author. Email address: israel.adefemi@gmail.com

as an intermittent flow that ‘results in alternate delivery of liquid and gas phases’. This delivery is caused by the difference in superficial velocities of the phases, which can cause liquid surges within the pipes.

Slugging can be observed within the vertical or inclined flexible riser and within the horizontal section of the piping lying on the seabed (Oseyande, 2010). The inclined orientation of flowlines, with hydrocarbon content flowing upwards, does tend to assist the initiation of slug flow (Al-Kandari and Koleshwar, 1999). Shotbolt (1986) emphasises that slug flow affects three major areas of concern: 1. It impacts the ‘volume and arrival rate of the worst liquid slug expected’, as well as the ‘differences between pressures and flowrates at the start and end of the gas bubble flow’.

2. Sufficient riser base pressures capable of stopping flow within the pipeline (i.e. ‘kill’ the well flow) can be generated when the riser is filled completely with liquid. Research carried out by Yocum (1973) stated that 50 % capacity losses in flow have been observed to avoid slugging in risers.

3. Vibrations may be generated along the riser owing to momentum change reactions and its dead weight as gas and liquid phases alternately flow through the piping.

Sagatun (2004) corroborates this by stating that the pressure differentials created during slug flow causes fatigue and consequently wear and tear of the process equipment. These areas of concern also affect the delivery of the hydrocarbon content at the receiving facilities; for example flow irregularities observed in the oil-water separator causing liquid surges in volume.

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1.1. Multiphase severe slug flow Depending on the severity of the slug flow, three different types of slugging can be identified in multiphase flow (Tang and Danielson, 2006): • hydrodynamic slugging; • slugging due to ‘operationally induced surges’; and • severe or terrain slugging.

The conditions for each type of slug flow occur on a regular basis during the production of hydrocarbon in deepwater oil fields. However, severe or terrain slugging is observed mainly at the riser base.

Therefore, this paper focuses on investigating a self-lifting approach as mitigation for severe slugging at the riser base due to the inclination needed for the technique to be effective.

Severe slug is observed at low gas rates of hydrocarbon and Barbuto (1995) describes how severe slugging can occur when: • There is a ‘stratified downward flow in the production line’ to the riser base.

• Pressure builds up in the production line that exceeds the designed allowable riser pressure.

Severe slug occurs from the accumulation/blockage of liquid at the low point-elevation of negatively inclined/vertical piping or flowline (riser). The inclination is caused by the geometry of the pipeline (usually a dip at the riser base) or the terrain (seabed bathymetry).

The accumulation of liquid at the low pointelevation causes liquid slugs to form. Jones et al.

(2014) states that this type of slugging is a cyclic

process and liquid slugs formed are of ‘at least one riser height’. As depicted in Fig 1, Ogazi (2011) summarised four major stages of severe slug as: • • • •

slug build up/formation; slug production; slug blow-out; liquid fall-back.

A study by Schmidt et al. (1979) classified severe slugging into two different types: severe slugging with liquid slugs usually of riser length, and severe slugging with slightly aerated liquid slugs, the length of which did not exceed the height of the riser pipe. They also stated that the first type of severe slugging could be eliminated by varying either the flowrate of the liquid or the flowrate of the gas.

However, with the second type of slugging, depending on the flowrate of the liquid, an increase in the flowrate of the gas could cause annular flow or slug flow to form (Schmidt et al., 1979).

Malekzadeh et al. (2012) later categorised severe slugging into three types: severe slugging type 1 (‘pure liquid slug length larger than the riser height’), severe slugging type 2 (‘pure liquid slug length smaller than the riser height’) and severe slugging type 3 (‘growing long aerated liquid slug in the riser followed by a gas blow down stage’).

1.2. Slug mitigation approaches There are several established approaches to the mitigation of slugging in deepwater oil fields.

Jones et al. (2014) stated that the most effective mitigation approach to slugging is riser top valve

Fig 1: Different stages of severe slug (Ogazi, 2011)

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choking (topside choking). Jansen et al. (1996) agreed with Schmidt et al. (1979) that ‘choking eliminates severe slug by increasing the back pressure and acting as a flow resistance proportionally to the velocity of the liquid slug in the riser’. This meant that choking could potentially balance and maintain the multiphase flow with ‘minimal back pressure’. However, Ogazi et al. (2011) argued that an inherent disadvantage with this approach is the extra back pressure induced on the pipeline and recommended the use of an active feedback control (dynamic choke) that could attenuate the slug flow and increase production.

Another slug mitigation approach is the use of a rise base gas injection system (gas lift). Jansen et al.

(1996) prescribed gas lift as a viable method for eliminating severe slug, by ‘increasing the velocity and reducing the liquid holdup in the riser’. However, Al-Kandari and Koleshwar (1999), through a successful trial, stated that an increase in gas-to-oil ratio (GOR) led to slug-like flow regime within a 36-inch crude transfer line and there were consequent problems in ‘associated separator train at the gathering centre’. However, Jansen et al. (1996) highlighted this approach as being quite costly due to the ‘large gas volumes needed to obtain a satisfactory stability of the flow in the riser’. Jones et al. (2014) describe other passive methods including: • altering the pipeline geometry to reduce or eliminate slugging, although this approach is not cost-effective for already existing subsea pipelines; and • using slug catchers, which can be comparatively cheap, but space and weight of installation topside is a crucial issue.

This study, however, focuses on a relatively novel approach in the mitigation of severe slugs through the use of ‘self-gas lifting’.

Fig 2: Schematic diagram of self-lift approach (Barbuto, 1995)

This design mitigates severe slug by conveying the gas of the multiphase flow from point B to point A; this is possible due to the differences in pressure at point B and A. (Barbuto, 1995). The gas bubbles conveyed into the vertical line ‘help break up the liquid slugs’ (Ogazi, 2011). Moreover, the quantities of gas contained in oilfields were either greater or lesser compared to the oil (Shotbolt, 1986). That meant that although the gas cap of a reservoir was not noticeable, the oil still contained a considerable amount of dissolved gas.

Tengesdal (2002) used this novel approach to model the mitigation of severe slug at the riser base.

The approach was not considered to need any additional gas injection from the platform and was therefore termed ‘self-gas lifting’ (Tengesdal, 2002). This approach appeared to be quite beneficial as any extra-cost needed to compress external gas for mitigation of severe slugs, to transport the gas, and to store it on platforms topside, could all be reduced or completely waived.

The research concluded that:

1.3. Self-lift approach in severe slug mitigation The self-lift approach was invented and developed as a ‘method to eliminate severe slug in multiphase flow subsea lines’ (Barbuto, 1995). Barbuto (1995) described this novel approach as the use of an auxiliary line that connects the downwards inclined flowline with the main riser. A basic schematic is provided in Fig 2 detailing the configurations of the connection points:

• The approach caused a reduction of hydrostatic head within the riser and of the pressure in the production line.

• From experimental observations, it is ideal to have the ‘injection point at the same level or slightly higher than the take-off point for optimum performance’.

• From experiments, it was observed that a ‘small choking was needed to stabilize the flow when the injection point is at a higher level than the take-off point’.

• This approach to mitigating severe slug was ‘not sensitive to changes with liquid and gas flowrates’.

• Point A – the connection point between the auxiliary line and the vertical line (main riser); • Point B – the connection point between the production line and the auxiliary line; and • Point C – the connection point between the production line and the vertical line.

Tengesdal (2002) suggested that a variable choke controlled by a PC-based system would improve the flow as shown in Fig 3.

Further studies proposed by Tengesdal to improve its adaptability in the industry included: the study of self-lift with variations in the internal

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Fig 3: Self-lift with small choking at injection points (Tengesdal, 2002)

diameter of the self-lift bypass and an application of choke at the bypass. Previous applications of selflift have focused on experiments in the laboratory, which do not truly approximate real life scenarios.

Therefore, this study focused on the effectiveness of self-lift with data obtained from an oil field.

2. Self-lift model 2.1. Background, numerical model and validation An experimental slug (Fabre et al., 1990) was first modelled for validation of the numerical tool, OLGA,

after which the self-lift method was applied to prove the concept.

A few experiments were conducted by Fabre et al. (1990) using a 2.09" internal diameter transparent polyvinyl inclined pipe of length 25 m (designated ‘pipeline’) and a connecting vertical pipe of height 13.5 m (designated ‘riser’). Both pipes were connected using a 0.5 m radius bend. The test facility used an air/water mixture as fluid. The velocity of the air as the gaseous phase was obtained from the mass flowrate using its density at standard temperature and pressure (20 °C and 100 kPa).

However, this study will focus on one experiment (Exp-1) to validate the model.

Exp-1 superficial velocities for gas and liquid at standard conditions were superficial velocities of gas (Vsg) = 0.45 m/s and water (Vsl) = 0.13 m/s, respectively. The pipeline was inclined to a negative slope (–1 %). The experiment agreed with literature that ‘negative slope is generally considered a necessary condition for an unstable cycle’ (Fabre et al., 1990; Schmidt et al., 1979).

The geometry of the model in Fig 4 corresponds with the experiment. An increase in meshing (more section lengths) enabled better accuracy; therefore, three different mesh sizes at constant time-step were analysed. The time-step used was 0.0001 s. The coordinates of the pipe

Overview

[m]

Vsg0.45Vsl0.13horplus : GEOMETRY-5

Sections [24]

13 12.5 12 11.5 11 10.5 10 9.5 9 8.5 8 7.5 7 6.5 6 5.5 5 4.5 4 3.5 3 2.5 2 1.5 1 0.5 0 –0.5 0

1

2

3

4

5

6

7

8

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 [m]

Fig 4: Model geometry of Exp-1

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Table 1: Pipe coordinates and section lengths Pipe

x [m]

Starting point Negatively inclined pipe (pipeline) Vertical pipe (riser)

0 0 25.5 –0.801 25.513 25.5 13.199 14 Total number of sections

y [m]

Length [m]

Outlet

Riser Source Injection point

Take-off point Inlet

Pipeline

Bypass line

Riser base

Fig 5: Visual representation of the self-lift literature model (not geometrically accurate)

and section lengths are given in Table 1. For results of analysis, see section 3. For more detail on the OLGA numerical model of the experiment, see Appendix A. The self-lift concept uses a bypass line to ‘lift’ the flow at a certain point above the riser base (Tengesdal, 2002), as shown in Fig 5. The OLGA model of this concept uses two additional functions: a process equipment called the ‘phase-splitter’ and an internal node. The phase-splitter, which acts as the takeoff point along the pipeline, functions between an internal network node and a network separator. A bypass pipe of internal diameter 1.299" is connected to the take-off point at 2.567 m from the riser base, along the pipeline. The bypass pipe is then connected to an internal node which serves as the injection point into the riser at 20 cm from the riser base (see Table 2).

Elevation [m]

No. of Sections

–0.801 14

Mesh 1 25 14 39

Mesh 2 50 28 78

Mesh 3 55 28 83

2.2. Field data Field data from a Chevron deepwater oil field in West Africa were obtained for study of the self-lift concept. In a previous study, the field experienced hydrodynamic slugging at low production rates in one of its flow loops (which will henceforth be referred to as flow loop F1). However, the focus of this study is severe slugging; the conditions of hydrodynamic slugging were aggravated to result in an example of typical severe slugging type one (1) and three (3): SS1 and SS3.

The field operates at a depth greater than 1000 m with four flow loops connected to the topside via a riser system. For the purpose of this study, only flow loop F1 will be considered. Hydrocarbon is drawn from well 1 (W1) to the manifold through a 6" pipeline. Flow loop F1 comingles well 1 (W1) and well 2 (W2) using the manifold, and transports the hydrocarbon via an 8" pipeline from the manifold to the riser. The geometry of F1 as well as its pressure and temperature are given in Table 3.

The fluid flowing through flow loop F1 was defined using PVTsim 20. The water-cut of the fluid is defined at 3 % from the field data. GOR using the PT flash is verified as 385.91 Sm3/Sm3 at a minimum pressure of 1 bar and maximum pressure of 300 bar, and minimum temperature of –20 oC and Table 3: Flow loop F1 geometry, pressure and temperature.

Station

Separator (TS) Manifold (MF) Wellhead (W1)

Flow loop F1 Total vertical depth (ft)

Pressure (psia)

Temperature (°F)

164 –4800 –4750

290 1300 1678

150 168 180

Table 2: Pipe coordinates and section lengths Pipe

x [m]

y [m]

Length [m]

Elevation [m]

No. of sections

Starting point Pipeline to take-off point Bypass line to injection point Take-off point to riser base Riser base to injection point Riser

0 22.933 22.936 25.5 25.5 25.5

0 –0.720 –0.601 –0.801 –0.601 13.2

22.944 0.119 2.568 0.2 11

–0.720 0.119 –0.081 0.2 11

Mesh 25 2 5 1 22

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maximum temperature of 120 oC. The API of the fluid is given as API 47º. The densities of the oil and gas (641 kg/m3 and 18.2 kg/m3, respectively) were also flashed from the fluid. The properties of the fluid are given in Table 4.

Two wells (W1 and W2) were comingled along flow loop F1 at the manifold. Oil, gas and water flowed at volumetric flowrates of 6722 BoPD, Table 4: Fluid properties Component

Mol. % Flow loop F1

Carbon dioxide Nitrogen Methane Ethane Propane Iso-butane N-butane Iso-pentane N-pentane Hexanes Heptane plus

0.81 0.13 43.3 7.49 7.29 2.61 3.28 1.98 1.56 2.72 28.83

4 MMScf/d and 0 STB/d, respectively, for W1. Oil, gas and water flowed at volumetric flowrates of 22 157 BoPD, 23 MMScf/d and 6 STB/d, respectively, for W2. The mass flowrates were then converted and adjusted from the volumetric flowrates for easier input in OLGA. For mathematical conversion of the flowrates, see Appendix A. Fluid flows to W1 to comingle at the manifold through a 6" pipeline, and from the manifold to the riser through an 8" pipeline. The pipeline has a pipe roughness of 0.002 m and has two walls; the outer wall serves as insulation. Wall 1 and 2 have thicknesses of 0.009 m and 0.011 m, respectively. The ambient temperature is 5 oC, and the mean heat transfer coefficient on the outer wall is 2.3 W/m2K. A total number of 142 sections were allocated for the meshing of the model, which is depicted in Fig 6. The model time-step was: 0.0001 s. The coordinates of the pipe and section lengths are given in Table 5.

The self-lift bypass was connected to the pipeline at the take-off (TK) at a distance of 274.67 m from

0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 1,900 2,000 2,100 2,200 2,300 2,400 2,500 2,600 2,700 2,800 2,900 3,000 3,100 3,200

[m]

50 0 –50 –100 –150 –200 –250 –300 –350 –400 –450 –500 –550 –600 –650 –700 –750 –800 –850 –900 –950 –1,000 –1,050 –1,100 –1,150 –1,200 –1,250 –1,300 –1,350 –1,400 –1,450

[m]

Fig 6: Model geometry of field data

Table 5: Pipe coordinates and section lengths Pipe Starting point Pipe 1 (W1-MF) Pipe 2 (MF-RB) Pipe 3 (RB-FPSO) Pipe 4 (FPSO-Sep)

x [m] 0 1066.8 2712.649 3139.369 3204.745

y [m] –1447.8 –1447.8 –1463.04 0 49.987

Length [m]

1066.8 1645.92 1524 82.296

Elevation [m]

0 –15.24 1463.04 49.987

No. of sections Mesh 35 54 50 3

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Table 6: Pipe coordinates and section lengths Pipe

x [m]

y [m]

Length [m]

Elevation [m]

No. of sections

Starting point Pipe 1 (W1-MF) Pipe 2 (MF-TK) Pipe 3 (TK-RB) Pipe 4 (RB-INJ) Pipe 5 (Bypass) Pipe 6 (INJ-FPSO) Pipe 7 (FPSO-Sep)

0 1066.8 2438.05 2712.72 2721.254 2721.254 3139.369 3204.745

–1447.8 –1447.8 –1460.5 –1463.04 –1433.779 –1433.779 0 49.987

1066.8 1371.309 274.232 30.48 284.014 1493.5002 82.296

Mesh 35 45 9 1 9 49 3

the riser base and reinjected into the riser column at 30.48 m from the riser base (see Fig 7 and Table 6).

This is supported by literature: the re-injection point should be located at a distance from the riser base which is 2–3 % the length of the riser (Sarica and Tengesdal, 2000). Due to an increased number of total sections (151 sections), the time-step was reduced to 0.000000001 s to enable transient convergence.

Outlet: FPSO (Separator)

Riser

Injection point

Manifold

Well head Inlet

Take-off point

Production line

3. Results and discussion: numerical models

Bypass line Riser base

Pressure (Bara)

Fig 7: Visual representation of the self-lift OLGA model based on field data (not geometrically accurate)

2.4 2.2 2 1.8 1.6 1.4 1.2 1 0

50

100

150

Time (s) Fabre-Vsg0.45Vsl0.13

Numerical model

Fig 8: Validation of numerical model

2.4 2.2 Pressure (bara)

3.1. Literature data: validation Simulations involving Fabre et al. (1990) research studies were run at an angle of –1 % to simulate severe slugging experimentally. The numerical model on OLGA first had to be validated to depict the conditions of the experiment correctly, and then self-lift was applied to the model to mitigate severe slugging.

The air-water fluid numerical model was validated correctly against experiments at superficial velocities of gas (Vsg) and water (Vsl) of 0.45 m/s and 0.13 m/s, respectively. Severe slugging was observed at riser base as shown in Fig 8, where the higher pressure of 2.249 Bar was reached over the duration of the 30 min simulation. The cyclic fluctuations of pressure in the prediction of the numerical model matched the experiment. This implied that the model could correctly predict the effect and presence of severe slugging.

In order to achieve more precise results without decreasing to a smaller time-step needlessly, three different types of mesh (sectioning) were compared. The mesh with 78 sections in Fig 9 had the best convergence with the literature data.

The self-lift concept was applied to severe slugging modelled from published data. Tengesdal (2002) numerically modelled the gas re-entry point at a distance of 20 cm from the riser base to depict a complete elimination of slug flow.

Slug flow was completely eliminated using selflift at the riser base and at the top of the riser of the experimental slug case (Fabre et al., 1990), as evidenced by the more stable pressure. As shown in

0 –12.7 –2.54 29.261 26.721 1433.7792 49.987

2 1.8 1.6 1.4 1.2 1 0

20

40 Mesh: 39 Mesh: 83

60 80 Time (s)

100

120

140

Mesh: 78 Fabre-Vsg0.45Vsl0.13

Fig 9: Mesh convergence of numerical model with literature data

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2.5 2 1.5 1 0.5 0

The trend, shown in Fig 14, of the flow regime at the bypass pipe further confirmed this fact. This implied that the flow in the bypass could create more ‘turbulence’ when re-joining the flow in the riser column, as well as the formation of slugs.

The riser column trend of its pressure, liquid hold-up and flow regime (see Fig 15 and Fig 16) confirms that although there are no cyclic fluctuations in pressure, the flow of the liquid in the column was not stable; the flow was fluctuating between a bubble flow and slug flow.

3.2. Field data: slugging A West Africa, Chevron-operated deepwater oil field experienced hydrodynamic slugging from one of its wells. Hydrodynamic slugging was observed from 80.00 70.00 Volume flow (m3/d)

Pressure (bara)

Fig 10, the highest riser base pressure was recorded at 2.114 Bara over the duration of the 30 min simulation, which is quite reduced from that recorded in the severe slugging model (2.249 Bara).

It can also be observed from the liquid hold-up shown in Fig 11 that the riser base is full of more stable liquid and no gas. The liquid hold-up is the fraction of the liquid volume with respect to the internal diameter of the pipe. This implies that the self-lift technique was effective in diverting the gas from the riser base and just liquid remained.

Effects of the self-gas lift were more noticeable from the bypass pipe connecting the take-off point and the injection point through the riser column.

As shown in Fig 12, liquid was passed through the bypass pipe to the injection point. Further analysis (see Fig 13) showed that gas and liquid were flowing through the bypass pipe, and that ‘short slugs’ (slugs of short length that form and dissipate intermittently) formed.

60.00 50.00 40.00 30.00 20.00 10.00 0.00 0

0

20

40

60

80 Time (s)

Riser base pressure

100

120

140

200 400 600 800 1000 1200 1400 1600 1800 Time (s)

QL [m3/d] (BYPASS LINE.PIPE-1.1) “Liquid bulk volume flow” QG [m3/d] (BYPASS LINE.PIPE-1.1) “Gas volume flow”

Riser top pressure

Fig 13: Gas and liquid flow at bypass

1.02 1 0.98 0.96 0.94 0.92 0.9 0.88 0.86

Flow regime

Liquid holdup

Fig 10: Self-lift riser base and riser top pressure

0

200

400

600

800 1000 1200 1400 1600 1800 Time (s)

Flow regime: 1=Stratified, 2=Annular, 3=Slug, 4=Bubble 0

200 400 600 800 1000 1200 1400 1600 1800 2000 Time (s)

Fig 14: Flow regime at bypass

Fig 11: Liquid hold-up at riser base

2.5 2 Pressure (bara)

1.2 1 Liquid hold-up

4 3.5 3 2.5 2 1.5 1 0.5 0

0.8 0.6 0.4

1.5 1 0.5

0.2 0

0 0

200

400

600

800 1000 1200 1400 1600 1800 Time (s)

Fig 12: Liquid hold-up at bypass

0

200

400

600

800 1000 1200 1400 1600 1800 Time (s)

Fig 15: Pressure in the riser column

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W1 along flow loop F1 at production rates that were lower than 3000 barrels of oil per day (BOPD) and low reservoir pressure within the vicinity of the well. The same conditions were first modelled to observe the reported hydrodynamic with the pressure fluctuations (Fig 17).

Due to the geometry of the flow loop, severe slugging could not form easily at the riser base.

Well 2, comingling with the flow at the manifold, is a fast-flowing well and also acts as a gas injection well for the flow loop.

4 3.5 3 2.5 2 1.5 1 0.5 0 0

500

1000

3.2.2. Self-lift numerical model The self-lift concept was applied to the severe slugging modelled from the field data with varying degrees of effectiveness. Slug flow persisted with the application of self-lift to the severe slugging observed from the model. Fig 20 shows that transitional severe slugging at the riser base was observed in the numerical model with a higher riser base pressure of 108.069 Bara. The highest total number of slugs per second recorded along the flow loop was 4 slugs per second, as seen in Fig 21.

From literature, finding the optimal re-injection point in the riser is crucial to the mitigation of slugging, with the optimal re-injection point prescribed as 2 % to 3 % of the riser length (Sarica and Tengesdal, 2000). However, Fig 22 shows that

1500

60

Riser column flow regime: 1=Stratified, 2=Annular, 3=Slug, 4=Bubble

50 No. of slugs

59.3 59.2 59.1 59 58.9 58.8 58.7 58.6 58.5 58.4 58.3

40 30 20 10 80 000

70 000

60 000

50 000

40 000

30 000

20 000

0

0

10 000

Time (s)

9000

8000

7000

6000

5000

4000

3000

2000

1000

Time (s) 0

Pressure (bara)

Fig 16: Flow regime in the riser column

10 000

Flow regime

3.2.1. Adjusted ďŹ eld data: severe slugging The conditions for hydrodynamic slugging observed with the field data were aggravated by tuning the superficial velocities of oil, gas and water of W1, to model a severe slugging condition at the riser base. To observe slugging, the flow of crude

oil from W2 leading into the manifold was turned off. Severe slugging was observed within a 24 hr simulation time, with cyclic fluctuations of pressure at superficial velocities of gas and liquid (oil and water) as 0.523 m/s2 and 0.303 m/s2, respectively, and a higher pressure of 109.846 Bara, as seen in Fig 18. Fig 19 shows that the number of slugs recorded in the flow loop were as high as 34 slugs per second after the first 2 hrs.

Fig 19: Number of slugs in the pipeline 120

Fig 17: Hydrodynamic slugging Pressure (bara)

100

100 80 60

80 60 40 20

40

Fig 18: Severe slugging

80 000

70 000

25 000

60 000

20 000

50 000

10 000 15 000 Time (s)

40 000

5000

30 000

0

20 000

0

10 000

0

20

0

Pressure (bara)

120

Time (s)

Fig 20: Self-lift with severe slugging

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changing the re-injection points (30.48 m, 41.15 m, and 45.72 m along the riser length) did not eliminate the slug flow.

A study was also conducted to ensure only the flow of gas in the bypass pipe, by applying different sizes of the internal diameter of the bypass pipe: 0.55 m; 0.2032 m; 0.20 m; 0.18 m; 0.16 m; 0.15 m; 0.14 m; 0.12 m; 0.10 m; 0.08 m; and 0.06 m. Although severe slugging was observed in the bypass pipe, the bypass internal diameter, 0.16 m, 0.10 m, 0.06 m showed the most effective change in trend of the severe slugging (see Fig 23). Fig 24 shows that liquid and gas flow were present in the bypass pipe.

In Fig 25, the application of a choke at the bypass increased the slug formation time and, consequently, the length of the slug. This meant that the riser base pressure was increasing over a longer duration, and the length of the liquid accumulation increased beyond the height of the riser into the production pipeline.

4.5 4 3.5 3 2.5 2 1.5 1 0.5 0

120

80 000

80 60 40 20 80 000

70 000

60 000

50 000

40 000

Fig 21: Self-lift 2 % total number of slugs in the pipeline

30 000

Time (s)

20 000

10 000

0 0

70 000

60 000

50 000

40 000

30 000

20 000

10 000

Pressure (Bara)

100

0

Number of slugs

3.2.3. Self-lift in conjunction with gas injection Riser base gas-lift (RBGL) was also explored and modelled using field data, to compare its effectiveness with self-lift. Gas was injected into the riser column at 86 ºF and mass flowrate of 1.5 kg/s. This

successfully eliminated severe slugging at riser base, with a stabilised pressure of 35 Bara.

Applying self-lift with RBGL yielded unique results: the pressure at the riser base exceeded the design parameters. This result can be explained from the concept of slug flow; pressure fluctuations in slug flow are usually caused by the trapping of gas pockets behind varying lengths of liquid accumulations (Luo et al., 2011; Tang and Danielson, 2006). The bypass pipe reintroduced slug flow (severe slugging) into the riser column at a point beyond the riser base, therefore trapping the inflow of gas from the RBGL, and consequently increasing the pressure at the riser base.

This meant that RBGL cannot be applied with self-lift.

However, external gas injection was modelled with self-lift by placing the entry point of gas further downstream, beyond the re-injection point of the bypass pipe. Injecting gas at mass flowrate of 1.5 kg/s further downstream showed a more stabilised fluid flow at an average pressure of 44.71 Bara. It is observed that the pressure of the combined slug mitigation techniques was higher than RBGL and also less stable, unlike with just RBGL (see Fig 26).

Time (s)

120

C4-0.16 ID

C8-0.10 ID

C10-0.06 ID

Fig 23: Self-lift 2 % bypass internal diameter sizing 80

2% gas re-injection 3% gas re-injection

Fig 22: Self-lift gas re-injection points

10 0000

Time (s) 2.7% gas re-injection

90 000

80 000

70 000

60 000

50 000

40 000

Time (s)

30 000

80 000

70 000

60 000

50 000

40 000

30 000

20 000

10 000

0

0

20 000

20

20000 15000 10000 5000 0 –5000 10 000

40

0

60

Volume flow (m3/d)

Pressure (Bara)

100

Bypass gas volume flow Bypass total liquid volume flow

Fig 24: Self-lift bypass volume flows

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120

Pressure (Bara)

100 80 60 40 20 0 0

2000

4000

6000

8000

10 000 12 000 14 000 16 000 18 000 20 000 Time (s)

100 % Choke opening

80 % Choke opening

60 % Choke opening

50 % Choke opening

40 % Choke opening

35 % Choke opening

30 % Choke opening

28 % Choke opening

25 % Choke opening

20 % Choke opening

18 % Choke opening

15 % Choke opening

80 000

70 000

60 000

50 000

40 000

30 000

20 000

10 000

60 40 20 0 0

Pressure (bara)

Fig 25: Self-lift manual choke at bypass

Time (s) 1.5kg/s RBGL

Self lift with 1.5kg/s gas Inj

Fig 26: Self-lift with gas injection

4. Conclusion Self-lift, which has not been deployed in a field situation, may be adopted as a passive slug mitigation technique, which must be adapted on a case-bycase basis, to produce maximum effectiveness. Selflift was verified by numerically modelling it to severe slugging observed experimentally in literature (Fabre et al., 1990). Self-lift completely eliminated slug flow and yielded a more stable pressure at the riser base. The application of self-lift reduced the riser base pressure by 6 % from 2.249 Bara to 2.114 Bara.

Self-lift achieved a complete separation of the fluid phases (gas and liquid) at the riser base using published data. Short slugs were observed in self-lift bypass pipe. The results of self-lift modelled from published data showed that liquid accumulated in the bypass pipe, leading to slugging within the pipe. It was observed that slugs were reintroduced into the riser column, leading to surges in liquid volume. Field data were successfully modelled numerically to depict the reported hydrodynamic slugging.

Self-lift was applied to the severe slugging numerical model based on field data. Although it did not

eliminate severe slugging at the riser base, the total number of slugs per second at riser base were reduced from 34 to 4 and the higher pressure reduced from 109.846 Bara to 108.069 Bara. This meant that self-lift resulted in a 1.62 % reduction in riser base pressure and an 88 % reduction in slugs per second within the flow loop. Self-lift modelled using field data also showed that liquid and gas volume flows were observed in the bypass pipe.

Consequently, severe slugging was also observed within the bypass pipe. The variations of internal diameter of the self-lift bypass pipe with field data showed that the most effective change in trend of severe slugging occurred with 0.16 m, 0.1 m and 0.06 m. Self-lift modelled using field data, with a manual choke at the bypass, increased the slug formation time; pressure build up and liquid accumulation were longer.

Using field data, the self-lift technique applied in conjunction with the RBGL caused the riser base pressure to exceed its design parameters, although external gas injection could occur at a point beyond self-lift bypass re-injection point. Self-lift was also applied in conjunction with gas injection. The combination yielded a more stable pressure at riser base, but the RBGL technique was more effective alone than with self-lift. With the presence of liquid in the bypass, the numerical modelling tool was simply splitting the fluid flow rather than splitting the fluid into its phases. Self-lift is dependent on fluid flow as well as the gas-to-oil ratio of the hydrocarbon; it is more suitable for fluid flows of relatively low mass flowrates. It is also not easily adaptable to work in conjunction with RBGL in deepwater oil fields. Slugging at riser base is aggravated by the slug flow reintroduced into the

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riser column through the self-lift bypass, and consequently increases the riser column pressure.

It can be inferred that improving the geometry design of the self-lift bypass pipe would reduce the likelihood of slugging within the pipe.

References Al-Kandari AH and Koleshwar VS. (1999). Overcoming slugging problems in a long-distance multiphase crude pipeline. In: Proceedings of the Society of Petroleum engineers (SPE) Annual technical Conference, 3–6 October, Houston, Texas.

Barbuto FA. (1995). Method and apparatus for eliminating severe slug in multi-phase flow subsea lines. United States, Patent No. 5478504.

Fabre J, Peresson L, Corteville J, Odello R and Bourgeois T. 1990. Severe Slugging in Pipeline/Riser Systems. SPE Production Engineering 5: 29–-305.

Jansen FE, Shoham O and Taitel Y. (1996). The elimination of severe slugging- experiments and modelling. International Journal of Multiphase Flow 22: 1055– 1072.

Jones R, Cao Y, Beg N and Wordsworth C. (2014). The Severe Slugging Mitigation Capability of a Compact Cyclonic gas/liquid separator. In: Proccedings of the BHR 9th North American Conference on Multiphase Technology, 11–13 June, Banff, Canada.

Luo X, He L and Ma H. (2011). Flow pattern and pressure fluctuation of severe slugging in pipeline-riser system.

Chinese Journal of Chemical Engineering 19: 26–32.

Malekzadeh R, Mudde RF and Henkes RA. (2012). Dualfrequency severe slugging in horizontal pipeline-riser systems. Journal of Fluids Engineering 134: 121 301–121 301.

Ogazi I. (2011). Multiphase severe slug flow control. Doctoral thesis, Cranfield University. Available at: https://

dspace.lib.cranfield.ac.uk/bitstream/1826/8345/1/ Anayo_Ogazi_Thesis_2 011.pdf <Last accessed 18 August 2017>.

Ogazi IA, Cao Y, Lao L and Yeung H. (2011). Production potential of severe slugging control systems. IFAC Proceedings Volumes 44: 10 869–10 874.

Oseyande OP. (2010). Feasibility Study on Hydrodynamic Slug Control. Masters thesis, Cranfield University.

Sagatun SI. (2004). Riser slugging: a mathematical model and the practical consequences. SPE Production and Facilities 19: 172–173.

Sarica C and Tengesdal J. (2000). A new technique to eliminate severe slugging in pipeline/riser systems. In: proceedings of the SPE Annual Technical Conference, 1–4 October, Texas, USA. Schmidt Z, Brill JP and Beggs HD. (1979). Choking can eliminate severe pipeline slugging. Oil and Gas Journal 12: 230–238.

Shotbolt K. (1986). Methods for the alleviation of slug flow problems and their influence on field development planning. In: proceedings of the SPE European Petroleum Conference, 20–22 October, London, UK. Statoil ASA, 2007. Flow Assurance: Slug Control. Available at: http://www.statoil.com/en/TechnologyInnovation/Field Development/FlowAssuance/SlugControl/Pages/ default.aspx.

Tang Y and Danielson TJ. (2006). Pipelines slugging and mitigation: case study for stability and production optimization. In: Proceedings of the SPE Annual Technical Conference, 24–27 September, San-Antonio, Texas.

Tengesdal JO. (2002). Investigation of self-lifting concept for severe slugging elimination in deep-water pipeline/riser systems.

PA: Pennsylvania State University, 274 pp.

Yocum BT. (1973). Offshore riser slug flow avoidance: mathematical models for design and optimization. In: Proceedings of the SPE European Meeting, 2–3 April, London, UK.

Appendix A: Mathematical conversion of volumetric flowrates to mass flowrates Barrels of oil per day (BOPD)

1 BOPD =

0.159m3/d, or 1.8402778e-006 m3/s

Million standard cubic feet per day (MMScf/d)

1 MMScf/d =

28,316.85 m3/d, or 0.32774132 m3/s

Stock tank barrels per day (STB/d)

1 STB/d =

0.119 m3/d, or 1.3773148e-006 m3/s (density of water is taken at 60 °F)

Well 1 Volumetric flowrates: • Oil, Qo: 6722 BoPD • Gas, Qgas: 4 MMScf/d • Water, Qwater: 0 STB/d Qo = 6722 BoPD = 1.2370347e-002 m3/s m˙o = 7.9293927 kg/s

Qgas = 4 MMScf/d = 1.31096528 m3/s @ STP: 101.325 kPa, 60 °F At operating pressure, using ideal gas law: Qgas: 1.310965*101.325*355.37222*1 288.706*11569.404*1 = 0.01413268 m3/s m˙gas = 0.25721475 kg/s Qwater = 0, m˙ m˙ water = 0

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Well 2

At operating pressure, using ideal gas law:

Volumetric flowrates: • Oil, Qo: 22157 BoPD • Gas, Qgas: 23 MMScf/d • Water, Qwater: 6 STB/d Qo = 22157 BoPD = 4.0775035e-002 m3/s m˙o = 26.1367975726 kg/s Qgas = 23 MMScf/d = 7.53805036 m3/s @ STP: 101.325 kPa, 60 °F

Qgas: =

7.538055036*101.325*348.70556*1 288.706*8963.1853*1

= 0.1029239238 m3/s m˙gas = 1.873215413 kg/s Qwater = 6 STB/d = 8.2638888e-006 m3/s m˙water = 8.2482089e-003 kg/s

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CALL FOR PAPERS Underwater Technology: InternaƟonal Journal of the Society for Underwater Technology The Society for Underwater Technology is calling for papers for its internaƟonal journal, Underwater Technology. The journal publishes peer-reviewed technical papers on all aspects and applicaƟons of underwater technology, including: • • • • • • • • • • • • •

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doi:10.3723/ut.34.171 Underwater Technology, Vol. 34, No. 4, pp. 171–178, 2017

Technical Briefing

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Development of data layers to show the fishing intensity associated with individual pipeline sections as an aid for decommissioning decision-making Sally Rouse1,2,*, Andronikos Kafas2, Peter Hayes2 and Thomas A Wilding1 1 SAMS, Scottish Marine Institute, Oban, Argyll, PA37 1QA, UK 2 Marine Scotland Science, 375 Victoria Road, Aberdeen, AB11 9DB, UK Received 31 July 2017; Accepted 18 September 2017

Abstract Numerous pipelines have been installed in the North Sea to support offshore oil and gas extraction. Pipeline decommissioning options include full and partial removal, as well as in situ decommissioning, either with or without intervention.

The choice of decommissioning strategy has social, economic and safety implications for commercial fisheries, according to the type and intensity of fishing in the vicinity.

Assessing the impacts of decommissioning strategies on fisheries and mitigation options is an essential step in the decommissioning consenting process. It is important that fisheries impact assessments employ the best available data that are capable of resolving the fine-scale spatial patterns that are known to exist in pipeline-fishing overlaps.

This paper describes the development of geographic information system (GIS) layers that provide high-resolution fishing intensity data for individual pipeline sections. The layers were created using fishing data extracted from the vessel monitoring system (VMS) for UK vessels operating mobile demersal gear between 2007 and 2015. The layers are freely available to download via the Scottish Government’s National Marine Plan Interactive (NMPi). The layers provide a common evidence base for industry, regulators and stakeholders to assess the impacts of different decommissioning options to commercial fisheries during the decommissioning process.

Keywords: pipelines, decommissioning, fisheries, VMS, vessel monitoring system

1. Introduction The wide-scale deployment of pipelines in the north east Atlantic has facilitated the exploitation of offshore oil and gas reserves since the 1960s.

There are ~2500 pipelines in the North Sea, with a

* Contact author. Email address: sally.rouse@sams.ac.uk

combined length of ~44 000 km (Oil and Gas UK, 2013). Pipelines range in diameter from 2" to 42" (ca. 5 cm to 107 cm internal diameter) and are categorised as ‘surface-laid’, resting on top of the substratum, or trenched, laid within a subsurface channel that is either back-filled – naturally or artificially – or left open (Oil and Gas UK, 2013). Pipelines are generally constructed from steel, but may have concrete or polymer external coatings (Oil and Gas UK, 2013).

To date, less than 2 % of UK pipelines have been decommissioned (Oil and Gas UK, 2013), but ~7500 km of pipelines are scheduled for decommissioning by 2026 (Oil and Gas UK, 2016). Unlike oil and gas platforms (OSPAR, 1998), there are no international regulations dictating pipeline decommissioning, and individual governments are able to set their own national policies. Options for pipeline decommissioning include full and partial removal, and leaving pipelines in situ, either with or without intervention (e.g. the addition of protective material such as rock placement) (Oil and Gas UK, 2013). The choice of pipeline decommissioning strategy has implications for the environment and other marine industries, including commercial fishing (Love and York, 2005; McLean et al., 2017; Rouse et al., in press).

Commercial fisheries are one of the largest users of the North Sea in terms of spatial footprint and are considered to be major stakeholders in decommissioning decisions (Eastwood et al., 2007; Jentoft and Knol, 2014). Outside the 500 m exclusion zones around platforms, there are no restrictions on fishing in the vicinity of pipelines. Substantial overlaps exist between fishing activity and pipelines in certain regions, including the northern North Sea and east of Shetland, and a number of vessels 171

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appear to actively target pipelines when fishing (Rouse et al., in press). Under UK regulations, operators must evaluate pipeline decommissioning options in terms of cost, safety, technical feasibility, the environmental consequences and the societal impacts through a comparative assessment process (Department of Energy and Climate Change (DECC), 2011). The comparative assessment is reviewed by government advisors and statutory consultees, who provide feedback and advice to the regulator. The societal impacts that must be considered in the comparative assessment include the consequences of decommissioning to commercial fishers. These include potential snagging hazards from in situ decommissioned pipelines, and loss of access either during the decommissioning process and/or as a result of disused pipelines left on the seabed (de Groot, 1982; Jiexin et al., 2013).

Snagging can potentially result in damage to gear, loss of fishing time and/or risk of injuries to crew.

Additionally, physical contact between fishing gear and decommissioned pipelines can be a risk to pipeline integrity and, over time, increase the snagging hazard posed by the pipeline (Ellinas et al., 1995; Det Norske Veritas (DNV), 2006). Repeated trawling activity may also disturb any protective material (such as rock placement) which has been added to in situ decommissioned pipelines to mitigate snagging risks.

The implications of any particular decommissioning method to commercial fishing operations will depend on both the type and intensity of fishing in the vicinity. Currently, the majority of operators (and their consultants) use fishing intensity data that are reported at the scale of the International Council for Exploration of the Sea (ICES) statistical rectangles (1° latitude by 1° longitude) as the basis of decommissioning impact assessments (see Canadian Natural Resources International (2017) as an example of the use of ICES-scale data†1). Integration of effort across ICES rectangles prevents the identification of fine-scale spatial fisheries patterns, and interactions between vessels and individual pipeline sections in particular will not be detectable (Mills et al., 2007; Lee et al., 2010; Rouse et al., in press).

Since 2005, all vessels ≥15 m registered in the European Union (EU) have been required to submit their location, heading and speed to the relevant EU competent authority through a vessel monitoring system (VMS) (European Commission (EC), 2002).

In 2012, the size of vessels required to fit VMS was reduced to 12 m. Data must be submitted at regular † Canadian Natural Resources also presented a map of VMS records in the northern North Sea, obtained from the Marine Management Organisation, to complement ICES-scale fishing intensity data.

intervals, and a minimum of every 2 hours (EC, 2002). Data extracted from the VMS can be analysed to provide higher resolution representations of fishing intensity (Mills et al., 2007; Vermard et al., 2010).

These data offer significant potential for aiding decommissioning decisions by providing a more accurate representation of spatial overlaps between fishing and specific pipelines or pipeline sections (Rouse et al., in press). VMS data also offer a common evidence base that is available across the entire North Sea region and can be shared between operators, regulators and stakeholders for assessing fisheries-pipeline interactions. This can facilitate timely, consistent and transparent decision-making, as advocated under the Marine Strategy Framework Directive (Flannery and Ó Cinnéide, 2012).

This paper provides details on the development and publication of spatial data layers using VMS data from the UK commercial fishing fleet to show the fishing intensity along the length of North Sea oil and gas pipelines. These data layers represent an alternative source of fishing intensity data that can be used in the evaluation of societal impacts in the comparative assessment framework for decommissioning.

2. Development of geographic information system layers 2.1. Data sources VMS data were obtained from the Scottish Government’s Fisheries Information Network database for all UK commercial fishing vessels that operate dredges, Nephrops trawls (otter and pair trawls) and demersal trawls (otter, beam and pair trawls) over the period 2007–2015. VMS records were only included from vessels greater than 15 m in length, with no data from vessels between 12 m and 15 m (for detailed descriptions of fishing gear types, see Montgomerie, 2015). For each VMS record (reported approximately every 2 hours), the following attributes were available: latitude, longitude, date, time, speed, heading and vessel size.

The VMS data were linked to vessel logbooks to obtain gear type information. The location and properties of pipelines in the North Sea were obtained from Oil and Gas UK (Common Access Data (CDA), 2013) and the Norwegian Petroleum Directorate (2016). The pipeline dataset consisted of trunklines (large pipelines transporting oil or gas), flexible and rigid flowlines (transporting oil or gas) and umbilicals (transporting chemicals or hydraulic fluids), as well as cables, mooring lines and anchor chains. Data included the operator, diameter and fluid medium inside each pipeline.

Data on whether pipelines were surface-laid or trenched were not available.

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2.2. Data processing A unique fishing trip ID was assigned to all VMS records between a vessel leaving and returning to port.

For each VMS record, a derived speed was calculated from the distance and time interval between successive records according to fishing trip. The derived speed serves as a second measure of vessel speed, in addition to ‘instantaneous’ speed recorded as metadata for each VMS point, and can be used for quality control purposes. VMS records with any of the following attributes were removed: a latitude or longitude outside the range of possible values, a vessel heading outside the range of possible values or a derived speed of >20 knots (Hintzen et al., 2010).

Records within 5 km of a port were also removed to avoid misidentification of fishing activity when a vessel’s speed fell below designated thresholds (see Table 1) around ports (Hintzen et al., 2010).

Individual VMS points were categorised as ‘fishing’ or ‘non-fishing’ (i.e. steaming) using the activity Tacsat function in the R package VMSTools (Hintzen et al., 2012). This function applies a segmented regression to the cumulative frequency distribution of speed profiles for each vessel according to gear type. It returns gearspecific thresholds for delimiting the two peaks (a lowspeed peak representing fishing, and a higher speed peak representing steaming), which are typical of mobile demersal gear speed profiles (Bastardie et al., 2010; Hintzen et al., 2012; Natale et al., 2015). The thresholds (Table 1) are then used to label each VMS ping as fishing or steaming according to its associated speed. ‘Fishing’ periods represent occurrences when fishing gear is deployed and expected to come into contact with the seabed, potentially interacting with pipelines. Steaming points were removed from the data. The remaining VMS fishing points were interpolated into fishing tracks to obtain a greater spatial resolution of fishing activity (Lambert et al., 2012; see Fig 1). The interpolation followed the method of Hintzen et al.

(2010) using a cubic Hermite spline, which accounts for the heading and speed of the vessel.

Each pipeline was divided into 1 km sections.

The section length was chosen based on the median Table 1: Speed thresholds used to categorise VMS point data as actively fishing or steaming according to gear type.

The minimum and maximum speed thresholds that have been used to distinguish between fishing and non-fishing VMS points are shown (see Lee et al., 2010) Gear type

Speed threshold for fishing (knots)

Minimum speed (knots)

Maximum speed (knots)

Dredging Otter trawls (including pair) Beam trawls

0.0 to 3.0 ≥1.0, ≥4.0

0 0

6.0 6.0

≥1.0, >8.5

0

8.0

error between interpolated tracks (~500 m for VMS reported at a 2 hour interval for UK trawlers and dredgers) and the true fishing path (Billet, 2016), and previous analysis of VMS data around a Dutch pipeline (Hintzen, 2016). The fishing intensity associated with each 1 km section was calculated as the total number of tracks intersecting the area extending 500 m either side of the pipeline (i.e. in a 1 km by 1 km square containing a pipeline section at the centre). Tracks within the 1 km2 were included irrespective of whether the track intersected with the pipeline, based on the assumption that gear may still interact with a pipeline without the vessel crossing over the pipeline. The intensity was calculated for each year and according to four gear categories: (1) dredging; (2) Nephrops trawls (pair and otter trawls); (3) demersal trawls (otter, pair and beam trawls); and (4) all mobile demersal boats (dredging, Nephrops and demersal amalgamated).

The number of fishing tracks for each gear category was joined to the pipeline section attributes to create four GIS layers (one for each gear category). The resulting layers, showing pipelines across the whole North Sea, are available to view via the Scottish Government’s National Marine Plan interactive2‡ (NMPi) and can be downloaded from Scottish Spatial Data Infrastructure MetaData portal§3.

The development stages for the GIS layers are summarised in Fig 1, with a sample from one of the final output layers shown in Fig 1d.

3. Applications for layers The GIS layers showing the intensity of fishing associated with individual pipeline sections have multiple applications for pipeline decommissioning and management. They provide an evidence base for: (1) policy decisions and regulatory guidelines; (2) planning and executing pipeline decommissioning; and (3) optimising oil and gas operations prior to decommissioning. The layers are of particular value for evaluating impacts of different decommissioning options with respect to commercial fisheries (and according to different fishing sectors) during the comparative assessment process. For example, the impacts of decommissioning pipelines in situ on commercial fisheries would be lower for sections identified as having little or no interaction over the last nine years. In these instances, other considerations, such as environmental interactions, could be weighted higher in the comparative assessment processes. Conversely, for the pipeline sections that have a consistently high number of fishing ‡ www.gov.scot/marinescotland/viewpipelines § www.gov.scot/marinescotland/downloadpipelines

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Fig 1: Development stages for high-resolution GIS layers showing fishing intensity associated with pipeline sections in the North Sea. VMS data for all UK vessels were formatted (A), and filtered to remove non-fishing points (B). Fishing points were interpolated into tracks (C). Pipelines (solid lines D) were divided into 1 km sections and overlaid with fishing tracks (E) to provide the fishing intensity associated with pipeline sections – darker sections have a higher fishing intensity (F). Data shown are from 2015 and represent all mobile demersal gear

tracks associated with them, it is important that decommissioning strategies are selected to account for future fisheries interactions and any snagging risks posed by material left on the seabed, in consultation with representatives from the fishing industry.

The pipeline-specific fishing intensity data may also be used to specify the monitoring programme for pipeline integrity and span development, which must be initiated following in situ decommissioning (Oil and Gas UK, 2013). Pipelines sections with little or no fishing activity are likely to maintain their integrity for longer and, as such, could be subjected to a less frequent monitoring regime than those sections of pipelines that are regularly fished over. The adoption of such a risk-based approach to monitoring, informed by the fishing intensity data, could represent a significant cost-saving to the industry and regulators.

By making the layers publically available and accessible to all stakeholders concerned with pipeline decommissioning and management, the transparency

of decision-making can be improved. The explicit linkage of fishing intensity data to specific pipelines within layers enables operators to efficiently extract information pertaining to their own assets using the standard BEIS (Department for Business, Energy and Industrial Strategy formerly Department of Trade and Industry (DTI)) identification nomenclature that is assigned to all UK North Sea pipelines. The higher spatial resolution of the data, compared to intensity data reported at the scale of ICES statistical rectangles, means that greater confidence can be given to the comparative assessment process and proposed mitigation for risks to fishers.

The layers provide an opportunity to gain novel insight into the temporal and spatial variation in interactions between commercial fishing and North Sea pipelines (Fig 2), and this could form the basis of future research. Additionally, the data could be used to understand the impacts of previous pipeline decommissioning decisions (if they are within the available timescale) on commercial fishing

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power cables. Furthermore, the interpolated VMS tracks could be summarised to provide fishing intensity data at a variety of scales (e.g. ICES statistical rectangles, oil and gas licence blocks, renewable licence areas) according to specific management requirements.

4. Recommended steps for using layers The following recommended steps are provided to guide users in the extraction of data from the layers.

Fig 2: The GIS layers can be queried using the ‘Time Aware’ function on NMPi to show variations in fishing intensity according to year, e.g. 2007 (A), 2011 (B) and 2015 (C), and at different locations. Darker pipeline sections have a higher number of associated fishing tracks

at local and regional scales. This would serve as a guide for future decommissioning decisions and would allow decision-makers to consider the precedents set by individual pipeline decommissioning cases, including the potential consequences of these decisions at the scale of the UK Continental Shelf. For such an assessment, it would be necessary to collate spatial data on previous pipeline decommissioning practices, which are currently disparate and not readily accessible.

The data layers could also be linked with other data relevant to decommissioning decisions, such as predicted or known associations between pipeline sections and marine species, and in particular species of conservation concern, according to physical environmental drivers (e.g. depth or substratum type). This would further improve the efficiency of decommissioning decisions, by providing a single data source for use in the comparative assessment process to evaluate the impacts of decommissioning to the environment and fishing industry.

The methods used in this study are readily applicable to other marine spatial planning considerations beyond pipeline decommissioning, including the planning, installation and decommissioning of offshore renewable infrastructure and

1. Users should download the data to a desktop GIS application via the Scottish Spatial Data Infrastructure MetaData portal. The data are delivered in two formats: an ESRI ArcGIS layer package (which has pre-formatted symbology incorporated) and a standard shapefile (with no symbology information provided). The data consist of a single layer containing 43 770 polygons (each 1 km2) covering UK and Norwegian pipelines. The geographic coordinate system of the layer is WGS84. The attribute table of the layer contains a pipeline identifier field called ‘PL_No’, a pipeline table field called ‘Operator’ (representing the operator in May 2016) and 40 fields relating to the number of fishing tracks in each polygon according to year and gear type.

The ‘AllGear’ field shows the total number of fishing tracks per polygon over the nine-year period. The ‘AllDredge’, ‘AllNep’ and ‘AllDem’ fields show the total number of fishing tracks over the nine-year period for vessels operating dredges, Nephrops trawls and demersal trawls respectively. The number of tracks for each year is given in the remaining fields for each gear category with field names showing ‘AllGear’, ‘Dredge’, ‘Nep’ or ‘Dem’ to represent gear type (all gear types, dredging, Nephrops trawling and demersal trawling, respectively) and a two-digit year code representing the years between 2007 and 2015. A summary of the attribute table fields is shown in Table 2.

2. After adding the layer to a map, users should select their area of interest either by zooming to the area or building an SQL expression with known BEIS pipeline identification codes contained in the ‘PL_No’ field.

3. If the ESRI ArcGIS layer package is used, the polygons associated with each 1 km pipeline section will be colour-coded to show the total number of tracks for all years and all gear types. Polygons shown in yellow have the fewest number of tracks associated with them, while red polygons have a higher number of tracks. The symbology will need to be set manually by the user if the shapefile data format is used. Initial inspection of the

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Table 2: Summary of layer attribute table fields Field Name

Type

Description

PIPE_DT OPERATO All_Gear

Text Text Integer

All_Dem

Integer

All_Dredge

Integer

All_Nep

Integer

Dem_07… Dem_15

Integer

Dredge_07… Dredge_15

Integer

Nep_07… Nep_15

Integer

Department for trade and industry pipeline identification code Pipeline operator as of May 2016. One of fifty operators.

Total number of VMS tracks per 1 km2 from vessel operating all gear types between 2007 and 2015 Total number of VMS tracks from vessels operating demersal gear per 1 km2 between 2007 and 2015 Total number of VMS tracks for vessels operating dredges per 1 km2 between 2007 and 2015 Total number of VMS tracks for vessels operating Nephrops gear per 1 km2 between 2007 and 2015 Total number of VMS tracks for vessels operating demersal gear per 1 km2 according to year (2007 to 2015) Total number of VMS tracks for vessels operating dredges per 1 km2 according to year (2007 to 2015) Total number of VMS tracks for vessels operating Nephrops gear per 1 km2 according to year (2007 to 2015)

data should be done using the ‘AllGears’ field to identify pipelines sections that are associated with commercial fishing activity. The symbology of the layer can then be manipulated using the remaining fishing fields to identify the type of fishing in the area and any temporal variability in fisheries interactions with the pipeline.

4. The number of fishing tracks associated with pipeline sections of interest can be compared to the fishing patterns for other pipelines in the region (e.g. northern North Sea) to provide context to the data, and determine whether the interactions at the pipeline sections of interest may be considered as high or low relative to regional patterns. This can form the basis of permit/licence applications.

5. It is important to note that the number of fishing tracks that may be considered ‘high’ or as representing a ‘significant interaction’ will depend on numerous factors, including pipeline type, gear type substratum type and burial/exposure status of the pipeline. The fishing intensity data should therefore be considered in consultation with technical experts and pipeline engineers on a case-by-case basis to understand risks to pipeline integrity and rock placement stability from fishing. This is consistent with current practices using lower resolution fishing intensity data.

5. Limitations of data The risks to pipeline integrity and fishing vessel access and safety (in terms of snagging hazards) occur where pipelines are exposed (permanently or temporarily) on the seabed. Since pipeline burial/ exposure data were not available in this study, the current layers are limited in their application to

regional assessments of overall fisheries-pipeline interactions. At the time of decommissioning, individual operators will have access to pipeline exposure data, either from historical records or a pre-decommissioning survey, which can be combined with the developed layers to understand existing and future risks of fisheries interactions.

There are a number of limitations associated with VMS data that must be considered in relation to the pipeline intensity GIS layers. Primarily, the method used to differentiate between fishing and non-fishing VMS records relies on speed as a proxy, yet there are several circumstances – including weather, vessel turning, hauling of gear, and travelling near hazards/port – when the speed of the vessel may fall below the designated speed thresholds.

A fishing vessel’s speed may also fall below the threshold when conducting ‘guard ship’ duties around oil and gas infrastructure. Guard ships are fishing vessels contracted by operators to patrol infrastructure during periods of installation or construction to prevent interaction with fishing vessels or other marine traffic. This patrolling occurs at slow speeds, and guard vessels maintain VMS transmissions during their duties. Guard ship duties do occur along exposed cables and pipelines, however, the overall contribution to VMS is considered to be minor, with ~14 vessels conducting guard ship duties on any given day (Scottish Fishermen’s Federation, pers. comm.).

The inclusion of VMS records from periods when vessels are operating at low speed, but not fishing, means that for a small minority of trips the total fishing effort may have been overestimated. Despite this overestimate, it can be assumed that the intensity data associated with pipeline sections represent an overall underestimate of the total fisheries interaction.

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This is because non-UK vessels were not included in the analysis, even though it is likely that a large number also interact with North Sea pipelines while fishing. Access to European-wide VMS data, including logbooks or other gear type information, would be required to provide the overall fishing intensity associated with pipeline sections.

VMS data for EU vessels could be obtained through the Scottish Government’s Fisheries Information Network, but the data only included points when vessels were present within the UK Continental Shelf. This geographical cut-off, along with missing information on vessel heading, meant that the EU VMS data could not be interpolated into fishing tracks using the methods applied to UK data.

Furthermore, without access to EU vessel logbooks, gear type could not be assigned to VMS records.

Other European VMS, e.g. from Norwegian and Icelandic vessels, could not be obtained through the Scottish Government. Similarly, UK vessels smaller than 15 m are not represented within the current data layers. Since smaller vessels tend to operate closer to shore, the level of fisheries-pipeline interaction will not be accurately represented in coastal areas. When decommissioning sections of pipelines close to shore, operators must consult fisheries representatives and other data sources on inshore fisheries data, such as ScotMap (Kafas et al., 2017).

The inherent error in track interpolation means that it may not represent the true fishing track and this must also be considered when using the data layers. Access to high-resolution plotter data would enable more accurate descriptions of spatial patterns of fishing activities, and centralised initiatives, e.g. the UK Crown Estate Fisherman’s mapping project (Crown Estate, 2010), are currently underway to facilitate access to these datasets. Once such data are available, the resolution of fishing intensity data associated with pipelines could be improved even further.

Acknowledgments The authors would like to thank Liam Mason and Martyn Cox at Marine Scotland for their support and assistance in publishing the data layers on NMPi. This work was supported by the Natural Environment Research Council [grant number NE/N019369/1].

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Rouse S, Kafas A, Catarino R and Hayes P. (in press). Commercial fisheries interactions with oil and gas pipelines in the North Sea: considerations for decommissioning.

ICES JMS. Will be available at: https://doi.org/10.1093/ icesjms/fsx121.

Vermard Y, Rivot E, Mahevas S, Marchal P and Gascuel D. (2010). Identifying fishing trip behaviour and estimating fishing effort from VMS data using Bayesian Hidden Markov Models. Ecological Modelling 221: 1757–1769.

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Popularizing Science: The Life and Work of JBS Haldane

By Krishna Dronamraju Published by Oxford University Press

Hardcover edition, 2017 ISBN 978-0-19-933392-9 367 pages John Burdon Sanderson Haldane (1892–1964) is regarded widely as one of the most influential British scientists of the twentieth century.

A true polymath, Haldane made significant contributions to a number of science disciplines including genetics, physiology, biochemistry, biometry and cosmology. Of most interest to the members of the SUT are his works on diving physiology and his relationship with his father, John Scott Haldane, who generated the first ever set of diving decompression tables in 1908.

According to this new biography of him, JBS – or Jack as he was known to his family – accompanied his father during the diving trials that evaluated the new tables. He apparently undertook some of the dives himself but, because he was younger than 16 at the time, his name was excluded from the final report.

His next involvement with underwater physiology was as an investigator of the sinking of the submarine HMS Thetis during trials shortly before the outbreak of World War II. The investigation triggered a series of wartime experiments for the British

Navy on the effects of breathing different gas mixtures under pressure. Haldane carried out many of the experiments on himself along with a number of his friends and colleagues, and most of the diving physiology included in this book is covered by a chapter entitled, ‘On Being a Guinea Pig’.

Considering how influential some of these works are to modern diving, the level of detail afforded to this aspect of Haldane’s career is disappointing. Dronamraju can be forgiven, considering the scale and diversity of Haldane’s overall research portfolio, but there is little mention of contributions to the future use of helium in breathing mixtures for deep diving. His seminal work on oxygen toxicity, under the direction of surgeon LieutenantCommander Donald, gets little more than a page of text, most of which is a reprinted letter on the subject from Haldane to Albert Behnke of the US Navy. For this reason, it is hard to recommend this book purely on the amount of diving physiology included.

However, that misses the fact that Haldane was a great scientist and theorist who did much to popularise scientific discovery. This book covers all areas of his research and is an interesting read for anyone engaged in science, not least that it is difficult to comprehend how someone like Haldane could have been accommodated under the current restrictive funding limitations of the UK research councils, especially when he had no formal academic qualifications in science.

The book is divided into five parts, which roughly follow Haldane’s life through five decades from the 1920s to the

www.sut.org

Book Review...

doi:10.3723/ut.34.179 Underwater Technology, Vol. 34, No. 4, pp. 179–180, 2017

1960s. In the first part, there is a brief introduction to his family background and early life, followed by a chapter relating the controversy surrounding his first marriage. Subsequent chapters are arranged around his wide range of research interests including: eugenics, population genetics, evolutionary biology and the origin of life. The second part of the book continues to recount his research into human genetics, but also explains his conversion to socialism and Marxism.

Part three contains chapters relating to his second marriage, and also how he became disillusioned with the post-war Soviet Union following its suppression of the science of genetics. This part also contains a chapter on how Haldane popularised science through a series of essays published by various newspapers and magazines, and how some of his writings may have influenced other authors such as Arthur C Clark and Aldous Huxley. Part four lists his relations with many other scientists, and then recounts how the Haldanes’ move to India was influenced largely by their dislike of British actions during the Suez Crisis. The final part of the book recounts Haldane’s time in India and his eventual death.

This part also contains chapters that provide summaries and introspective accounts of life with Haldane, Haldane and religion, and the impact of Haldane today.

The author of this biography, Krishna Dronamraju, was one of Haldane’s last students and had spent a lot of time working and living with him. The biography is mainly written chronologically, but also concentrates on some of the highlights and controversies of Haldane’s life. The

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Dronamraju. Popularizing Science: The Life and Work of JBS Haldane

author’s close association with Haldane means that there are numerous interesting references to personal conversations between the two. However, it may be because the author’s own research interests are in genetics that Haldane’s studies of genetics appear to dominate the biography.

The account is generally well written, and the thoughtprovoking subject material means that many sections of the book are easy to read. There are some chapters where the format becomes a bit mechanical, and there is a recurring tendency to repeat even quite basic factual

information frequently throughout the book. But these irritations do not detract from the overall enjoyment of learning more about such an exceptional life.

(Reviewed by Dr Martin Sayer, UK National Facility for Scientific Diving)

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SUT Publications The SUT publishes a peer-reviewed technical journal Underwater Technology; a quarterly magazine UT2 and e–magazine UT3; a series of conference proceedings Advances in Underwater Technology, Ocean Science and Offshore Engineering and The Operation of Autonomous Underwater Vehicles; and in–house conference proceedings and collected papers from seminars.

All SUT books and conference proceedings are available to purchase from the SUT website www.sut.org/publications/books-and-conference-proceedings/ This is a selection of the larger collection of the Society’s books and conference proceedings available to purchase online.

Can a Lobster be an Archaeologist?

Quirky Questions and Fascinating Facts about the Underwater World From exploring lost treasure to sea monsters, ocean rubbish and how to build your own ROV, the book is packed with factual and fun illustrated stories.

Offshore Site Investigation and Geotechnics: Integrated Geotechnologies – Present and Future Proceedings of the international conference held in September 2012

Price: £220

Price: £12.99

Order Ref. C42

ISBN 978 0 906940 55 6

Hardback; 2012

Paperback; 2015

674 Pages

ISBN 978 0906940532

152 Pages

Subsea Control and Data Acquisition 2010: Future Technology, Availability and Through Life Changes Guidance Notes for the Planning and Execution of Geophysical and Geotechnical Ground Investigations for Offshore Renewable Energy Developments

Price: £15 ISBN 978 0 906940 54 9 Paperback; 2014

Proceedings of the international conference held in Newcastle, UK, 2-3 June 2010 Proceedings of the International Conference

Price: £95

2–3 June 2010 Newcastle, UK

Order Ref. C41

SUBSEA CONTROL AND DATA ACQUISITION 2010

ISBN 978 0906940525

Future Technology, Availability and Through Life Challenges

Hardback, 2010 176 Pages

48 Pages

The Operation of Autonomous Underwater Vehicles, Volume One: Recommended Code of Practice for the Operation of Autonomous Marine Vehicles, Second Edition

Price: £75 Order Ref. C40 ISBN 978 0906940518 Paperback, 2009 78 Pages

The Collaborative Autosub Science in Extreme Environments: Workshop on AUV Science in Extreme Environments Proceedings for the international science workshop held at the Scott Polar Research Institute, University of Cambridge, 11-13 April 2007

Price: £95 Order Ref. C39 ISBN 978 0906940501 Hardback, 2008 202 Pages

For orders and enquiries, please contact: Cheryl Ince, Society for Underwater Technology, Unit LG7, 1 Quality Court, London WC2A 1HR t +44 (0)20 3440 5535 e cheryl.ince@sut.org

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Society for Underwater Technology

Educational Support Fund Sponsorship for Gifted Students in Marine Science, Technology and Engineering to meet industry’s critical shortage of suitably qualified entrants.

SUT sponsors UK and overseas students (studying in the UK and abroad) at undergraduate and MSc level who have an interest in marine science, technology and engineering.

Students are supported who are studying subjects such as:

Offshore and Ocean Technology Subsea Engineering Oceanography Marine Biology Ship Science and Naval Architecture Meteorology and Oceanography The SUT annual awards are £2,000 per annum for an undergraduate, and £4,000 for a one-year postgraduate course. (Part-time postgraduate studies funding available.)

As one of the largest non-governmental sources of sponsorship, the SUT has donated grants totaling almost half a million pounds to over 270 students since the launch of the fund in 1990.

For further information please contact Society for Underwater Technology, Unit LG7, 1 Quality Court, London WC2A 1HR UK t +44 (0)20 3440 5535 e info@sut.org or please visit our website

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Society for Underwater Technology International multidisciplinary learned society This non-aligned membership-based organisation seeks to further the dissemination of knowledge and lessons learned in the underwater environment through networking, events and publications

Its membership covers the following activity areas:

diving and manned submersibles environmental forces marine policy marine renewable energies ocean resources offshore site investigation and geotechnics salvage and decommissioning subsea engineering and operations

For further information For membership, publications or general enquires, contact SUT Head Office Unit LG7, 1 Quality Court, London WC2A 1HR t +44 (0)20 3440 5535 e info@sut.org For events, contact SUT Aberdeen Office Enerprise Centre Exploration Drive Bridge of Don Aberdeen AB23 8GX UK t +44 (0)1224 823 637 e events@sut.org

underwater robotics underwater science

www.sut.org

underwater vehicles

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Vol. 34 32 No. No. 432 2017 2014 Vol.

UNDERWATER TECHNOLOGY

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147 171 DISCOVER THE LATEST PRODUCTS AND SERVICES FROM THE FOLLOWING INDUSTRIES: A Personal View...

Downturns and the deep

Bil Loth

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Protection of submarine optical fibre cables on the coral reefs of the Maldives

Muneez M, Vinesh T and Nai-Shyan L UNDERWATER COMMUNICATIONS

HYDROGRAPHY

POSITIONING

MARINE

AND AND RENEWABLES Investigation of slug mitigation: GEOPHYSICS METROLOGY self-lifting approach in a deepwater oil field

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Adefemi IO, Kara F and Okereke NU

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In partnership with:

Technical Briefing Development of data layers to show the fishing intensity associated with individual pipeline sections as an aid for decommissioning decision-making

Sally Rouse, Andronikos Kafas, Peter Hayes and Thomas AOIL Wilding OCEAN & GAS MARITIME AQUACULTURE RESEARCH

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SECURITY

Book Review Popularizing Science: The Life and Work of JBS Haldane

ISSN 1756 0543

UNMANNED VEHICLES AND VESSELS SHOWCASE

MONITORING STRUCTURAL INTEGRITY

HANDLING BIG DATA

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