• Author / Uploaded
• Alberto Mora Perea

Citation preview

May 2020

World Trends and Technology for Offshore Oil and Gas

CRISIS MANAGEMENT • FPU construction update • Platform of the future • France supplement

2005OFFC1-C5.indd 1

4/29/20 11:50 AM

Achieve reliability offshore. Shallow and deepwater assets require a technology provider that enhances safety, reduces rig time and sustains high-margin production.

© 2020 Weatherford. All rights reserved.

Ready? We are.

2005OFF_Weatherford 2005OFFC1-C5.indd 2 1

weatherford.com/offshore

4/6/20 11:50 4:58 PM 4/29/20 AM

CONTENTS •

International Edition Volume 80, Number 5

Celebrating 65 Years of Trends, Tools, and Technology

16

• CRISIS MANAGEMENT

Industry responds to low oil prices, coronavirus pandemic������������������������������������������������������16 The offshore oil and gas industry began 2020 on a cautiously optimistic note. That optimism was quickly shattered with the onset of the novel coronavirus pandemic and the equally rapid collapse in crude oil prices. The lockdowns and quarantines that followed have taken a huge bite out of oil demand; this has further eroded oil prices. The result is an unprecedented level of uncertainty in the market. Pandemic, falling prices take steam out of floating production market�������������������������������������������������������������22 Prior to the COVID-19 pandemic and concurrent crash in oil prices, 2020 was on track to be a strong year for new project awards and ongoing construction in the floating production sector. Energy Maritime Associates anticipates that few new projects will be sanctioned this year, and that its previous five-year forecast for new orders should be reduced by approximately 20%. Embattled industry goes into crisis management mode������������������������������������������������������������26 The sudden drop in the oil price together with the coronavirus pandemic has thrown the global offshore EPC market into a state of flux. 2020 budget cuts so far have been around 25%. The offshore

sector will see a significant slowdown in planned investments. Discretionary E&A budgets have been slashed, rig contracts cancelled, and new project sanctioning is being reassessed.

• DRILLING & COMPLETION

Third-party verification plays key role in HP/HT technology adoption���������������������������������������������������������27 Since the consequences of failure in offshore HP/HT environments are potentially severe, regulators such as BSEE have added extra rigor in their permitting and approval process for such projects, requiring additional risk studies, design verification, and validation of equipment using an Independent Third Party (I3P) for verification and oversight.

• ENGINEERING, CONSTRUCTION, & INSTALLATION

FSRU enables cleaner energy production for El Salvador�������������������������������������������������������������������30 The 378-MW Energía del Pacífico project in El Salvador will not only introduce a new source of energy to the country, but it will also include the development of the first offshore regasification vessel deployed off the Pacific Coast of Central America – thus demonstrating the viability of floating LNG as an energy source for landbased power generation in the region.

Offshore® (ISSN 0030-0608, print; 2688-3295, digital/USPS 403-760) is published 10 times a year by Endeavor Business Media, LLC, 1233 Janesville Avenue, Fort Atkinson WI 53538. Periodicals postage paid at Fort Atkinson, WI 53538 and additional mailing offices. SUBSCRIPTION PRICES: US $127.00 per year, Canada/Mexico $165.00 per year, All other countries $208.00 per year (Airmail delivery $292.00). Worldwide digital subscriptions: $76.00 per year. POSTMASTER: Send address changes to Offshore® PO Box 3257, Northbrook IL 60065-3257. Offshore® is a registered trademark. Endeavor Business Media, LLC 2020. All rights reserved. Reproduction in whole or in part without permission is prohibited. We make portions of our subscriber list available to carefully screened companies that offer products and services that may be important for your work. If you do not want to receive those offers and/or information via direct mail, please let us know by contacting us at List Services Offshore®, 7666 East 61st Street, Ste. 230, Tulsa, OK  74133. Printed in the USA. GST No. 126813153. Publications Mail Agreement no. 40612608. MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM1

2005OFF01-03_toc.indd 1

4/28/20 11:38 AM

• CONTENTS Volume 80, Number 5

• EQUIPMENT & ENGINEERING

COVER: The offshore industry is in crisis management

Air filtration system helps improve gas turbine performance on BP’s Clair platform��������������������63

mode. The onset of the COVID-19 pandemic and the collapse in crude oil prices has forced the industry to slash capex, delay projects, and cancel and terminate contracts. Learn how the industry is dealing with these challenges starting on page 16. (Image courtesy Siemens)

Changing the fundamentals of subsea well completion�����������������66

Hybrid power plants can help decarbonize offshore drilling rigs and vessels��� 34 The marine and offshore oil and gas industries are coming under immense pressure to reduce emissions and improve the sustainability of their operations. Considering this, the application of low voltage direct current-based diesel-electric propulsion systems has gained significant traction. BOKA Vanguard delivers second box-shaped FPSO to Petrobras������������������ 37 Boskalis’ giant heavy transport vessel BOKA Vanguard has delivered a second box-shaped FPSO to Petrobras for a deepwater oilfield development in the Santos basin offshore Brazil. A dry-tow of the platform onboard the vessel cuts the journey time from the Far East by up to 60 days, Boskalis claims, compared to a conventional wet tow using tugs. This cuts the overall project costs and helps speed the schedule toward first oil.

• PRODUCTION OPERATIONS

Quantitative engineering analysis ensures assets remain safe, sustainable��� 41 Fitness for service provides a quantitative engineering evaluation to demonstrate the integrity of a component to continue to operate under a specific set of conditions, potentially in the presence of a defect or degradation mechanism. It translates inspection results into quantifiable operational and safety risks, enabling informed integrity management decisions.

Slim stop collar intended for closetolerance applications��������������������68

DEPARTMENTS Online������������������������������ 4 Comment������������������������� 5 Data���������������������������������� 6 Global E&P���������������������� 8 Offshore Europe����������� 10 Gulf of Mexico��������������� 11 Subsea Systems����������� 12 Vessels, Rigs, & Surface Systems����������� 13 Drilling & Production���� 14 Offshore Wind Energy�� 15 Business Briefs������������ 69 Advertisers’ Index��������� 71 Beyond the Horizon������ 72

Digital technologies leading industry toward autonomous operations��������� 46 Autonomous operations can help make systems safer, more capable and reliable, as well as more cost-effective. Removing people from the process reduces the scope for errors and improves safety. The journey toward autonomous operations is happening in the energy sector, predominantly now where digital technologies are being used to sense, measure, and control connected assets.

• FRANCE

Eiffage Métal expanding offshore wind construction capability���������52 GTT membranes safeguard LNG on Prelude, Coral South����������������������54 DORIS maintaining focus on renewables, lower-cost production���������������������������������������56 iXblue develops second Gaps USBL system for shallower-water subsea tasks������������������������������������������������������� 58 Re-purposing gas carriers for offshore re-gas, storage roles�������60 Les “Habitués” de OTC�������������������62

2

2005OFF01-03_toc.indd 2

51 WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

2004OF

showcase

2004OFF_Allseas 1 2005OFF01-03_toc.indd 3

3/17/20 4/28/20 11:20 11:38 AM AM

• ONLINE

VP AND GROUP PUBLISHING DIRECTOR Paul Westervelt [email protected] CHIEF EDITOR/ CONFERENCES EDITORIAL DIRECTOR David Paganie [email protected] MANAGING EDITOR Bruce A. Beaubouef [email protected] EDITOR-EUROPE Jeremy Beckman [email protected] ASSISTANT EDITOR Jessica Stump [email protected]

LATEST NEWS AVAILABLE AT OFFSHORE-MAG.COM The latest news is posted daily for the offshore oil and gas industry covering technology, companies, personnel moves, and products. CORONAVIRUS PANDEMIC COVERAGE

COVID-19 Impact on the Oil & Gas Industry Volatility has always been a challenging element of the oil and gas market but has rarely been more extreme than it is today. COVID-19-led disruptions to demand, combined with its dramatic impact on financial markets, have led to rapid price swings. Oil & Gas Journal and Offshore magazine editors discuss how COVID-19 has impacted our industry. https://www.offshore-mag.com/home/webinar/14174206/covid19-impact-on-the-oil-gasindustry

Latest news on Coronavirus Offshore magazine is committed to help you navigate this new period of uncertainty, with a dedicated web page with daily news and analysis on the impact of the coronavirus (COVID-19) pandemic. https://www.offshore-mag.com/business-briefs/coronavirus

NEW WHITE PAPERS

The Challenges of Maintaining Equipment on Offshore Platforms

https://www.offshore-mag.com/white-papers/whitepaper/16805384/sulzer-the-challengesof-maintaining-equipment-on-offshore-platforms

Top 10 Safety Tips For Summer FR Compliance

POSTER EDITOR E. Kurt Albaugh, P.E. [email protected] EDITORIAL CREATIVE DIRECTOR Jason Blair PRODUCTION MANAGER Shirley Gamboa [email protected] AUDIENCE DEVELOPMENT MANAGER Emily Martin [email protected] OFFSHORE EVENTS David Paganie (Houston) [email protected] Gail Killough (Houston) [email protected]

endeavorbusinessmedia.com OFFSHORE

10300 Town Park Drive, Suite S1000, Houston, TX 77072 U.S.A. Tel: (01) 713 621-9720 • Fax: (01) 713 963-6296 www.offshore-mag.com CORPORATE OFFICERS CHIEF EXECUTIVE OFFICER: Chris Ferrell CHIEF REVENUE/MARKETING OFFICER June Griffin

https://www.offshore-mag.com/white-papers/whitepaper/14172792/bulwark-protectiontop-10-safety-tips-for-summer-fr-compliance

EVP KEY ACCOUNTS Scott Bieda

Targeting Offshore Platform Cost Control Challenges

https://www.offshore-mag.com/white-papers/whitepaper/14170084/aggreko-targetingoffshore-platform-cost-control-challenges

CHIEF OPERATIONS OFFICER Patrick Raines

NEW MAPS, POSTERS, AND SURVEYS

CHIEF ADMINISTRATIVE AND LEGAL OFFICER Tracy Kane

• 2020 Rotary Steerable Systems Directory • 2020 Worldwide Survey of Subsea Processing Poster • 2020 Status of US Gulf of Mexico Deepwater Discoveries • 2020 Gulf of Mexico Map • 2019 Environmental Drilling and Completion Fluids Survey • 2019 Worldwide Survey of Floating Production, Storage and Offloading Units • 2019 MWD/LWD Services Directory • 2019 Worldwide MODU Construction/New Order Survey • 2019 Brazil Map • 2019 World Survey of Stimulation Vessels • 2019 Deepwater Solutions & Records for Concept Selection

SUBSCRIBER CUSTOMER SERVICE To start a free subscription, visit www.offshoresubscribe.com. Contact us for subscription questions, address changes and back issues.

OFFSHORE CUSTOMER SERVICE: P.O. Box 3257, Northbrook, IL 60065-3257 Tel: (847) 559-7598 Email: [email protected] CUSTOM PUBLISHING Roy Markum [email protected] Tel: (713) 963-6220

https://www.offshore-mag.com/resources/maps-posters.html

REPRINT SALES Please contact your sales associate.

SUBMIT AN ARTICLE

Offshore magazine accepts editorial contributions. To submit an article, please review the guidelines posted on our website by following this link. https://www.offshore-mag.com/page/article-submission 4

2005OFF04-15_fob.indd 4

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

COMMENT •

Market rebalancing, recovery underway DAVID PAGANIE, CHIEF EDITOR

THE COVID-19 PANDEMIC has forced millions

of people across the world to change the way they live and work. This has led to a precipitous decline in oil demand due to lower air and road transportation, and thus downward pressure on oil prices. The OPEC+ agreement, sealed via videoconference on April 12, is an important step toward rebalancing the market, but it will be a gradual process over the next several months. The agreement calls for a reduction of 9.7 MMb/d from May 1 until June 30, 7.7 MMb/d until December 30, and then 5.8 MMb/d for a subsequent 16-month period. Other producers outside the agreement may also see their output fall in the coming months due to the impact of the lower oil prices. This should help to reduce the supply overhang and build-up in storage, but it will not immediately bring supply in balance with the rapidly declining demand. The International Energy Agency (IEA) in its April oil report projected oil demand to fall by 29 MMb/d in that month yearover-year, which would be the lowest level since 1995. Demand would gradually recovery to 2.7 MMb/d down in December and close out the year down a record 9.3 MMb/d. Equally daunting is the economic outlook. The International Monetary Fund in April projected that the impact of COVID-19 would cause the global economy to contract by 3% this year, which is worse than the contraction recorded during the 20082009 financial crisis.

Layher SIM®

Oil company operators have responded to the deteriorating economic conditions with cuts to capex plans for 2020, many in the range of 20-30%. This includes pushing some project sanctions to next year or beyond. Oil demand should improve when the stay-at-home and physical distancing restrictions loosen, and business and travel pick up again. At the time of this writing, some countries were beginning to rollout plans to reopen their economies, and with government-sponsored stimulus packages to support the recovery. The IEA forecasts that the second half of this year could see demand exceed supply if the recovery plays out as expected. Key signals to keep an eye on are the level of compliance by OPEC+, oil storage inventories, and any improvements in global economic activity. For more on the impact of COVID-19, see page 16.

To respond to articles in Offshore, or to offer articles for publication, contact the editor by email ([email protected]).

From digital planning to the successful project with full planning and scheduling certainty. 2 Planning and scheduling certainty at the site. 2 Transparency in all work steps and cost control. 2 Increase in safety and profitability for every project. 2 Your access to BIM.

Learn more: software.layher.com

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM5 2005OFF_WilhelmLayher 1 3/30/20 8:59 AM

2005OFF04-15_fob.indd 5

4/28/20 11:38 AM

• DATA

Low oil prices to slow project sanctioning

In a $30/bbl oil price scenario Rystad Energy expects the sanctioned dollar amount by operators to fall below the 2016 level for both offshore and onshore projects. In the previous downturn, the pace of sanctioning long-cycle deepwater projects slowed down, and the analyst expect this trend to be repeated in the current cycle. The list of new deepwater projects currently under evaluation by operators is long and several projects are likely to face delays. Some large deepwater projects that have already been pushed from approval this year, include Aker Energy’s Pecan, Woodside’s Browse, and ExxonMobil’s Rovuma LNG Area 4 project.

100

900

90

800

80

700

70

600

60

500

50

400

40

300

Apr.

Jun.

Aug.

Oct. Dec. 2018

Feb.

Apr.

Total utilization % Total supply Note: Rig types included are jackups, semis, and drillships Source: IHS Markit RigPoint

Jun.

Aug.

Oct. Dec. 2019

Total under contract

Fleet utilization rate (%)

1,000

Number of rigs

The total number of jackups, semis, and drillships under contract grew by six units from 483 in February to 489 rigs through March, while the global supply stayed flat at 758 rigs. As a result, utilization improved from 63.7% in February to 64.5% in March. The number of rigs working also improved between February and March, climbing by five units to 462. However, it absolutely must be noted that going into March of this year, offshore drilling activity was still on the incline as operators were only just beginning to make adjustments in light of the spreading COVID-19 pandemic and the crash of the oil price. So, these metrics are currently falling and likely will continue to for at least some months to come.   – Justin Smith, Petrodata by IHS Markit

WORLDWIDE OFFSHORE RIG COUNT AND UTILIZATION RATE APRIL 2018 – MARCH 2020

30

Feb.

Working

PROJECT SANCTIONING STATUS AND FORECAST 160

Offshore sanctioned Offshore to-go Onshore sanctioned Onshore to-go

140 120 Billion USD

Worldwide offshore rig count and utilization rate

100 80

110

104

88

79 60

57

60

67 55

38

40

34

31

42

41 30

20 0

2014 2015 2016 2017 2018 2019 2020 2014 2015 2016 2017 2018 2019 2020 $30 $30 Offshore Onshore

Source: Rystad Energy ServiceCube

Drilled

120 100

Drilled

16

Drilling

Drilling

14

Expected

Expected

12 80

10 Bboe

Exploration well numbers this year could be 35% down on 2019 levels, according to Westwood Global Energy Group. Kai Gruschwitz, senior analyst, Global E&A, expects ~60-70 high-impact exploration wells will be completed by the end of 2020, which would be back down to numbers last seen from 2016 to 2018 following the 2014 price crash. The 26 ‘high-impact’ wells completed so far this year have discovered a total of around 2.1 Bboe and according to Westwood, wells currently drilling are testing a further 2.5 Bboe of risked volumes. The analyst now expects discovered volumes for 2020 to total 6-9 Bboe, compared with the 15 Bboe added last year worldwide.

HIGH-IMPACT EXPLORATION DISCOVERED AND PROSPECTIVE VOLUMES

HIGH-IMPACT EXPLORATION DRILLING

Completed HI Exploration Wells

Exploration drilling falling back to post-2014 levels

60 40

107

93 66

69

68

20

34 13 26

0

2015 2016 2017 2018 2019 2020

8 6 4 2 0

15.1

12.9 9.6 4.9

4.3 2.5

6.1

2.1

2015 2016 2017 2018 2019 2020

Source: Wildcat, Westwood analysis 6

2005OFF04-15_fob.indd 6

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

2005OF

IfififififificfififififihfifififixfifififivfifififififififififififiAfifififi’fifiKBfififififificfifififififi;fiThe KBE compressor frame.fi EfihfificfififibfififififififififiKBK:Tfififififififififfififififififi,fifihfifiKBEfififificfififibfififififfiffififififififififififififififififififififififififififi fififififififififificfifififififififififififififififi.fiGfifififififififififififfifififificfififfifififithe world standard in compression.fi CfififificfififififififiAfififififififififififibfifififififififififififfififififififififififififififi.

www.fifififificfififi.cfifi/KBE

2005OFF04-15_fob.indd 7 2005OFF_ArielCorp 1

4/28/20 11:38 AM 4/28/20 11:25 AM

JEREMY BECKMAN LONDON

• GLOBAL E&P

NORTH AMERICA

TGS and PGS have released final data from 3D surveys offshore Newfoundland and Labrador, ahead of the Canada Newfoundland Labrador Offshore Petroleum Board’s licensing round later this year. The Tablelands and North Tablelands data-sets cover 12,500 sq km (4,826 sq mi) in the eastern Orphan basin off Newfoundland, and identify potentially promising reservoirs from Lower Cretaceous to Lower Tertiary intervals. ◆◆◆ Husky Energy has suspended major construction work on its West White Rose platform offshore Newfoundland to protect site staff and contractors against the spread of COVID-19. However, production continues from the SeaRose FPSO, the White Rose field and its satellite extensions 350 km (217 mi) offshore. ◆◆◆ McDermott International is managing pre-front-end engineering design (pre-FEED) on behalf of BHP for a floating production unit for the deepwater Trian oilfield. The platform will be moored in 2,500 m (8,200 ft) of water, 180 km (112 mi) from the Mexican coast and 30 km (19 mi) south of the US/Mexico offshore median line. Houston Engineering and Wood are supporting McDermott respectively on the hull and topsides studies. ◆◆◆ Bahamas Petroleum Co. plans to re-schedule Perseverance #1, its first exploration well offshore the Bahamas, to mid-October or later. Recent shutdown measures imposed by the government have impacted movements of drilling rigs and associated preparations, the company said, with the three-month hurricane season ruling out drilling from mid-July. SOUTH AMERICA

Petrobras has two further deepwater oil discoveries off southeast Brazil. The well on the Araucária prospect, 200 km (124 mi) from the city of Santos and in 1,995 m (6,545 ft) water depth, was the first on the Uirapuru block in the presalt Santos basin. It encountered oil in porous reservoirs. ExxonMobil, Equinor,

and Galp are the other partners. The Natator oil discovery was on the Sudoeste de Tartaruga Verde block in the Campos basin, 130 km (81 m) offshore Macaé in 1,080 m (3,543 ft) of water. The well proved oil in post-salt carbonate reservoirs. ◆◆◆ Apache Corp. and Total have made what appears to be a second large oil discovery on block 58 offshore Suriname. The Sapakara West-1 well, drilled by the Noble Sam Croft, south of the earlier Maka Central-1 find, tested oil and gas condensate in multiple stacked targets in Upper Cretaceous Campanian and Santonian intervals. On completion of the well, the drillship was due to head 10 km (6 mi) to the northwest to drill the Kwaskwasi prospect. ◆◆◆ Brazil’s licensing agency ANP has temporarily suspended this year’s planned 17th oil and gas licensing round, due to worsening economic conditions and the growing impact of the coronavirus. It was reportedly set to offer 130 blocks across five basins. ◆◆◆ Searcher Seismic has reprocessed a further 8,008 km (4,976 mi) of 2D seismic over Argentina’s offshore Austral and Malvinas basins. The Argentina Super-Tie 2D reprocessing project now comprises over 19,000 km (11,806 mi) of broadband data to support the country’s future bid rounds and assessments of other commercial opportunities. Searcher said work to date had improved imaging of deeper stratigraphy and basement potential. ◆◆◆ Premier Oil and its partners remain committed to the Sea Lion oilfield development in the offshore North Falkland basin. However, the final investment decision will probably be delayed until the external macro-environment improves, according to Rockhopper Exploration. The partners now plan to target 250 MMbbl from the first phase via 29 wells, 12 to be drilled prior to first oil, with production building to a plateau of around 85,000 b/d via a conventional FPSO. WEST AFRICA

Location of Notator oil discovery in the Campos basin. (Courtesy Petrobras) 8

2005OFF04-15_fob.indd 8

BP and partner Kosmos Energy may delay start-up of the ultra-deepwater Greater Tortue Ahemyim gas-condensate project off Mauritania and Senegal until 2023, due to recent global developments. Travel bans, social distancing, and office closures have impacted the project’s progress, Kosmos said, including construction of the breakwater for the LNG jetty during the 2020 weather window. BP has also notified Golar LNG that it will not now be ready to receive the converted FLNG vessel Gimi on the planned connection date in 2022. ◆◆◆ The BGP Prospector has started acquiring the 4,770-sq km (1,842-sq mi) Gambito 2020 3D seismic survey in the MSGBC basin offshore The Gambia. TGS, which is coordinating the campaign with BGP and the government, says the deep/ultra-deepwater areas covered appear strongly prospective, based on large basin floor fans identified on previous 2D surveys. WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

JEREMY BECKMAN LONDON

◆◆◆ Aker Energy has cancelled a letter of intent that it issued in February to Malaysian shipyard Yinson to charter and operate and FPSO for the Pecan field development offshore Ghana. The company has suspended work on the project in the Deepwater Tano Cape Three Points until further notice. ◆◆◆ São Tomé and Principe and Equatorial Guinea have agreed to create a Special Zone for Joint Exploration of hydrocarbons in blocks bordering each country’s maritime zone. They hope to initiate offshore operations in October. ◆◆◆ PGS has completed acquisition of its 3D Kwanza Shelf survey offshore Angola, with total GeoStreamer broadband overage over blocks 6, 7 and 8 and surrounding areas of the shelf now at 8,300 sq km (3,205 sq mi). The company will make the data available for Angola’s planned 2021 licensing round. The shallow-water Kwanza Shelf is said to present imaging challenges, which the survey is part-designed to address. MEDITERRANEAN SEA

The Lebanese Petroleum Administration has extended the closing date for applications for the country’s second offshore exploration licensing round to June 1, 2020. The Ministry of Energy and Water accepted that bid preparations may have been impacted by COVID-19 restrictions. ◆◆◆ The hull of the FPSO Energean Power reached the Sembcorp Marine Admiralty Yard in Singapore last month following a short voyage from the Cosco yard in China. Preparations for the topsides integration, however, were put on hold due to a (temporary) COVID-19 related suspension of activities. Energean is confident the floater will be ready in time to receive first gas from the Karish field offshore Israel in the first half of The hull of the FPSO Energean Power next year. Later in 2020, during its tow to Singapore. (Courtesy Energean) the company expects to take an investment decision on tying in the Karish North discovery to the FPSO. same sector.

GLOBAL E&P •

signments, a collaboration with SapuraKencana, involved construction and installation of three new platforms, replacement of an existing topsides, and installation of associated subsea infrastructure. ◆◆◆ Development drilling has started on Qatar Petroleum’s offshore North Field East project. Eight jackups will drill a total of 80 wells in the first phase, with the increased gas production raising Qatar’s LNG capacity from 77MMt/yr to 110 MMt/yr. The first of four new offshore jackets for the project was due to be installed late last month. ASIA/PACIFIC

ONGC has produced first gas from the 98/2 block subsea development in the Krishna Godavari basin offshore eastern India. McDermott International is the project engineering contractor, responsible for supply and installation of the subsea production systems, including 26 deepwater trees, and the SURF system in water depths extending out to 1,300 m (4,265 ft). ◆◆◆ CNOOC has discovered oil in an emerging play, the Laibei lower uplift, in the southern Bohai basin offshore China. Well KL6-1-3 was drilled on the Kenli 6-1 structure in 19.2 m (63 ft) water depth in Bohai Bay, intersecting 20 m (65.6 ft) of oil pay zones and flowing 1,178 b/d during testing. AUSTRALASIA

Searcher Seismic has entered a marketing and sales agreement with Timor-Leste’s Petroleum Authority ANPM for its Offshore Timor-Leste data and study package. Searcher, in co-operation with Discover Geoscience, has complied the seismic and well data to support companies assessing the 19 offshore blocks available under the country’s current second petroleum licensing round. The package reviews all play types, including little-explored Triassic plays. •

MIDDLE EAST

ADNOC has terminated two contracts awarded in February to the Petrofac Emirates joint venture for the Dalma gas development in the Ghasha ultra-sour offshore concession, 140 km (87 mi) northwest of Abu Dhabi. Petrofac said it would work with the NOC over the coming weeks on alternative options better suited to the present challenging environment. One of the as-

Blocks on offer offshore Timor-Leste. (Courtesy Autoridade Nacional do Petróleo e Minerais de Timor-Leste)

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM9

2005OFF04-15_fob.indd 9

4/28/20 11:38 AM

JEREMY BECKMAN LONDON

• OFFSHORE EUROPE

JOHAN SVERDRUP HITS PEAK EARLY

Equinor expected production from Phase 1 of its Johan Sverdrup project in the Norwegian North Sea to reach a peak of 470,000 b/d this month, ahead of schedule. Arne Sigve Nylund, EVP for Development and Production Norway, credited higher plant capacity, adding that output had been stable since start-up last October with the 10 wells drilled performing above expectations. Sverdrup’s low operating costs mean that the field continues to provide stable revenue and cashflow both to the partners and Norwegian society as a whole, he stressed. Work continues on Phase 2, which will raise production to 690,000 b/d via a second drilling and production platform connected to the existing field center, with targeted operating costs of less than $2/bbl.

However, most of this year’s scheduled wells already had contracted rigs, so the impact of deferrals will likely be felt more in 2021. Just as the extent of the downturn was becoming apparent, Total announced a potentially commercial HP/HT gas, condensate and light oil discovery in the Isabella prospect in the UK central North Sea, 40 km (25 mi) south of the company’s Elgin-Franklin production complex. The well, drilled by the jackup Noble Sam Hartley, delivered 64 m (219 ft) of net pay in Upper Jurassic and Triassic reservoirs. Wood Mackenzie analyst Glenn Morrall said the proximity to offshore infrastructure could enhance the field’s economics when market optimism eventually returns. In the central Norwegian North Sea, MOL found light oil and gas in the Evra/Iving structure, 8 km (5 mi) northwest of Vår Energi’s Balder X redevelopment (the Balder and Ringhorne fields), with potentially up to 71 MMboe recoverable. And Wintershall Dea’s Bergknapp oil discovery in the Norwegian Sea, close to the company’s producing but declining Maria field, could hold up to 97 MMboe. NO CHANGE TO LICENSE ROUND PLANS

The topsides module for Wintershall Dea’s Nova field. (Courtesy Wintershall Dea/Thor Oliversen)

Rosenberg Worley in Stavanger has completed construction of a new 740-metric ton (816-ton) topsides module for processing hydrocarbons from Wintershall Dea’s Nova field in the North Sea. The structure was due to be transferred to Heerema Marine Contractor’s crane vessel Sleipnir for installation on the Neptune Energy-operated Gjøa platform. The module is also designed to supply injection water to Nova from the platform: first gas should follow in 2021. NORTH SEA OPERATORS APPLYING BRAKES TO EXPLORATION

Exploratory drilling could be one of the chief casualties of budget cuts in the North Sea area this year, despite strong results from several wells completed during 1Q. Following notifications of postponements, the Norwegian Petroleum Directorate downgraded its estimate of exploration wells across the Norwegian sector from 50 to 40, and could not rule out further reductions in the future. Some planned geophysical surveys have also been delayed or canceled offshore Norway. While UK offshore exploration recovered in 2019, operators had indicated activity would fall back again in 2020, according to Rystad Energy. Ithaca Energy reacted swiftly to the latest oil price collapse by deferring a planned well on the Fotla prospect, and Rystad expected other UK operators to take similar action. 10

2005OFF04-15_fob.indd 10

Norway’s Ministry of Petroleum and Energy is pushing ahead with its Awards in Predefined Areas (APA) 2020 licensing round. It plans to include 36 new offshore blocks along with re-offered blocks, although the proposal is out for public consultation. Minister Tina Bru said that despite the present challenges, the industry needed continued stable access to new acreage for petroleum exploration, while the government wants to maintain activity levels on the Norwegian shelf. Britain’s Oil and Gas Authority too affirmed its commitment to this summer’s planned 32nd UK offshore licensing round, adding that it would be flexible in considering amendments to existing license timelines. AKER BP COMMITS TO VALHALL PLATFORM CLEAR-OUT

Aker BP has responded to the recent shocks, like many others, by drawing up various cost-cutting measures, including putting on hold the non-sanctioned redevelopment of the Hod field in the southern Norwegian North Sea. But the company remains committed to a series of platform removals from the Valhall complex that receives Hod’s production. Last June, Allseas’ Pioneering Spirit removed the 3,800-t topsides from the QP platform, one of the three original facilities at Valhall that will go as part of the modernization of the field center. During 2021-26 the vessel will lift and dispose of the drilling and production/compression platforms and connecting bridges’ and Hod’s 4,600-t unmanned production platform, the first of its type in the Norwegian North Sea. Others to be optionally removed are Valhall’s quarters platform jacket and the 2/4-G jacket on the Ekofisk field, 24 km (15 mi) to the north. •

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

BRUCE BEAUBOUEF HOUSTON

GULF OF MEXICO •

Gulf operators keep pushing forward despite crisis OPERATORS AND DEVELOPERS working in the Gulf of

Mexico have continued to advance their projects, even while the global oil market crashed and the Coronavirus pandemic wreaked havoc with global offshore E&P market. In April, Equinor and co-venturers Progress Resources USA Ltd. and Repsol E&P USA Inc. reported that they encountered oil in the Monument exploration well in the central US Gulf of Mexico. Drilled in Walker Ridge block 316, the well found about 200 ft (60 m) of net oil pay with good reservoir characteristics in Paleogene sandstone. This provides an early indication of the productive reservoir interval at the well location, the company said. The drillship Pacific Khamsin drilled the well to a TD of 33,348 ft (10,164 m). Water depth is about 1,900 m (6,234 ft). Bjørn Inge Braathen, senior vice president of Exploration in North America, said: “We are pleased to have proved an accumulation of movable hydrocarbons in the Monument exploration well. However, determining the full potential of the discovery will require further appraisal drilling.” The Monument exploration well is operated by Equinor (50%) with partners Progress Resources USA Ltd. (30%) and Repsol E&P USA Inc. (20%). Monument is Equinor’s first operated exploration well in the US Gulf of Mexico since 2015. Mfon Usoro, senior research analyst at Wood Mackenzie, said: “In the current low oil price environment, Equinor’s Monument discovery is a welcome one for the partners – Repsol and Petronas subsidiary Progress Resources – and the wider US Gulf of Mexico. The discovery proves the mature region still has more life in it.” Equinor has a strong footprint in the US Gulf of Mexico (largely in non-operated assets), but the company has indicated plans to become an operator in the region, with growth focused on Paleogene-rich resources. Wood Mackenzie says that it expects Monument to be one of Equinor’s first commercialized discoveries in the Gulf. But the company could face technical challenges with the complex and often compartmentalized Paleogene reservoir. Based on the drill depth of more than 32,000 ft, the discovery could be similar to other ultra-high-pressure fields requiring 20,000 psi-rated equipment which indicates significantly higher development cost. Exploration activity in 2020 has taken a hit as companies have quickly slashed budgets. It is likely that appraisal efforts at Monument will take a back seat until prices recover, according to Wood Mackenzie.

The deepwater drillship Pacific Khamsin drilled the Monument discovery well to a TD of 33,348 ft (10,164 m). (Courtesy Equinor)

Meanwhile, Subsea 7 announced the award of contracts by Chevron U.S.A Inc. for subsea installation services related to the Anchor field in the Green Canyon area of the Gulf of Mexico. The Anchor field is about 140 mi off the coast of Louisiana.   Subsea 7’s scope of work includes project management, engineering, procurement, construction and installation of the SURF components including, but not limited to, the production flowlines, risers, umbilicals, flying leads, jumpers, and associated appurtenances.  Project management and engineering will commence immediately at Subsea 7’s offices in Houston. Fabrication of the flowlines and risers will take place at Subsea 7’s spool-base in Ingleside, Texas, with offshore operations anticipated to occur in 2022 and 2023.   In mid-April, Genesis Energy, L.P. said that it had entered into agreements to provide downstream transportation services for crude oil production associated with the deepwater Gulf of Mexico Katmai field development, through the existing Tarantula production platform. The agreements are with Fieldwood Energy LLC, Ridgewood Katmai, LLC and ILX Prospect Katmai, LLC, two entities managed by Ridgewood Energy Corp. The existing Tarantula production platform is owned by Fieldwood. The Tarantula platform, located in South Timbalier block 308, has the capability to process up to 25,000 b/d of oil from the Katmai field development. The Katmai field development is in Green Canyon blocks 39 and 40. The Tarantula platform is currently connected to the Tarantula lateral and the crude oil production will be delivered to the Poseidon crude oil system for delivery to shore. First deliveries of oil are anticipated in the second quarter of this year. •

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM11

2005OFF04-15_fob.indd 11

4/28/20 11:38 AM

• SUBSEA SYSTEMS

CHEVRON LETS ANCHOR CONTRACTS

Chevron has awarded Aker Solutions a master agreement to provide umbilicals for its operated oil and gas fields in the US Gulf of Mexico. The first job involves providing 24 km (15 mi) of 20,000-psi steel tube umbilicals for the Anchor development, 225 km (140 mi) offshore Louisiana in a water depth of 1,524 m (5,000 ft).The work scope includes engineering, design and manufacture of dynamic and static con- The Anchor umbilicals will be built at the company’s facility in Mobile, Alabama. trol umbilicals, dynamic (Image courtesy Aker Solutions) and static power umbilicals and distribution equipment, and service/ installation support. The company’s facility in Mobile, Alabama, will manage the program. The master agreement is said to lay the foundation for a longterm collaborative relationship incentivizing both companies to jointly improve their long-term technical and commercial performance through delivering multi-project synergies, repeatability, and life-of-field thinking. Chevron also contracted Subsea 7 to provide subsea installation services for the Anchor project. The work scope includes project management, engineering, procurement, construction and installation of the SURF components including, but not limited to, the production flowlines, risers, umbilicals, flying leads, jumpers, and associated appurtenances. Project management and engineering are under way at the company’s offices in Houston. Fabrication of the flowlines and risers will take place at its spoolbase in Ingleside, Texas, with offshore operations anticipated to occur in 2022 and 2023. Craig Broussard, vice president for Subsea 7 US, said: “The combination of the SURF scope for Subsea 7 and the ongoing subsea equipment delivery by OneSubsea, will allow the Subsea Integration Alliance to work in partnership with Chevron to unlock the value of an integrated approach to project optimization.” MERO TO FEATURE STAINLESS STEEL UMBILICAL TUBES

Sandvik will supply stainless steel umbilical tubes for Petrobras’ Mero oil field project in the presalt Santos basin offshore Brazil. According to the company, field developments in the region more typically use thermoplastic hose umbilicals. For this contract, Sandvik will supply more than 500 km (310 mi) of super duplex Sandvik SAF 2507 stainless steel umbilical tubes encapsulated by Prysmian Group. Mero is managed by the Libra Consortium, a partnership between Petrobras, Total, Shell Brasil, CNPC, and CNOOC. Mero Phase 1 calls for 17 wells in a water depth of around 2,000 m (6,562 ft). According to Sandvik, deeper offshore fields require more robust 12

2005OFF04-15_fob.indd 12

JESSICA STUMP HOUSTON

subsea equipment to withstand higher pressures, corrosion and erosion. SAF 2507 is an austenitic-ferritic stainless steel said to provide strong resistance to stress corrosion cracking, pitting and crevice corrosion, erosion corrosion and corrosion fatigue, with high mechanical strength and good The company will supply more than 500 km (310 mi) of super duplex Sandvik weldability features. SAF 2507 stainless steel umbilical tubes In addition, the com- encapsulated by Prysmian Group. pany claims, umbilical (Image courtesy Sandvik) seamless tubes made from this material provide stronger structural reinforcement in smaller sizes compared to thermoplastic technology. TECHNIPFMC SECURES AUSTRALIA, ANGOLA ASSIGNMENTS

Woodside Energy has awarded TechnipFMC an integrated EPCI (iEPCI) contract for the Lambert Deep and Greater Western Flank Phase 3 developments offshore northwest Australia. The company will design, manufacture, and install equipment including subsea production systems, flexible flowlines and umbilicals for connection to the Angel platform. The latter is about 120 km (74.6 mi) northwest of Karratha and is connected to the North Rankin Complex via a 50-km (31-mi) subsea pipeline. This is the second contract under TechnipFMC’s recent five-year iEPCI frame agreement with Woodside. Arnaud Pieton, President Subsea at TechnipFMC, said it confirmed “our common ambition to transform subsea economics through integration, standardization, and configurability.” BP has awarded the company an iEPCI contract for the deepwater Platina field development in block 18 off Angola. Water depths range from 1,200-1,500 m (3,937-4,921 ft). The award covers the manufacture, delivery, and installation of subsea trees, a production manifold with associated subsea control and connection systems, rigid pipelines, umbilicals and flexible jumpers. In addition, TechnipFMC has postponed its planned separation into two new businesses. Market conditions brought on by the COVID-19 pandemic have deteriorated, the company said, with a sharp decline in commodity prices and heightened volatility in global equity markets. The present environment therefore does not justify the separation into TechnipFMC and Technip Energies, the company said. It stressed that the strategic rationale for the separation is unchanged. It remains committed to the transaction and will continue preparations to ensure that the two companies are ready for separation once conditions have improved. •

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

JESSICA STUMP HOUSTON

DRILLING CONTRACTORS STACKING RIGS

As the low oil price and coronavirus pandemic have forced operators to cut budgets and cancel contracts, drilling contractors have started stacking and retiring rigs. As of this writing, Noble Corp. has cold-stacked the drillship Noble Bully II and the semisubmersible Noble Paul Romano; and warmstacked the jackups The drilling contractor has cold-stacked Noble Sam Hartley, No- the drillship Noble Bully II. (Courtesy Noble Corp.) ble Sam Turner, and Noble Hans Deul. In addition, the drilling contractor will retire the 1981-built jackup Noble Joe Beall. Transocean Ltd. has stacked the semisubs Henry Goodrich and Transocean 712. Shelf Drilling has stacked the jackups Galveston Key and Key Hawaii. SHELL, BP RETAIN NORTH SEA FPSOS

Teekay Corp. has entered into a new bareboat charter contract with Britoil Ltd., a BP subsidiary, for the FPSO Petrojarl Foinaven for up to about 10 years. The FPSO has operated at the Foinaven field west of Shetland since 1997. Under the terms of the contract, Teekay is expected to receive an upfront payment of about $67 million in cash, a nominal per day rate over the life of the contract, and a lump- The FPSO Petrojarl Knarr will operate at the Knarr field in the Norwegian North sum payment at the Sea until at least March 2022. (Courtesy end of the contract pe- Altera Infrastructure) riod, which is expected to cover the costs of recycling the FPSO unit in accordance with the EU Ship Recycling Regulations. As part of the transaction, Teekay Offshore Partners L.P., now known as Altera Infrastructure L.P. has entered into agreements with BP directly to provide the operations and shuttle tanker services for the FPSO. Altera Infrastructure subsidiary Teekay Knarr has agreed to a contract amendment with AS Norske Shell concerning the Knarr field in the Norwegian North Sea. The contract for lease and operation of the FPSO Petrojarl Knarr, which has operated on the field since 2015, will now run until at least March 2022. Original duration of the firm contract period had been until March 2021. Under the amendment, there will be a reduction in the day rate from March 2021 to March 2022 and the fee payable by the operator if the contract were not extended has been waived.

VESSELS, RIGS, & SURFACE SYSTEMS •

In return, Shell has agreed to the introduction of an additional production volume and oil price-related tariff. The amendment also provides for a mutual right to terminate the contract on six months’ notice without payment of penalty, the termination not being effective before March 2022. SOLSTAD TO RESTRUCTURE, REDUCE FLEET

Solstad Offshore has reached agreement with a majority of its stakeholders on a restructuring of the company. Key terms include: • Around NOK10 billion ($959 million) of debt (secured debt, leasing obligations, bond obligations and others) to be converted to equity. • The group’s balance sheet and liquidity to be strengthened. • The offshore service/construction/platform supply vessel fleet to be rationalized, with 37 older vessels likely to be sold or scrapped, with the long-term business based on a core fleet of around 90 vessels. • Termination agreements in respect of the leasing agreements for the five vessels owned by subsidiaries of SFL Corp, and new leasing agreements on amended terms for two vessels owned by a subsidiary of Ocean Yield, F-Shiplease. CEO Lars Peder Solstad said: “We are entering a period where global offshore activity is likely to be reduced with the impact of the COVID-19 virus and the drop in the oil price. A successful implementation of the restructuring will enable the company to better meet the challenges of the current markets and position the company well for the coming years.” SILVER EAGLE ORDERS JACKUPS

Bahrain-based Silver Eagle Global has contracted PetroVietnam Marine Shipyard to build two self-elevating drilling units (SEDU). Based on the Levingston/MiNO Enhanced 430WC-4 design, the new series will have what Silver Eagle claims is the industry’s largest deck area and deck load capacity, a cantilever with modular design, and a high-speed jacking system. The self-propelled design is said to be capable of working at greater water depths and in harsh environments. ABS will provide classification for the series. Matthew Tremblay, senior vice president, Global Offshore, ABS, said: “These unique units offer the flexibility to adapt to the mission and payload. The large deck and cantilever are innovative design features, while self-propulsion and the four legs allows the vessel to get on the job site independently. These unique design features of the Silver Eagle units will bring a new level of versatility for the offshore industry.” Silver Eagle, which is associated with Rawabi Holding of Saudi Arabia, has also entered into a master service arrangement with Baker Hughes. •

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM13

2005OFF04-15_fob.indd 13

4/28/20 11:38 AM

• DRILLING & PRODUCTION

BRUCE BEAUBOUEF HOUSTON

Drillers batten down the hatches for rough seas ahead THE OFFSHORE DRILLING INDUSTRY is facing the direst

again as the industry now tries to continue to cut costs and improve moment in its 73-year history. With the collapse in oil prices and its performance in a challenging environment,” Føre said. the growing coronavirus pandemic, operators and E&P firms are Evercore ISI sounded similar ominous portents in its Offshore canceling and deferring tenders and terminating rig contracts in Rig Market Snapshot of April 15, 2020. The report noted that cona rapid succession. tracting activity fell by almost two-thirds in March, and is on track The consensus among offshore drillers is that things will almost to trend lower for a third straight month, comparing negatively on certainly get worse before they get better. This was the major a year-over-year basis for a fourth straight month. Only four rig conclusion of a recent report issued by Westwood Global Energy contracts had been announced as of mid-April, trailing well below Group’s RigLogix service. Most of the nearly 300 drilling programs the 23 contracts announced at this point a year ago. All four conthat currently have 2020 start dates will be delayed, the consulting tracts were for less than a year, with two contracts each for jackups firm says. and floaters but no other Operators are typicaldiscernable trend except ly cutting planned 2020 declining activity. capex by 20-30%in reMeanwhile, with opsponse to falling oil pricerators canceling and es, and the coronavirus deferring tenders and is impacting movements terminating rig conof personnel and equiptracts, drillers have bement/services to and gun to cold stack and from rigs. This all means retire additional rigs. the number of idle rigs From mid-March to midwill soon increase April, three floaters and substantially. a jackup have been cold Already there has stacked while four floatbeen a steady surge of ers and two jackups have contract cancellations been retired, bringing the and terminations. Drill- Noble Corp. plc says it has cold stacked the semisubmersible Noble Paul Romano industry total to 39 float(left) and has warm stacked the jackup Noble Sam Hartley (right). ing contractors could be ers/87 jackups cold facing a combined loss of revenue of around $3 billion in 2020 and stacked (both 17% of the current available supply x-newbuilds) 2021, says Rystad Energy. The analyst estimates the total value of and 141 floaters/109 jackups retired since 2014. Evercore said that agreed contracts over the two years at $30 billion. So far, in the it expected a couple more contracts to be announced in the second present crisis, six rig years of contracts have been canceled, amounthalf of April, but added that “contracting activity is likely to be ing to around $400 million in value, and more look set to be called depressed for several more quarters.” off as operators cut capex budgets and delay projects. Some of the more notable recent contract cancellations and “More than $22 billion in contract value was wiped off the books early terminations include: as a result of contracts being cancelled between 2014 and 2017,” * ExxonMobil has notified Borr Drilling Ltd. of the early termisaid Oddmund Føre, Rystad head of Offshore Rig Market Services. nation of the contracts for the jackups Gerd and Groa offshore “Now, in the infancy of a new downturn, a market that was only Nigeria. The rigs were under contracts originally committed until beginning to return to a healthy level of contracting activity, contract April 2021 and May 2021, respectively. volumes and day rates has seen its hopes crushed.” * VAALCO has released Vantage Drilling International’s jackup Five years ago, following the previous oil price collapse, E&P Topaz Driller after the rig completed a successful workover on the companies canceled many contracts and chose not to declare South East Etame 2H well offshore Gabon. contract extension options, subsequently re-hiring rigs at lower * Noble Corp. plc says it has cold stacked the drillship Noble rates. But next year especially, there may be few contracts left for Bully II and the semisubmersible Noble Paul Romano; has warm them to cancel. So new contracts could be difficult to secure in stacked the jackups Noble Sam Hartley, Noble Sam Turner, and the current environment. Noble Hans Deul; and will retire the jackup Noble Joe Beall. • “We expect day rates to be pushed down to opex levels once 14

2005OFF04-15_fob.indd 14

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

OFFSHORE WIND ENERGY •

AKER SOLUTIONS, COGNITE SECURE DIGITAL OFFSHORE WIND ENERGY TECHNOLOGY GRANT

Aker Solutions and Cognite have been awarded a $2-million grant from the California Energy Commission (CEC) for a project called NextWind Real Time Condition Monitoring. The project is focused on next generation solutions in wind through digitalization and aims to develop a holistic digital solution that will enable monitoring the condition of an offshore floating wind farm and its impact on the environment via live data streaming.

SUBSEA 7 WINS CONTRACT OFFSHORE GERMANY

Subsea 7 has announced the award of a sizeable contract by innogy Kaskasi GmbH for the Kaskasi offshore wind farm project, located about 35 km northwest of Heligoland in the German sector of the North Sea. The contracted work scope includes the transport and installation of the offshore substation foundation, 38 wind turbine monopile foundations and 52 km of inner array grid cables in water depths of between 18 and 25 m. Offshore installation is scheduled for execution in 2021 and 2022 using Seaway 7’s heavy lift, cable lay and support vessels. When completed, the Kaskasi offshore wind farm will have an installed capacity of 342 MW. CAPE HOLLAND TO SUPPLY VIBRO LIFTING TOOL

Aker Solutions and Cognite will develop a digital solution that will enable condition monitoring of an offshore floating wind farm. (Courtesy Aker Solutions)

Aker Solutions, partnering with Cognite, was selected for the grant award as part of the California Energy Commission’s Electric Program Investment Charge (EPIC). The program provides grants for companies applying research and projects designed to help develop next-generation wind energy technologies. The projects must include objectives that increase the competitiveness, performance, and reliability of wind generation while reducing costs and effects on the environment and wildlife. A digital twin model of physical offshore wind assets will be developed to assess conditions and integrity management. This real-time information will allow access and analysis of data to help reduce operating expenses and maintenance costs by improving production efficiencies. Making this data available to a wide range of users will allow for additional understanding of environmental and wildlife impacts to help reduce mitigation. In April 2018, the Redwood Coast Energy Authority selected a consortium which includes Aker Solutions, Principle Power and EDPR Offshore to enter into a public-private partnership to pursue the development of the proposed Redwood Coast Offshore Wind Project. The 100-150 megawatt floating offshore wind farm is planned to be located more than 30 km off the coast of Humboldt Bay, and is expected online in the mid-2020s. The team intends to use this project as a case study for the new initiative due to its relevance.

CAPE Holland has been awarded a contract by Seaway 7 to supply a Vibro Lifting Tool for the installation of the monopile foundations for the Kaskasi offshore wind farm. This will be the first offshore wind project whereby the monopiles will be driven to final penetration with a vibro hammer only, says CAPE Holland. Seaway 7 first used the CAPE vibro equipment in 2012 to drive the monopiles for the Riffgat project to stabile depth. Since then they used the vibro equipment on a number of oil and gas projects and last year also on an offshore wind farm project in Taiwan. The Vibro Lifting Tool for this project will have multiple vibro hammers linked together to provide a total of 1920 kgm. A specially de- CAPE Holland says it veloped clamping system will be will supply a Vibro Lifting Tool (VLT) for work on the used to create the interface be- Kaskasi offshore wind farm. tween the Vibro Lifting Tool and (Courtesy CAPE Holland) the flanged top of the monopiles. PULSE WINS OFFSHORE TAIWAN WIND FARM CONTRACT

Ørsted has contracted Pulse Structural Monitoring, an Acteon company, to provide digital structural monitoring and insight services and equipment for the Greater Changhua wind farm offshore Taiwan. The company will design, fabricate, install, and commission its monitoring instrumentation on three wind turbine foundations. It will supply its NX2 digital platform to acquire a range of high-quality measurements that include bending and torsional strain, inclination, displacement and acceleration in key components of the jacket legs, nodes and wind turbine generator towers. This Acteon integrated solution will also include corrosion and anode monitoring equipment. •

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM15

2005OFF04-15_fob.indd 15

4/28/20 11:38 AM

• CRISIS MANAGEMENT

Industry responds to low oil prices, coronavirus pandemic Reduced capex, project delays and cancellations JESSICA STUMP, ASSISTANT EDITOR

16

2005OFF16-26_crisis.indd 16

60%

Initial Capex Revised Capex Budget Cut

35 30

50% 40%

25

30%

20 15

20%

Budget cut

40

10 10%

Santos

Noble Energy

Aker BP

Devon Energy Corp.

Husky Energy

Marathon Oil Corp.

OMV

Continental Resources

Pioneer Natural Resources

Repsol

Canadian Natural Resources

Source: GlobalData Oil and Gas Intelligence Center

Woodside Petroleum

Ecopetrol

Suncor Energy

EOG Resources

Occidental Petroleum Corp.

Eni

ConocoPhillips

Equinor

Total

Petrobras

Shell

0

Chevron

5 Saudi Aramco

try began 2020 on a cautiously optimistic note. For those that survived the 20142016 downturn, it appeared that there was light at the end of the tunnel. That optimism was quickly shattered with the onset of the novel COVID-19 (coronavirus) pandemic and the equally rapid collapse in crude oil prices. The lockdowns and quarantines that followed have taken a huge bite out of oil demand; this has further eroded oil prices. The result is an unprecedented level of uncertainty in the market. The industry is having to contend with three fundamental challenges, says Wood Mackenzie. The first is substantial reduction in demand for equipment and services. Stricter capital discipline from operators will reduce demand substantially this year both onshore and offshore, which means that only a handful of major projects will go forward this year. The second challenge will be a test of financial resilience. Companies across the supply chain had already cut back significantly in the past few years. It will be difficult for many to identify further savings without drastic measures such as refinancing or the restructuring of business models. Staff cuts and bankruptcies appear inevitable. The third challenge will be excess capacity. Companies holding onto idle assets “just in case” will have to think again. The prospect of sub-$40/bbl oil will force profound change and pain in the short term, Wood Mackenzie said, but could ultimately create a more sustainable business for those that survive.

OIL AND GAS CAPITAL EXPENDITURE, BY COMPANY IN 2020

2020 Capital Expenditure (US$ billions)

THE OFFSHORE OIL AND GAS indus-

0%

REDUCED CAPITAL SPENDING PLANS

Global capex for exploration and production companies is expected to drop by up to $100 billion this year, under Rystad Energy’s updated base case scenario of $34/bbl in 2020 and $44/bbl in 2021. According to the analyst’s data, the expected decline this year will make 2020’s capex volumes, estimated at about $450 billion, the lowest in 13 years. Its estimates before the coronavirus pandemic had indicated E&P would remain flat year-on-year. In a low case scenario, where Brent averages $25/bbl in 2020, global investments may plunge to around $380 billion this year, falling to almost $300 billion in 2021, a 14-year and a 15-year low respectively. The estimated cost cuts will be mainly achieved by lower activity within US shale, delays to projects that are yet to reach the final investment decision (FID) stage, deferred exploration activity, and cost cuts within development and production for conventional assets. By the end of March, GlobalData reported that E&P companies had cut more than $50 billion in capex. Daniel Rogers, Oil and Gas Analyst at GlobalData, said: “Of the announced $50 billion in cuts to date, approximately 20% of that is coming solely from Saudi Aramco, which could have implications for its ongoing expansion projects in the country. Elsewhere, across the supermajors, the investment cuts are within the 20-25% range, resulting in WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

CRISIS MANAGEMENT •

multi-billion-dollar pull backs in new projects and non-critical investments.” At that time, the analyst found that the the average announced capex cut for 2020 is 29% from original forecasts. On the higher end of the spectrum, US operators with significant shale acreage and Australian operators with imminent large-scale LNG projects have taken the most drastic reduction measures. “The types and severity of the cuts seen will differ depending on stakeholder requirements. National oil companies will strive to protect obligated payments to the government, whilst maintaining production volumes, whereas independent oil companies will focus on strengthening balance sheets and continuing to generate returns for investors in a challenging environment,” Rogers concluded. In early April, ExxonMobil and BP cut capex spending by 30% and 25%, respectively. PROJECT DELAYS

Of the 50-plus projects Wood Mackenzie had identified as potentially going ahead this year, only 10 now look to have a chance of proceeding. According to Rob Morris of Wood Mackenzie’s upstream research team, “only those with the strongest balance sheets will even contemplate major project FIDs. The majors and certain NOCs will take the lead, while projects with financially stretched partners and at the higher end of the cost curve will struggle.” Projects least at risk of deferrals are thought to include large deepwater oilfield developments off Guyana and Brazil, and ‘niche LNG’, including low-cost greenfield and feedgas backfill at legacy liquefaction projects. “Two-thirds of all greenfield projects, representing $110 billion of total future investment, face almost certain deferral,” Morris said. “Some project sanctions will be delayed to 2021 and beyond. Some will be completely reworked or even put on hold permanently. These include projects with weaker strategic drivers, high breakevens, and/or financially distressed operators. “Africa, the North Sea, Southeast Asia, and Australian LNG face mass project deferrals. Australian LNG is perhaps the most high-profile casualty. As we predicted, both Woodside Petroleum and Santos have already announced delays at Scarborough and Barossa until market conditions improve.” At the time of writing, many offshore projects have been delayed. Woodside has pushed back the FID for the Scarborough gas project and Pluto Train 2 on the North West Shelf to 2021. The Browse gas project has also been deferred. Jadestone Energy has delayed development of the Nam Du and U Minh gas fields offshore Vietnam. The company had assumed receipt of government approvals by 1Q DOLLAR VALUE BY REGION FOR 2020 CONTRACT OPTIONS Africa

$328.0

Southeast Asia

$256.3

Middle East

$238.8

North Sea

$188.2

US Gulf of Mexico

$136.1

Brazil

$106.0

Mediterranean

$101.7

Eastern Canada

$55.0

Australia

$47.1

South America - Other

$44.5

Mexico

$42.7

Others

$44.5

Source: RigLogix

2020, and now envisages start-up of the two fields no earlier than late 2022. Equinor and Husky Energy have reportedly postponed the Bay du Nord project offshore eastern Canada. Husky also has deferred by a year development of the block 15/33 oil field offshore China and put the brakes on developing the MDA-MBH gas field offshore Indonesia. In addition, the company has suspended major construction activities related to the platform-based West White Rose development offshore Newfoundland and Labrador. Aker BP has put on hold the non-sanctioned Hod redevelopment in the Valhall area of the southern Norwegian North Sea. Siccar Point Energy E&P Ltd. and joint venture partner Shell UK have deferred the planned sanction date for the deepwater Cambo project west of Shetland from 3Q 2020 to the second half of 2021. INEOS FPS delayed this summer’s planned shutdown of the Forties Pipeline System in the UK central North Sea to spring 2021. Aker Energy has postponed the Pecan project in the Deepwater Tano Cape Three Points block off Ghana. The BW Energy-led Dussafu joint venture has temporarily postponed the start of the Ruche Phase 1 development offshore Gabon. FAR Ltd. is working with Woodside and other partners in the Sangomar project offshore Senegal to examine how costs can be reduced, expenditure delayed or both and any impact on the timeline to first oil. ExxonMobil has delayed the greenlight on Mozambique’s multi-billion-dollar Rovuma LNG project. The company said it is collaborating with the partners and the government to optimize development plans through improved synergies and assessing opportunities related to the current lower-cost environment. BP and Kosmos Energy are working to defer the 2020 Tortue Phase 1 capital spending for their multi-billion-dollar Greater Tortue Ahmeyim gas-condensate project off Mauritania and Senegal. The Phase 1 timeline is expected to be delayed by 12 months. Shell’s Bonga Southwest, ExxonMobil’s Bosi, Owowo West and Uge-Orso, and Chevron’s Nsiko projects offshore Nigeria

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM17

2005OFF16-26_crisis.indd 17

4/28/20 11:38 AM

• CRISIS MANAGEMENT

Tullow Oil has cut short the drillship Maersk Venturer contract offshore Ghana. (Image courtesy Maersk Drilling)

are likely to be delayed. INPEX’s Abadi project offshore Indonesia, the Limbayong project in Malaysia, Shwe Yee Htun in block A6 off Myanmar, and the Kelidang Cluster in Brunei, are potentially at risk. ExxonMobil said that developing the numerous deepwater discoveries in the Stabroek block offshore Guyana remains an integral part of its long-term growth plans. Operations onboard the FPSO Liza Destiny are unaffected, and the second phase of the Liza field development remains on target for start-up in 2022, with the FPSO Liza Unity currently under construction in Singapore. However, as the company waits for government approval to proceed with a third production vessel for the Payara development, some planned 2020 activities are in the process of being deferred, and this could potentially delay the start of production by between six and 12 months. DRILLING MARKET

The consensus among drilling rig owners and operators is that things will likely get worse before they get better, according to a recent analysis offered by Westwood Global Energy Group’s RigLogix service. This will be especially true if current conditions persist, the report said. Operators are typically cutting planned 2020 capex by 20-30%, and the coronavirus is impacting movements of personnel and 18

2005OFF16-26_crisis.indd 18

equipment/services to and from rigs. This all means the number of idle rigs will soon increase substantially. For rig owners, some of which were slowly inching their way back to profitability, the road to recovery will be longer, and some will be impacted more than others. Terry Childs, head of RigLogix, pointed out many companies are having to face up to debt payments due in 2021. One major rig owner believes nearly every public driller will be in Chapter 11 this year or next. Currently, rig operations in most parts of the world continue to be supported by rig owners, but with strict protocols in place concerning crews, equipment and supplies. But a growing number of drilling rig contractors are saying that they expect to cease drilling soon and warm-stack their rigs, with the impact caused by COVID-19 on logistics cited as the main problem. And should more countries end up adopting no-travel bans or lockdowns, this will only extend the number of idle rigs. RigLogix’s data shows that Africa, Southeast Asia, and the Middle East have the highest dollar amounts at stake, and collectively comprise 50% of the total rig options value. In Southeast Asia and the Middle East, the options are entirely related to jackup contracts, whereas the $136.1 million in the US Gulf of Mexico is mainly for floating rig options. Valaris ($331 million) and Transocean ($195 million) are said WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

to have the highest dollar amounts of options to be exercised and are therefore the most exposed. Most of the nearly 300 drilling programs that currently have 2020 start dates will be delayed, Childs claimed. The planning process for certain drilling programs is continuing, but at a much slower pace. Some contract awards should continue, particularly where drilling is not planned until 2021 or beyond, but it seems probable that the number of contracts finalized over the next few months will be minimal. As of this writing, Valaris has received early termination notices for two rigs offshore Angola. Total is expected to terminate the contract for the drillship VALARIS DS-8, which was expected to end this November. Chevron has terminated the contract for the VALARIS JU-109, which was scheduled to operate until July 2021. As a result, the rig’s contract was expected to end last month. Valaris said it expects to receive additional notices of contract terminations and requests to renegotiate contract day rates and terms considering increased market uncertainty. Tullow Oil has notified Maersk Drilling of the early contract termination for the drillship Maersk Venturer offshore Ghana. The drillship will now likely finish its campaign in June, 20 months ahead of the anticipated termination date. Shelf Drilling and Dubai Petroleum have agreed to amend the contract end dates for the jackups Shelf Drilling Tenacious and Shelf Drilling Mentor from January 2022 to September 2020 and January 2022 to October 2020, respectively. ExxonMobil has notified Shelf Drilling of the early contract termination for the jackup Trident XIV offshore Nigeria. The contract end date has changed from February 2021 to July 2020. ExxonMobil has also notified Borr Drilling Ltd. of the early termination for the jackups Gerd and Groa offshore Nigeria. The rigs were under contracts originally committed until April 2021 and May 2021, respectively. Noble Corp. has warm-stacked the jackups Noble Sam Hartley, Noble Sam Turner, and Noble Hans Deul; cold-stacked the drillship Noble Bully II and the semisubmersible Noble Paul Romano; and will retire the jackup Noble Joe Beall. Saudi Aramco has requested a reduction to the operating day rates for the jackups Noble Scott Marks, Noble Roger Lewis, Noble Joe Knight, and Noble Johnny Whitstine. Drilling contractors could be facing a combined loss of revenue of around $3 billion in 2020 and 2021, according to Rystad Energy. It estimated the total value of agreed contracts over the two years at $30 billion. So far, in the present crisis, six rig years of contracts have been canceled, amounting to around $400 million in value, and more look set to be called off as operators cut capex budgets and delay projects. “More than $22 billion in contract value was wiped off the books as a result of contracts being canceled between 2014 and 2017,” said Rystad head of Offshore Rig Market Services Oddmund Føre. “Now, in the infancy of a new downturn, a market that was only beginning to return to a healthy level of contracting activity, contract volumes and day rates has seen its hopes crushed.”

INTRODUCING A NEW SERIES OF MARINE ELEVATORS

MARINE ELEVATORS Alimak is proud to launch a new innovative Marine Elevator, designed for marine applications. The all new ALIMAK ME is a passenger and freight elevator suitable for an array of marine vessels, built on Alimak’s tried and trusted traction technology. The ALIMAK ME is available in two car sizes, offers capacities of up to 1,600 kg and has superior ride comfort, all without the need for a machine room. Alimak continues to invest in new technologies and concepts to improve the productivity and sustainability of the industry. Contact us at [email protected] for more information.

www.alimak.com MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM19

2005OFF16-26_crisis.indd 19

4/28/20 11:38 AM

• CRISIS MANAGEMENT

EMGS is expected to cold-stack the EM vessel Atlantic Guardian. (Image by Tom Gulbrandsen / courtesy EMGS)

EXPLORATION

This year was slated to be another good year for exploration with about 45 countries launching at least 52 lease rounds, about 60% of them in offshore areas, according to Rystad Energy. However, more than half of the world’s planned licensing rounds are likely to be canceled this year due to the combined effect of the COVID-19 pandemic and low oil prices. New licensed offshore acreage is likely to fall by about 60% compared with 2019 levels. Aatisha Mahajan, Rystad Energy’s senior upstream analyst, said: “The unlikely upcoming lease rounds represent around 54% – a worrisome sign for global exploration. A number of factors together make these rounds unlikely to go ahead, including the oil price drop, a global cut in investments by almost 20%, a lack of skilled manpower due to the COVID-19 pandemic, fiscal regimes that are proving unattractive in the current environment, and a lack of interest among potential participating companies.” According to the analyst, licensing rounds are unlikely to take place in the UK, Ukraine, Romania, Germany, Colombia, Brazil, Ecuador, the Dominican Republic, Thailand, Uzbekistan, Myanmar, the UAE, New Zealand, Ivory Coast, Algeria, Tanzania, Senegal, Somalia, Liberia, Ghana, Equatorial Guinea, Angola, South Sudan, and Nigeria. Licensing rounds in the US, Suriname, Egypt, Russia, and China hang in the balance and are marked as tentative. However, licensing rounds in Malaysia, Trinidad and Tobago, Norway, India, Lebanon, and Canada are likely to go ahead. These countries look well on track to continue their lease rounds as scheduled, although the current industry volatility

could cause slight delays. As for seismic survey contractors, Polarcus has received two project cancellations. One was for an XArray marine seismic acquisition project in the Asia/ Pacific region that was due to start in 2Q 2020. The other was a 3D marine seismic acquisition project offshore West Africa. EMGS canceled a controlled source electromagnetic seismic survey offshore Mauritania and Senegal after BP postponed the project. The company has also decided to cold-stack the Atlantic Guardian. PGS has decided to cold-stack two of its eight currently operated 3D acquisition vessels during the current quarter and warmstack a third in 3Q. Shearwater GeoServices has received two project cancellations. The first includes a short project for Woodside offshore Western Australia that was part of an award announced last November. Reliance Industries canceled a 1,500-sq km (579-sq mi) survey over block KG-UDWHP-2018/1 in the Krishna-Godavari basin offshore India, awarded in January. The Polar Duchess had been due to start the program in the current quarter. The current market will bring many challenges for exploration drilling. Rystad has identified at least nine planned exploration wells in Norway, Brazil, the Bahamas, Guyana, the US, Gambia, and Namibia that would target a combined 7 Bboe are at risk of suspension. Senior upstream analyst Palzor Shenga, said: “Given the prevailing global situation we now foresee that the cumulative

The Center for High-Performance Computing in Houston will help advance the pace of scientific discovery in the fight to stop the virus. (Image courtesy BP)

20

2005OFF16-26_crisis.indd 20

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

CRISIS MANAGEMENT •

discovered volumes by the end of the year could go even below the 2016 level of 8.9 Bboe, which was the decade’s lowest. This will solely depend upon how many key wildcat wells will still see a spinning drill bit in the coming months, as some of them could be either suspended or postponed.” Bahamas Petroleum Co. has re-scheduled drilling of its first exploration well (Perseverance #1) off The Bahamas to mid-October onwards. Oryx Petroleum and FAR Ltd. have postponed exploration wells in the AGC Central license area offshore northwest Africa and The Gambia, respectively. COMBATING CORONAVIRUS

Even as it scales back its E&P campaigns, the industry has been making its expertise and technologies available to help stop the spread of the coronavirus. BP will provide access to its Center for High-Performance Computing (CHPC) in Houston to advance coronavirus research. It houses what the company claims is one of the world’s largest supercomputers for commercial research and processes enormous amounts of data. It has 16.3 petaflops of computing capability, allowing it to process more than 16 million billion calculations per second and complete a problem in an hour that would take a laptop nine years. Petrobras will direct part of its supercomputer processing capacity to helping researchers fight the virus. The Santos Dumont, said to be Latin America’s largest supercomputer, is in the Laboratório Nacional de Computação Científica in Petrópolis, Rio de Janeiro. The other supercomputer is in Salvador, northeast Brazil. The company plans to allocate 60% and 50% of the two supercomputers’ capacity, totalling 3 petaflops. This will be used to accelerate the simulation time so that researchers can achieve results faster. Eni has made its HPC5 supercomputer and molecular modeling capability available for research. Unveiled in February, the HPC5 hybrid architecture is said to make the algorithms for molecular simulation particularly efficient. ExxonMobil and the Global Center for Medical Innovation (GCMI) are collaborating to swiftly re-design and manufacture

reusable personal protection equipment for health care workers. The company said it is applying its experience with and know-how in polymer-based technologies, in combination with GCMI, to facilitate development and expedite third-party production of innovative safety equipment. Shell is part of a consortium that has been developing new face protectors for doctors, made of snorkel masks. These adjusted masks are said to cover the face fully and are connected to a medical filter by a part produced using 3D printers at the Shell Technology Centre Amsterdam. •

MAXIMIZE PRODUCTION. MINIMIZE DOWNTIME. For over fifty years, Nylacast have helped and assisted its customers to enhance project performance, efficiency and safety through the design, manufacture and supply of award-winning materials technology. Manufacturing components from initial chemistry to end product, Nylacast’s full engineering solutions enhance performance and reduce maintenance through their corrosion resistance, low weight and low friction. How can you enhance your projects? Speak to our engineering team today.

www.nylacast.com/energy | [email protected] MAY 2020   OFFSHORE

2005OFF16-26_crisis.indd 21

2005OFF_Nylacst45 1

2/21/20 11:38 8:54 AM 4/28/20 AM

• CRISIS MANAGEMENT

Pandemic, falling prices take steam out of floating production market Sanctioned projects expected to proceed, but with delays DAVID BOGGS, ENERGY MARITIME ASSOCIATES

CONSTRUCTION ACTIVITY

China has become the dominant location for all types of FPSOs, accounting for two-thirds of FPSOs on order. This includes nine newbuilt hulls as well as six conversions from oil tankers. CSIC-Dalian leads the way with five FPSOs for Modec – two newbuilds (Bachalau and Barossa) and three conversions for Petrobras (Marlim I, Buzios V, and Mero I). CSSC-SWS and China Merchants Heavy Industry are each building two FPSO hulls for SBM Offshore (Mero 2, Payara, and two speculative order for future projects). The speculative orders are most likely for expected awards in Brazil and Guyana. The Cosco group has four FPSOs under way in four different yards. The Shanghai and Dalian yards are converting vessels for Modec, while Qidong 22

2005OFF16-26_crisis.indd 22

FLNG

Redeploy

Number of units

Hull type (group) 10

Number of units

and concurrent crash in oil prices, 2020 was on track to be a strong year for new project awards and ongoing construction in the floating production sector. There are currently 23 FPSOs, seven production semisubmersibles and three FLNG units on order. These 33 units are being built or integrated in over 15 main facilities worldwide. Almost 90% of these units are being fabricated in Asia (China, Singapore, Korea). Confidence among contractors, yards and operators was high, but this has changed as the realities of the global pandemic have set in. In our latest models, we are anticipating that few new projects will be sanctioned this year, and that our previous five-year forecast for new orders should be reduced by approximately 20%.

UNITS ON ORDER BY YARD LOCATION (FPSOs, SEMIs, FLNGs)

10

Number of units

PRIOR TO THE COVID-19 pandemic

10

1 SEMI

5

9 FPSO

Conversion

Newbuild

SEMI

FPSO

5 2 1 FPSO 1 SEMI

0

5

6 3

0

0

10

1

2 FLNG 1 FPSO

5

5

1 FLNG

2 SEMI

3 SEMI

3 FPSO

1

1 FPSO

China Singapore Source: Energy Maritime Associates Pte Ltd., April 2020

Korea

Europe

Brazil

TBD

began conversion for Yinson’s Marlim II in 2020. A newbuild for TechnipFMC (BP’s Tortue) is under way in Zhoushan. COOEC is working on four newbuilt units (three FPSOs and one Semi). After taking a pause for a few years, Korean yards have resumed offshore production projects, especially production semis. Currently on order are three production semis, one FLNG, and one FPSO. Daweoo was awarded the hull for Chevron’s Anchor semisubmersible and Hyundai received an order for the King’s Quay production semisubmersible. This is its first large FPS order since the Jangkrik FPU in 2014. Samsung has remained the most active, with orders for the Coral South FLNG, the Mad Dog 2 semi, and a $1.1-billion FPSO award from Reliance India. In Singapore, activity is under way for eight units: four FPSOs, two Semis, and two FLNGs. SBM is carrying out topsides work for some of its hulls built in China that are destined for Guyana. For the Liza 2 FPSO, SBM awarded 22,000 tons of topsides to Dyna-Mac followed by integration by Keppel. The Payara FPSO will likely follow the same model. Bumi Armada had previously done its conversions in Keppel, but selected Sembcorp to convert the Cluster II FPSO for ONGC. The hull for the Karish FPSO is scheduled to arrive in Sembcorp in 2Q 2020 for topsides integration. Sembcorp is also executing two production semis for Shell. In 2019, an LOI was placed for the Whale semi, which is an 80% copy of Vito, which was ordered in 2017. Keppel is executing FLNG projects for Golar. After completing the Hilli Episeyo FLNG, Keppel began work on conversion of the 1976-built Gimi to a 2.5 mtpa FLNG unit for BP’s Greater Tortue field offshore Mauritania and Senegal. Golar and Keppel also have an agreement to convert the 1977-built Gandria, but no physical work has yet begun. Fabrication activity in Norway is under way to upgrade two existing units. In WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

CRISIS MANAGEMENT •

ORDER BACKLOG BY FIELD OPERATORS (FPSOs, SEMIs, FLNGs) Main contractor Modec

Petrobras

SBM

Petrobras

Sembcorp

Petrobras

TechnipFMC

Equinor

TBD Shell

BP

Eni

Samsung

BP

Reliance

Golar LNG

TBD

Eni

Woodside

Santos

ExxonMobil Equinor

Energean

BP

CNOOC

COOEC

Petrobras

Yinson

ONGC

Bumi Armada Hyundai

Murphy

Daewood/Kiewit

Chevron Shell

Fluor

Equinor

Kvaerner

Worley Vaar Energy 0

1

2

3

4

5

6

7

8

9

Number of units Source: Energy Maritime Associates Pte Ltd., April 2020

August 2019, Rosenberg Worley was awarded an EPCI contract to upgrade the 1999-built Jotun A FPSO. The unit will be taken to Worley’s Stavanger yard for 15 months to enable 25 years of additional production on the Balder field. The 1997-built Njord A production semi is being upgraded by Kvaerner in its Stord yard. Cost pressures have resulted in reduced local content requirements for many new projects. Some tenders for Petrobras FPSOs have been revised with lower levels of local content. As a result, yard activity in Brazil has been declining as orders placed in 2010-2013 are completed. SBM mothballed its Brasa yard until at least 2020. The main project currently under way in Brazil is integration of the P-71 topsides by Jurong Aracruz.  LEADING CONTRACTORS

The 33 production units are being executed by 14 different contractors. Half of these are juggling multiple projects, with the other half are working on a single project. Modec is the busiest by far with eight FPSOs on order, including four for Petrobras. Of the eight units, six are conversions and two are newbuilds. Modec will lease and operate the FPSOs for Petrobras and Eni (Amoca), while the FPSOs for Woodside (Sangomar), Santos (Barossa), and Equinor (Bacalhau) to be completed under EPC contracts. SBM has five FPSOs under way, with two for ExxonMobil in Guyana, Mero 2 for Petrobras, and two speculative hulls earmarked for future requirements. SBM will lease these FPSOs, with ExxonMobil expected to take ownership after two years of operation. MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM23

2001OFF_RMyoung 1 2005OFF16-26_crisis.indd 23

12/20/19 10:39 AM 4/28/20 11:38 AM

• CRISIS MANAGEMENT Sembcorp is building three new units (Vito and Whale production semis for Shell and the FPSO hull for Equinor’s Johan Castberg) in addition to integrating the P-71 FPSO in its Brazilian yard. TechnipFMC is the EPCI contractor for three developments (Energean’s Karish FPSO, Eni’s Coral South FLNG, and BP’s Tortue FPSO) and has engaged different yards for each project. Samsung, Golar, and COOEC have two units each. COVID-19 AND THE OIL PRICE CRASH

With oil companies slashing capex across the board, only the financially strongest companies will proceed with new projects. Those that do move forward will only select the biggest and best fields to be developed. We believe that Petrobras and ExxonMobil will continue with plans for multiple, large deepwater FPSOs. However, smaller companies that are not as financially sound are revisiting plans and commitments. Most companies are looking to cancel uncommitted capital and reduce or delay capital that had been committed. One FPSO project has been cancelled to date. In February 2020, Aker Energy issued an LOI for a leased FPSO on its deepwater Pecan field offshore Ghana. However, this was cancelled by Aker Energy on March 31. We anticipate that the development will be revised to reduce costs, and that the project could be re-sanctioned in 2021/22. The tender process had begun under Hess, which sold its stake in the field to Aker Energy in 2018. The unit will be spread moored in 2,400 m of water and is designed to produce 110,000 b/d of oil and 100 MMscf/d of gas. The FPSO was to be leased for 10 years firm, with options for another five years. Going forward, we expect sanctioned developments to proceed, with delays of three to 12 months due to supply chain disruptions and efforts to delay capex. Projects that are still in the engineering phase may experience larger delays, as there is a smaller penalty for delaying a development at that stage. Once construction is under way, delaying the project could prove more costly than keeping to the plan. However, given the need to preserve cash, it is certainly possible that some EPC projects could be stopped mid-way. This is especially true if financing has not been secured for the complete development.

These units are primarily for locations in Brazil, North Sea, and West Africa. Over the next five years, we foresee that Petrobras and other large operators resume ownership of FPSOs rather than sign 15- to 20-year leases. Leased units tend to be conversions, but there has been a recent trend toward newbuilt hulls used by leasing contractors. SBM has placed five orders for its newbuilt Fast4Ward FPSO hulls while Modec has two orders for its M350 FPSO. Both of these concepts are designed to reduce costs through standardization and repeatability. Over the next five years, we forecast that newbuilt FPSOs will account for almost half of all orders. Most of these new hulls will be constructed in China with a few in Korea and Singapore. Conversion work will continue to be dominated by yards in Singapore, Malaysia and China, although European and Middle Eastern yards will also compete, particularly for upgrading existing units. Historically, redeployed units have accounted for around 15% of FPSO orders, but we expect this number to increase to 25% in the next five years. This is due to the large number of available units (30 as of April 2020), as well as the drive for cost effective and fit for purpose solutions. The majority of redeployments will be small to mid-size FPSOs that can be modified and given a life extension for another five to 10 years. In addition, the owners of idle FPSOs are often willing to accept more flexible commercial terms, such as a lower fixed rate with an additional tariff linked to production and/or oil price. FLNG. Orders for one to four FLNGs are possible over the next five years with a total capital cost between $3.5 and $9.0 billion. The orders will range from small liquefaction-only barges to turret-moored gas processing and liquefaction units with capacities up to 3.5 mtpa. The Petronas FLNG 2 was delivered in February 2020. Golar’s second FLNG unit, Gimi, is scheduled to start operations on BP’s Tortue field in 2022. Production semis. Orders for three to six production semis are expected over the next five years with a total capital cost between $2.7 and $4.3 billion. Almost all will be purpose-built hulls ordered by field operators, although some may be financed through leasing or tolling agreements. The required production semis will likely be installed in the Gulf of Mexico, Australia, and West Africa.

FIVE-YEAR FORECAST

The following is our low to mid-case 2020-2024 forecast, which was created pre-COVID 19 and the oil price crash of March 2020. As mentioned earlier, we expect very few projects to be sanctioned for the rest of the year. Therefore, the following forecast should be reduced by approximately 20%. FPSOs. Orders for 40 to 60 FPSOs are expected over the next five years with a total capital cost between $50.3 and $76.3 billion. Some 60% of orders will be leased, 40% owned. Redeployment of existing units will satisfy around 25% of future FPSO requirements. Newbuilt hulls will be used for approximately 40% of all orders. The currently installed FPSO fleet is comprised of around one-third newbuilt units. Over 80% of these newbuilt units are owned by the field operator (mainly MOCs and Petrobras). 24

2005OFF16-26_crisis.indd 24

LOOKING FORWARD

We believe that active projects in the floating production sector will be challenged this year as companies try to preserve cash, deal with supply chain interruptions and push schedules to defer spending. Projects that are under way with secure financing will most likely be completed, although not on the original schedule. Early stage projects may be delayed substantially or cancelled. There had been fears of looming capacity constraints in the supply chain, which should now disappear. When oil prices re-stabilize, we strongly believe that orders for floating production systems will resume, particularly offshore South America and in the Gulf of Mexico. • WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

2004OF

Connecting What’s Needed with What’s Next™

INCREASE YOUR UPTIME From installation to remediation and intervention, our US-flagged, industry-leading MSV Ocean Evolution offers a complete portfolio of advanced technologies that lowers your costs, reduces risk, and delivers the highest level of redundancy.

Connect with what’s next at oceaneering.com/OE Copyright © 2020 Oceaneering International, Inc. All rights reserved.

2004OFF_Oceaneering 2005OFF16-26_crisis.indd1 25

3/11/20 11:38 1:29 PM 4/28/20 AM

• CRISIS MANAGEMENT

Embattled industry goes into crisis management mode Offshore operators to defer more than $42 billion in EPC contracts due to low oil prices, COVID-19 pandemic MARK ADEOSUN, WESTWOOD GLOBAL ENERGY GROUP

for $5.3 billion of offshore EPC contract value. virus pandemic has thrown the global offshore EPC market into The outlook for oil prices looks bleak for the remainder of the a state of flux. 2020 budget cuts so far have been around 25%, but year. Oil consumption fell by an estimated 5 and 10 MMb/d in Febshort-cycle US shale players have been the harder hit, announcing ruary and March, respectively, as Europe and the US joined Asia average capex cuts of 35% and up to 75%. The offshore market in rolling out social lockdown measures to prevent the spread of will see a significant slowdown in planned investments. DiscreCOVID-19. April is expected to be the inflection point for demand tionary E&A budgets have been slashed, rig contracts canceled, destruction with analysts estimating a drop anywhere between and new project sanction15-30 MMb/d. OPEC+ OFFSHORE EPC CONTRACT AWARD OUTLOOK ing is being reassessed. finally agreed to 9.7 MMb/d 80 Announcements of of production cuts on April WGEG Anticipated delays delays and deferrals are an 9 starting from May 1 and Announced delays 70 Revised April 2020 outlook almost daily occurrence. As tapering until April 2022. A Awarded contracts 60 of April 17, major offshore few days later, G20 memprojects that have been bers pledged a further 3.7 50 deferred include Bay du MMb/d of cuts and inter40 Nord (Equinor – Canada), national oil purchases into Scarborough (Woodside – SPRs amounting to 200 30 Australia), Cambo (UK) and MMbbl. However, despite 20 North Field South (Qatargas this unprecedented inter10 – Qatar). These four projects vention, oil markets are alone equate to around $8.5 expected to remain over0 2013 2014 2015 2016 2017 2018 2019 2020 billion of EPC* contracts. supplied for much of 2Q But it is not just oil prices Source: Westwood Global Energy Group with global consumption that are slowing down offonly reaching 90 MMb/d shore field development activity. The Coronavirus pandemic in June/July, according to recent analysis released by the EIA also poses major logistical challenges for large-scale construcand IEA. Westwood has revised its 2020 annual average oil price tion projects that rely on international procurement and signifiassumption to $40/bbl, rising to $50/bbl in 2021. cant imported manpower. This could see delays to the roughly $5 With $5 billion of offshore EPC contracts already awarded billion of already awarded EPC contracts this year such as those year to date, Westwood still anticipates around $25 billion of associated with Woodside’s Sangomar project off Senegal, and offshore EPC contracts to still be awarded, assuming prices Santos’ Barossa gas project off Australia. are around $30 throughout the remainder of 2020. These projAll in all, Westwood now expects up to $30 billion of EPC conects are typically high-priority developments that already have tracts to be awarded in 2020. This is $43 billion below the $68 substantial contracts awarded such as ExxonMobil’s Payara off billion of possible offshore EPC contracts Westwood had idenGuyana, Equinor’s Bacalhau off Brazil, and Shell’s Whale in the tified for 2020 and 37% less than that awarded in 2019. From an Gulf of Mexico. equipment perspective, possible contract awards in 2020 equate After a turbulent five years, the offshore E&P industry is once to 110 subsea trees, six floating production systems, 1,350 km again adopting the brace position and operators and contractors (839 mi) of line pipe, and 1,400 km (870 mi) of flexibles. Besides are treading a fine line between sustaining cashflow and ensurthe delays announced at the time of writing, others at a high ing the health and safety of their workforce. • risk of slipping include Western Gas’ Equus LNG off Australia *Offshore EPC contracts include floating production systems, fixed and high-profile African projects such as Shell’s Bonga Southplatforms, subsea production systems, subsea umbilicals, risers West and BP’s PAJ in the Gulf of Guinea and even Eni’s Mamba and flowlines and pipelines. gas project off Mozambique. These four projects alone account $ Billion

THE SUDDEN DROP in the oil price together with the Corona-

26

2005OFF16-26_crisis.indd 26

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

DRILLING & COMPLETION •

ABS is working with all three major BOP manufacturers, several major operators and drilling contractors in systematic TQ for HP/HT BOP stack and pressure-control equipment. (Image courtesy ABS)

Third-party verification plays key role in HP/HT technology adoption New codes and standards should expedite development HARISH PATEL, ABS

IN THE OFFSHORE ARENA, the journey to develop and pro-

duce oil and gas from high-pressure/high-temperature (HP/HT) fields began more than a decade ago. At that time, project needs were beyond the capability of the available technology. Nor had the applicable codes and standards been developed. The oil and gas industry needed new drilling, evaluation, completion and production equipment that could withstand these harsher environments. The US Department of the Interior’s Bureau of Safety and Environmental Enforcement (BSEE) defines an HP/HT environment as any reservoir that requires completion equipment or well control equipment with an assigned pressure rating greater than 15,000 psi and/or a temperature rating greater than 350°F. These harsher and more extreme drilling environments present a series of challenges to offshore operators, equipment vendors

and service companies. To safely and successfully operate in HP/ HT environments, operators clearly cannot use equipment that would quickly exceed its design capability. Operators need to redesign equipment to accommodate HP/HT conditions as well as carry out advanced planning for modified operational procedures. Since the consequences of failure in offshore HP/HT environments are potentially severe, regulators such as BSEE have added extra rigor in their permitting and approval process for such projects, requiring additional risk studies, design verification, and validation of equipment using an Independent Third Party (I3P) for verification and oversight. BECOMING A REALITY

The oil and gas sector has waited a long time for offshore HP/ HT production to become a day-to-day reality. In some cases,

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM27

2005OFF27-29_abs.indd 27

4/28/20 11:38 AM

• DRILLING & COMPLETION the meter is running on these resources; operators are keen requirement which the industry could follow. BSEE has now to develop them while they retain the rights to do so. With the published three Notice to Lessees (NTLs 2019-G02, 2019-G03 required technologies and regulations now in place, many operand 2019-G04) for HP/HT-related field development requireators with undeveloped offshore HP/HT assets are looking forments for offshore operators. ward to converting them from reservoirs into reserves. To address equipment design challenges, the industry has folBSEE requires the offshore operator to nominate an I3P that lowed the Technology Qualification (TQ) process for each piece will be responsible for evaluating documentation pertaining to of equipment, including both design verification and design valthe new technology, and to generate a report for BSEE’s review idation as separate processes. and approval. These BSEE requirements require the operator, In addition, TQ involves additional areas of concern regarding original equipment manufacturer, and sub-vendors to work with material selection/qualification, and the study of potential failure the I3P and BSEE. modes and risks with their mitigation methods. The materials From the beginning of these developments, ABS acted as the performance criteria in HP/HT drilling environments has not ISP on behalf of numerous offshore operators. Over last five to yet been established due to the limited availability of case histosix years, the classification society has been involved at various ries and the remaining uncertainties related to the composition stages of design verification, validation for various equipment, of the fluids involved at elevated temperatures and pressures. and studies aimed at addressing the risks of HP/HT technology As part of the TQ process, various risk and reliability studies and operations. are required to better identify the hazards and evaluate subseEarly in the development process, the industry identified the quent risks associated with a proposed technology during its iniimportant technical challenges it would need to address early in tial evaluation. These studies must be continuously updated to the cycle. These chalmanage risk over the lenges included a lack TYPICAL RISK AND RELIABILITYSTUDIES FOR HPHT EQUIPMENT/SYSTEM asset lifecycle. of industry codes and standards; lack of regRISK AND ulation; equipment RELIABILITY design; the need for The TQ process newer materials includes evaluating (both elastomer and HP/HT drilling hazmetallic); and the ards using risk assessresources for manuments and reliability facturing and inspecstudies. These studies tion of this much are an essential step larger equipment. in the TQ process to ensure the ability of HAZID - Hazard Identification SIL - Safety Integrity Level CODES AND the novel technology HAZOP - Hazard and Operability RAM - Reliability Availability Analysis STANDARDS aspects in achievFMEA - Failure Mode and Effects Analysis RAM - Reliability, Availability and Maintainability Over the last decade, FMECA - Failure Mode Effects and Criticality Analysis ing their functional the industry has requirements and worked systematigoals. cally to address these challenges and the result is that operators In addition, the risk and reliability studies provide extra verinow have field resources contracted and projects very close to fication that the technology meets the functional requirements, final investment decision. in order to provide an adequate level of safety. The flow chart in To address the challenges of industry codes and standard practhis article presents a typical process for the risk and reliability tices, ABS worked closely with various standards organizations studies when undergoing the technology qualification of HP/HT and has developed HP/HT-related requirements to the standards equipment and system. of the American Petroleum Institute (API) and American Society of Mechanical Engineers (ASME). These standards can now be MATERIALS SELECTION used for design and manufacture of HP/HT drilling equipment. HP/HT conditions add an increased challenge to the process of BSEE and API codes require that HP/HT equipment meet material selection for equipment due to the extreme operating ASME design check methodology. This presents a unique chalconditions. At the beginning of the study of HP/HT operations, lenge for the industry, since these are new methodologies for there were many uncertainties involving the specific environmendesign compared to traditional API methods. ABS quickly noticed tal effects on the material properties due to the lack of field data. that application and understanding of ASME methodology varAs a result of this data scarcity, uncertainty concerning mateied by manufacturer. This variability poses a unique challenge for rial suitability to operate in the HP/HT environment required the I3P, in particular for fatigue and fracture mechanics analysis. manufacturers to make major investments, to qualify their proABS worked closely with BSEE to develop a regulatory posed materials. Various factors having a major bearing on the 28

2005OFF27-29_abs.indd 28

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

DRILLING & COMPLETION •

material selection included but were not limited to: • Temperature • Chemistry • Manufacturing procedure • Material properties • Exposure to environment: seawater, wellbore, drilling and completion fluids, general and localized corrosion • Erosion • Elastomers • Design life • Creep at high temperatures • Material interactions. Over the last 10 years, an increasing proportion of equipment has been designed, built, and tested under the TQ process and been approved by both the independent third party and BSEE. Getting equipment qualified under this extremely challenging development process has been a significant achievement for the industry, but greater challenges are still ahead. The next phase of the HP/HT story is building the equipment and developing the fields themselves. Looking at the bigger picture, the operator needs to address risk related to development of the field. There will be numerous challenges. The equipment qualified for operations are of new design and as a result their reliability is still unknown and will require a great deal of attention during manufacture, testing, and operations. RIG DESIGN AND INTEGRATION

The demands of the HP/HT environment have increased size and weight of equipment and as a result, well control and drilling in particular pose a bigger challenge. Some of the challenges that need to be considered in building out systems for HP/HT operations include: • Structural modification • Higher weight of HP/HT equipment • Handling and lifting systems • Derrick capacity • HP/HT system integration • Blast load • Risk and risk study requirements • Well control • Crew training • Well completion • Equipment design verification and validation for HP/HT • Additional codes and standards compliance. In addition to well control, there will be additional drilling-related challenges that need to be addressed such as kick detection which has a major impact on safety and will require greater attention. Operators need to perform detailed risk studies from a system perspective, considering all operation phases and modes of field development to identify the likely risks and provide mitigation. At present, the regulator has not developed specific requirements for the types of control systems used to manage HP/ HT equipment and systems. These systems will require special attention, with all control systems subject to thorough risk study,

verification and validation. UNLOCKING THE POTENTIAL

The work of the past decade shows that the industry has grasped the challenges of HP/HT operations and has become more comfortable with the requirements from a technical and regulatory perspective. Operators are now able to make final investment decisions on the basis that the R&D work has produced approved technology. The first phase of actual operations will be critical in providing real world data and experience of how the technology performs in this environment, and whether new items need to be considered from a risk or system perspective. Once this begins to happen, the industry can move toward standardization of the technology components and begin to make inroads into managing and reducing the high costs associated with the development of first-generation equipment. • THE AUTHOR

Harish Patel is Senior Technical Advisor, Technology–Drilling and Process, ABS.

Are you sharing this copy of ? November 2019

World Trends and Technology for Offshore Oil and Gas

EUROPEAN

TECHNOLOGY

REPORT

Get Your Own Free Subscription at: www.offshore-mag.com/ subscribe Don’t Stop There - Engage With Us: @Offshoremgzn

@OffshoreMagazine

www.linkedin.com/groups/4542757

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM29 200401OFF_ShareSub14v 1 4/1/20 2:37 PM

2005OFF27-29_abs.indd 29

4/28/20 11:38 AM

• ENGINEERING, CONSTRUCTION & INSTALLATION

The FSRU will receive LNG from ship-to-ship deliveries from LNG carriers (LNGC). The LNGC is berthed to the FSRU, and LNG is transferred between the LNGC and FSRU via their mid-ship manifolds using cryogenic hoses. (All images courtesy Invenergy)

FSRU enables cleaner energy production for El Salvador Energía del Pacífico project calls for region’s first regasification vessel ALBERTO OSORIO LIEBANA, INVENERGY

EMERGING ECONOMIES continue to record sharp increases

in energy demand, and the floating storage regasification unit (FSRU) concept has demonstrated that it can deliver a fast and cost-effective solution. The first FSRU unit was installed in the Gulf of Mexico in 2005, and by mid-2016, 19 more were in operation. According to the publication, “Natural Gas and the Clean Energy Transition,” produced by the International Finance Corp., a sister organization of the World Bank, countries have turned to FSRUs primarily for three reasons: needing LNG for a secure supply of natural gas, using LNG to provide back-up to hydroelectricity, or making up for declining gas reserves. By the end of 2018, there were 40 LNG-importing countries, and almost all new importers are emerging markets that have developed FSRU-based terminals. In some cases, FSRU projects are serving 30

2005OFF30-40_eci.indd 30

the rapidly increasing gas-to-power market in places where there is no access to existing gas infrastructure. POWERING EL SALVADOR

Energía del Pacífico (EDP) is an ambitious project that is introducing a new, clean, and more efficient source of energy to El Salvador, where most power generation today is fueled by heavy fuel oil (HFO). The goal of the EDP development is to expand El Salvador’s energy mix, adding LNG to the current hydropower, geothermal, solar, and HFO sources to provide consistent and reliable energy. The project – which is being executed via a partnership headed by Invenergy and supported by El Salvador-based partners Grupo Calleja, VC Energy de Centroamerica and Quantum Energy – includes an FSRU that will transport regasified LNG via subsea pipeline in the Port of Acajutla to a newly constructed 378-MW WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

ENGINEERING, CONSTRUCTION & INSTALLATION •

thermal power plant onshore. This new facility will meet 30% of El Salvador’s energy demand. A 44-km (27.3-mi) transmission line and substations also are part of this development, which constitutes the largest private investment to date in El Salvador. RISING TO THE CHALLENGE

Laying the groundwork for this technically complex project did not come without challenges. In addition to introducing the first LNG-fueled power plant to El Salvador, this project includes the first FSRU for the region. Regulations needed to be formulated and approved for offshore gas storage as well as for transportation to shore. The scope of the transmission network expansion was another challenge because rights-of-way negotiations had to be finalized before construction could begin. Another challenge was designing the physical components of the project – the supply, storage, and regasification of LNG; the power plant; and a transmission network – all of which required creative technical solutions. INTRODUCING A NOVEL CONCEPT

Initial development concepts included onshore regasification and LNG tanks, a jetty, and an offshore FSRU barge protected by a near-shore cofferdam. Located close to shore in 17-m (56-ft) water depth and exposed to open ocean swell, these options became very expensive and potentially rendered the project unviable. In the end, the most practical and cost-effective solution was a permanently moored FSRU. The team procured the Gallina Moss LNG carrier from Shell and contracted BW LNG to carry out the FSRU conversion. The

FSRU will be moored on the Pacific coast of El Salvador, orientated at approximately 225° to minimize waves on the starboard bow and to position the mooring lines from the stern of the vessel to avoid interfering with pipelines. The vessel position was chosen to minimize interference with other port infrastructure, port traffic and anchorage areas and place it outside the nearby buoy moored oil importation terminal exclusion zone and out of the way of the associated marine terminal operations. The FSRU is designed with 137,000 cubic meters of storage and 280,000,000 scf/d of regasification capacity which is four times the throughput needed to meet the maximum power plant capacity providing a high level of reliability and redundancy. The FSRU will receive LNG from ship-to-ship (STS) deliveries from LNG carriers (LNGC) that will be supported and maneuvered alongside FSRU by tugboats from SAAM Towage. The LNGC is berthed to the FSRU, positioned along the starboard side. LNG is transferred between the LNGC and FSRU via their mid-ship manifolds using cryogenic hoses. The LNG is regasified onboard FSRU, and gas is delivered to shore from the regas manifold on the FSRU via a riser from a port side porch, to a pipeline end termination connecting to a 1,750-m (5,741-ft) subsea pipeline to the onshore power plant. EDP has signed a long-term supply agreement with Shell to supply LNG for the development for around 13 years. DESIGNING THE MOORING SYSTEM

An affordable mooring system that could permanently moor an FSRU for 20 years in 17 m (56 ft) water depth was needed to allow the project to move forward. The main objective was to design a mooring system that provides uninterrupted transfer of gas from

The Energía del Pacífico project is designed to deliver a new, clean and more efficient source of energy to El Salvador.

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM31

2005OFF30-40_eci.indd 31

4/28/20 11:38 AM

• ENGINEERING, CONSTRUCTION & INSTALLATION the FSRU for both operational and extreme conditions. in STS loading conditions as well as additional scenarios to deterThe installation site of the FSRU is south of the hurricane/tropmine the mooring capacity in conditions in which any single comical cyclone belt in an area with relatively benign environmental ponent in the station keeping/mooring system is lost. conditions. However, the vessel would be exposed to seasonal long Further simulations were performed with the most loaded line period swell and possible seismic activity with the potential to creremoved and with the second most loaded line removed. The ate tsunamis. The design environmental conditions considered results from the simulations form the basis for the line-broken most severe scenarios in 100-year wave, wind, and current conline tensions and FSRU offsets. For these single-component failditions and extreme 1,000-year events for tsunamis, including sea ure scenarios, the criterion for peak loads in the remaining anchor level variations as well as current speeds. lines and 100-year extreme condition loads is defined by API RP Nominal 100-year conditions include: 2SK – the industry standard for mooring systems. CAN Systems • 100-year significant wave height of 3.3 m (11 ft) with peak perialso conducted simulation and modeling to validate mooring perods of 12 to 18 sec formance for tsunami conditions. • 100-year wind speeds of 20 m/sec (1 hour mean) The validated mooring arrangement was verified and approved • 100-year surface currents of 1 m/sec. for use on the EDP project by classification society DNV GL. CAN Systems in Norway developed and designed the restricted catenary mooring (RCM) system, a refined spread mooring sysEFFECTING POSITIVE CHANGE tem that comprises a bow mooring system, a mooring restrictor The 378-MW EDP project in El Salvador will not only introduce arrangement and stern hold back lines. The main feature of the a new source of energy to the country, but it will also include the RCM system is a specialized, subsurface connecting plate and development of the first offshore regasification vessel deployed restrictor arrangement that keeps the mooring lines at the bow off the Pacific Coast of Central America – thus demonstrating the and stern close together viability of floating LNG as below keel level, thereby an energy source for landpreventing the mooring based power generation in lines from interfering with the region. the offloading LNGC. EDP is a transformaThe RCM system contional project for El Salvasists of the bow mooring dor and Central America system secured by chains as a whole, introducing a affixed to connecting new source of energy with plates arranged from deck a system that provides the The specialized mooring system will level hangoff with restrictor efficiency and flexibility to include a subsurface connecting plate chains to hold the moorsupplement varying prodesigned to prevent the mooring lines from ing lines together and interfering with the offloading LNGC. duction from solar and away from STS moored hydro generation sources. LNGCs to avoid interferThis added capacity will not ence during offloading. The holdback lines at the stern have a only balance energy availability but will also reduce the environsimilar arrangement as the bow mooring lines. The flexible 14-in. mental impact of energy production. Beyond the added benefits gas export riser is routed from a balcony at the side of the ship to to the energy mix and environment, the project is a catalyst for the pipeline end termination (PLET) on the seabed where it trangrowth for the country. • sitions to the pipeline that carries the gas to shore. The seabed where the FSRU will be moored is relatively sandy THE AUTHOR with the presence of volcanic boulders, which led to the selection Alberto Osorio is Director of Thermal Engineering at Invenergy of the Vryhof Stevshark REX drag embedment anchor for the and Project Director of the Energía del Pacífico mooring system. The REX anchor is designed with spread shanks (EDP) project, currently under development and and a geometry that improves installation, penetration, stability, construction in Acajutla, El Salvador. In this role and strength. The RCM mooring system consists of 84-mm chain he is responsible for leading and coordinating all for the lower anchor legs and 100-mm chain in the top chains project activities including EPC contractor manfor additional corrosion allowance in the splash zone (above the agement. He holds a BS in Civil Engineering from restrictor chain). Mooring legs have variable lengths from 135 m the University of Granada, Spain; a BS in Civil Engi(443 ft) to 235 m (771 ft) to fit within the site restrictions. The Vryneering from the National Autonomous University of Mexico; and hof Stevshark Rex anchors vary in weight from 12.5 tons to 23 tons an MS in Engineering of Roads, Canals and Ports from the Uniincluding extra ballast weight. versity of Granada, Spain. He is a licensed professional engineer Model testing to confirm the RCM design in 100-year wind, in Spain and Mexico. -wave and -current design conditions was carried out by MARIN in the Netherlands. Tests also evaluated LNGC alongside the FSRU 32

2005OFF30-40_eci.indd 32

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

2001OF

BUILDING A BETTER WORLD.

2001OFF_Noia 1 2005OFF30-40_eci.indd 33

12/23/19 10:23 AM AM 4/28/20 11:38

• ENGINEERING, CONSTRUCTION & INSTALLATION

Siemens’ BlueVault energy storage solutions are designed to help ensure continuity of power and to minimize carbon dioxide emissions, with an end goal of a low-emissions platform. (Courtesy Siemens)

Hybrid power plants can help decarbonize offshore drilling rigs and vessels Novel system expected to reduce CO2, NOx emissions on West Mira drilling rig STIG SETTEMSDAL, LARS BARSTAD, AND WOLFGANG VOSS, SIEMENS

THE MARINE and offshore oil and gas industries are coming

under immense pressure to reduce emissions and improve the sustainability of their operations. Considering this, the application of low voltage direct current (DC)-based diesel-electric propulsion systems has gained significant traction. Low voltage DC grids provide numerous advantages when compared to traditional power systems based on alternating current (AC) electrical distribution, including the ability to optimize the loading on diesel gensets by changing the speed according to the load, which reduces specific fuel consumption and associated emissions. Additionally, by reducing loading on the gensets, maintenance intervals can be extended. These benefits are especially relevant for offshore rigs and platform support vessels (PSVs), which have highly variable power demands for drilling, dynamic positioning, and station-keeping. DC power plants also enable easy incorporation of energy storage technologies to create hybrid or all-electric power schemes. 34

2005OFF30-40_eci.indd 34

Siemens delivered the first modern diesel-electric propulsion system to a Norwegian offshore supply vessel in 1996. The company has since implemented similar systems on 300+ marine vessels worldwide. In 2018, another significant milestone was achieved on the West Mira drilling rig in the North Sea. It became the world’s first modern drilling rig to operate a low-emission power plant using lithium-ion batteries. DC POWER GRIDS

The application of DC power grids on offshore marine vessels is not new and can be traced as far back as the 1880s. However, most ships and rigs in operation today use AC power distribution. In these systems, prime movers (typically diesel engines) are connected to a generator, which distributes power to various consumers across the facility, including the propulsion system. Although these systems have been used with success for decades, one inherent disadvantage is that the diesel engine must be kept running at a fixed speed in order to maintain constant frequency and voltage within defined static and dynamic WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

ENGINEERING, CONSTRUCTION & INSTALLATION •

limits. This speed is typically less than the rated output of the engine, which results in partial loading. When this occurs, engine temperature is not high enough to burn all the available fuel. As a result, unburnt fuel passes into the exhaust system, reducing efficiency and increasing specific fuel-oil consumption (SFOC) – both of which lead to higher emissions. Modern low-voltage DC solutions solve this problem by decoupling the power grid from frequency and allowing the diesel engines to be operated at variable (i.e., more optimal) speed, which lowers SFOC. This can yield substantial fuel savings and emissions reductions for PSVs, which only require full power a small proportion of the time they are in operation. In such cases, total fuel reduction on the order of 10-25% can be achieved. NOx emissions reductions as high as 80-85% are also possible due to higher exhaust temperature and more efficient utilization of scrubbers. In addition to the environmental benefits, DC power grids are more flexible and unlike AC grids, do not require a frequency converter for connection to onshore power sources. There are also safety advantages, including rapid fault clearing, which eliminates the possibility of generator synchronization failures and drastically improves blackout recovery time. LEVERAGING ENERGY STORAGE

Another significant benefit of low voltage DC power grids is that they allow for easy incorporation of energy storage technologies to create hybrid (i.e., diesel-electric) or all-electric power schemes. The latter is typically not feasible for large PSVs with high power loads; however, there are many commercial transport vessels in operation today that are fully electric. In 2015, Siemens supplied the power system for the world’s first

electrically powered ferry boat. Named Ampere, the ferry carries passengers and cars across a 6-km (4-mi) crossing between two communities in the Fjord area of Norway. At 80 m (262 ft) long, it is driven by two 450 kilowatt (kW) electric motors powered by lithium-ion batteries. The batteries have a combined capacity of 1,000 kilowatt-hours (kWh). With electricity in the Fjord area being generated exclusively by hydroelectric plants, Ampere cuts emissions by 95% and lifecycle cost by 80% compared to a fuel-powered ferry traveling the same route, which consumes around one million liters of diesel fuel and emits 2,680 tons of CO2 and 37 tons of NOx each year. Similar savings are possible in hybrid power plants by enabling diesel engines to be operated at an optimal combustion level most of the time, which improves fuel utilization. This is the case with the Norwegian offshore construction vessel, Edda Freya. This vessel was commissioned in 2016 and features Siemens’ BlueDrive PlusC DC power grid with 23MW installed power generation and 500kWh battery capacity, coupled with an energy storage solution from Corvus Energy. The hybrid power system enables lower fuel consumption when compared to vessels of similar size – and in turn, a lower emissions profile. In the case of offshore rigs with hybrid power plants that use energy storage, excess power produced from diesel generators or gas turbines could potentially be stored and used to support and improve operation of the primary energy source. Energy could be used for immediate consumption to improve dynamic operation of engines with low response capability in critical situations, as well as for reducing rapid speed changes during normal operation. The application of energy storage for drilling rigs or PSVs ultimately enables companies to fundamentally change the way they

The Norwegian offshore construction vessel Edda Freya was commissioned in 2016 and features Siemens’ BlueDrive PlusC DC power grid, coupled with an energy storage solution from Corvus Energy. (Courtesy Siemens)

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM35

2005OFF30-40_eci.indd 35

4/28/20 11:38 AM

• ENGINEERING, CONSTRUCTION & INSTALLATION operate assets. A summary of the key benefits is outlined below. first lithium-ion battery solution to an offshore drilling rig. The Reduced fuel consumption and lower emissions. As previously West Mira is a sixth-generation, ultra-deepwater semisubmersstated, by integrating low voltage DC power grids with energy storible that will operate in the North Sea’s Nova field, about 120 age, it is possible to optimize the loading on combustion units, km (75 mi) northwest of Bergen, Norway. It will be the world’s such as diesel gensets, which reduces specific fuel consumption first modern drilling rig to operate a low-emissions hybrid (dieand associated emissions. This is particularly beneficial on drilling sel-electric) power plant using Siemens’ BlueVault lithium-ion rigs, where power plants have highly variable power demand for battery technology. drilling, dynamic positioning, and station-keeping. Hybrid power The solution consists of four converter-battery systems (total schemes can also be used to lower transient loads on gensets and 6MW). The battery system is connected to the main switchboard improve dynamic response times of thrusters. using a Clean Grid Converter (CGC) and step-up transformer Improved reliability with better redundancy schemes. Relatively to medium voltage AC connections. The batteries are charged speaking, diesel engines are slow to handle large, abrupt load from the rig’s two diesel-electric generators and used for supchanges. Using batteries or supercapacitors to provide temporary plying power during peak load times. In addition, they serve as power affords facility/vessel operators more flexibility and proback-up to prevent blackout situations and provide power to the vides the opportunity for new redundancy schemes, thus ensuring thrusters in the unlikely event of loss of all running machinery. safety, lower opex and improved uptime throughout operations The installation of the ESS on the West Mira will result in by reducing the number of engines / gensets on the platform. an estimated 42% reduction in the runtime of on-platform dieFor example, in a power plant where there have been traditionsel engines, reducing CO2 emissions by 15% and NOx emissions ally three gas turbines, an operby 12%, which is equivalent to ator could potentially use two annual emissions from about gas turbines with an energy stor10,000 automobiles. age solution attached to it. Additionally, batteries can be used to THE ROAD AHEAD remove the need for load shedThe long-term success of the ding and bridge the gap between offshore oil and gas industry is one engine failing and another predicated on reducing costs starting up. and minimizing environmental Reduced footprint and impacts. Low voltage DC power increased payload. Low voltgrids coupled with energy storage DC grid diesel-electric plants Installation of a hybrid power plant aboard the deepwater age provide a means to achieve incorporating ESS have a smaller semisubmersible West Mira is expected to enable the rig to increase that objective by providing its energy efficiency and lower emissions. (Courtesy DNV GL) footprint than traditional power clean, flexible, and dispatchschemes which use gas turbines. able power. For example, a 6.6kV high-voltage power plant with dual fuel turThe benefits of deploying a hybrid power plant with energy bine-driven generators and one auxiliary diesel generator requires storage in the offshore environment could potentially be realapproximately 120 sq m (1,292 sq ft) of space in the process area. ized on any facility. However, regional economic, environmental, By comparison, a 690V plant with four 4MW diesel generators, and regulatory factors play an important role in cost-effective a main switchboard, integrated variable speed drive (VSD), and deployment. ESS requires zero square meters of space in the process area. This In Norway, for example, the government is incentivizing the increases payload and enables operators and EPCs to rethink industry to reduce emissions. This is one of the main benefits of topsides philosophies, opening the door to more flexible designs. developing and using energy storage solutions for offshore facilities in the North Sea. Other countries, including the USA and PAVING THE WAY FOR RENEWABLES other EU nations, do not heavily incentivize the industry to supThe concept of using renewable sources of energy, such as offport emissions reductions. However, new International Maritime shore wind farms, to provide clean power to offshore oil and gas Organization (IMO) 2020 regulations which came into effect this assets continues to gain traction. But there are still many huryear are making these types of novel power solutions more attracdles to overcome in order to make this a reality, not the least of tive and cost-effective. • which involves finding ways to offset the intermittence and inherent unpredictability of electricity generation from wind. Energy THE AUTHORS storage is an important part of the solution to this problem and Stig Settemsdal is CTO Offshore Solutions with Siemens Energy AS. will play a key role in helping the offshore industry drive toward Lars Barstad is DC Power & Drives Program Lifecycle Manager, decarbonization. also with Siemens Energy AS. In 2018, Siemens took an important step on the way to reducWolfgang Voss is DC Power & Drives Program Lifecycle Manager ing emissions and eventually harnessing renewable sources of with Siemens Energy AG. energy to power oil and gas operations by supplying the world’s 36

2005OFF30-40_eci.indd 36

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

ENGINEERING, CONSTRUCTION & INSTALLATION •

BOKA Vanguard delivers second box-shaped FPSO to Petrobras Faster dry tow cuts long-haul transportation costs JEREMY BECKMAN, EDITOR, EUROPE

EARLIER THIS YEAR, Boskalis’ heavy

transport vessel BOKA Vanguard ( formerly the Dockwise Vanguard) broke its own record for a long-distance dry transport when it delivered the 92,000-metric ton (101,412-ton) box-shaped FPSO P-70 from China to Rio de Janeiro, Brazil. The previous benchmark had been established two years earlier with the transport of the ‘sister’ vessel P-67 to the Lula Norte field in the same region. Offshore spoke to Boskalis’ Bart Heijermans, Member of the Board of Management and Head of the Offshore Energy Division, and Pim Nelemans, Business Unit Director Heavy Marine Transport about the engineering challenges and scheduling benefits of this method of transportation for larger floating production systems.

Dry transport of the FPSO P-67. (All images courtesy Boskalis)

Offshore: Was the P-67 Boskalis’ first FPSO assignment for Petrobras? Boskalis: Transport of the P-67 was executed in 2Q 2018, and it was the first FPSO that Boskalis had delivered to Petrobras: indirectly, we had been involved in other transports and installations previously for the company. The contract scope consisted of providing the vessel in order to load, transport and discharge the FPSO. No major modifications had to be made to the Vanguard in order to transport this unit. The main preparations for the vessel for the voyage comprised devising the cribbing plan and installing large guide frames in order to load the FPSO in a controlled manner. In addition to the transport, Boskalis provided tug assistance until the point of handover of the FPSO to the installation contractor. In recent years we have transported MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM37

2005OFF30-40_eci.indd 37

4/28/20 11:38 AM

• ENGINEERING, CONSTRUCTION & INSTALLATION various types of floaters from the Far East to the western hemisphere, ranging from a ship-shaped FPSO for BP’s Schiehallion redevelopment west of Shetland in 2016, to the circular FPSO for Eni’s Goliat project in the Norwegian Barents Sea, and the Moho Nord FPU offshore Congo for Total in 2017. Whatever the design or shape, the process of taking it onboard BOKA Vanguard is always the same, i.e. submerging the vessel’s deck to a sufficient water depth to accommodate the cargo, which is brought in using tugs and winches. Offshore: Did Petrobras select Boskalis to transport the P-70 for Atapu based on good experiences with the Lula Norte project?

Boskalis: Petrobras chose Boskalis to transport these hulls based on the benefits a dry transport provides. The contract was signed with the Chinese fabricator (COOEC), however Petrobras’ preference for a dry-tow really helped to secure these jobs. These are sister vessels, both of a boxshape designed by Petrobras. P-70 was a couple of hundred metric tons heavier than P-67. But because it was in most other aspects a replica of P-67, a lot of experience could be incorporated from the first job for the second FPSO transport. In addition, both the loading and discharge locations were the same and we were able to use our experiences from the loading/discharge operations for P-67 to optimize planning for the P-70, especially in the use of tugs and the anchor spread to position the FPSO during loading. The overall process was more efficient for the second job, which was one of the biggest cargoes we have ever loaded. This was a first-time role of its type for COOEC. The hulls for the two FPSOs had been awarded and constructed and were transported to Brazil for integration of the topsides. But when the previous oil crisis of 2014-16 hit Petrobras, both hulls had to be taken back to China for the topsides integration. Offshore: How did Boskalis state its case during tendering?

Submerged heavy transport vessel BOKA Vanguard starts loading of the FPSO P-70.

38

2005OFF30-40_eci.indd 38

Boskalis: Our biggest challenge was convincing both Petrobras and COOEC that there were many benefits of a dry tow onboard the Vanguard. For such a long voyage, a conventional wet tow using tugs takes much longer, and around the Cape of Good Hope, where conditions are often severe, the speed becomes much slower. With Petrobras on a very tight schedule for first oil at Lula Norte through the P-67, we convinced them that the Vanguard could carry such a big unit - weighing close to 91,000 metric tons [100,310 tons] - and that our approach could save them up to 50-60 days in sailing time compared to a wet tow. We were contracted to pick up the platform from the shipyard in Qingdao toward the end of 2017, although the WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

ENGINEERING, CONSTRUCTION & INSTALLATION •

Offshore: Was Boskalis’ scope for the two Petrobras jobs limited to delivery of the FPSOs? Boskalis: For the P-67 and P-70 the company was only involved with transportation. But we are keen to offer an expanded ‘one-stop-shop’ service, whether the FPSO is being transported via a dry or wet tow - the latter is something we also do for long-distance transports. Boskalis has a wide-ranging marine installation capability, including anchors, suction piles and mooring lines, that we would like to offer our customers as a way to de-risk their projects. The BOKA Vanguard sets sail from Qingdao, China.

schedule ended up slipping to 2Q 2018. There is always an interplay between us and the yard in these situations, and we always make sure we have sliding windows when we can pick up and deliver the cargo. In the event, the Vanguard completed the voyage within 43 days. Compared to a wet tow this was 40-50 days faster, and it was achieved because the vessel’s average speed is around 11 knots, against 5 to 5.5 knots for a wet tow of a box-shaped FPSO. Offshore: Did BOKA Vanguard undertake any other transport jobs between the two FPSOs for Petrobras, and did it have to undergo a major structural survey following completion of each assignment? Boskalis: Yes, the vessel was involved in multiple voyages during the intervening period including transport of the topside platform structures for the Johan Sverdrup project from South Korea to Norway and the dry-docking of the Carnival Vista cruise vessel in the Bahamas. No major structural survey was needed in either case. Offshore: In terms of preparations, what were the main considerations for the two Petrobras deliveries? Boskalis: The dimensions (length and width) of the two boxed-shape FPSOs including the riser hang of structures were the main challenge. Dealing with these huge sizes and weights of cargo is always stretching the limits of vessel strength, seafastenings design, cribbing, and so on. There was a bit of overhang on the bow and stern of the Vanguard, and both cargoes just fitted in between the vessel’s accommodation block and the casings. This arrangement introduces stresses on a vessel 275 m [902 ft] long while sailing through high waves, so in some places we had below-deck reinforcements. Otherwise, it was mainly a case of managing the ballast carefully. A tailor-made cribbing plan was been designed to make sure the loads from the FPSO were spread over the whole of the vessel and introduced nicely into the vessels’ strong points. One of the reasons Petrobras has been moving slowly away from VLCC-FPSO conversions is that if you look at the tanker’s bow, it’s not optimum because you can’t fit enough processing equipment on it. With a box-shaped FPSO, you can put more modules onto it and therefore more weight. We also have experience of transporting box-shaped floating storage and regasification units from China for Excelerate Energy to Argentina.

Offshore: Did the route around the Cape of Good Hope to southern Brazil waters present any special challenges for the two boxed-shaped FPSO transports? Boskalis: The conditions around the CoG can be a challenge, but this also demonstrates the advantages of a dry tow versus a wet tow. Using a vessel like BOKA Vanguard makes the transport less sensitive to bad weather, because the vessel is faster and as such can change course more quickly. Another advantage is that the vessel can sail closer to shore where there is generally less severe weather than farther out at sea. With all these deepwater project deliveries, predictability is extremely important, but it can be planned. For the dry tow of the P-70, the scheduled delivery date was January 23, and the Vanguard did indeed arrive on time. With a wet tow, the unpredictability of a long voyage is much higher, making it much harder for the client to plan activities subsequent to the vessel’s arrival. Offshore: Has Boskalis made any changes to improve the operation and fuel economy of its transport vessels, or to monitoring motions during transit? Boskalis: Clients always want to compare a wet tow versus a dry tow, in terms of wave impact and slamming effects. We have applied different coatings to reduce

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM39

2005OFF30-40_eci.indd 39

4/28/20 11:38 AM

• ENGINEERING, CONSTRUCTION & INSTALLATION the drag resistance of the hull which in turn leads to lower fuel consumption. Offshore: Finally, does Boskalis see any benefits of earlier engagement with companies during the FPSO project planning phase? Boskalis: We are having some discussions with operators. If the fabricator selects a dry transport very early on, the project can be safer because the forces imposed on the FPSO during a dry tow are less than for a wet tow. And there are savings that can be made if you design the platform for a dry transport. For instance, you can continue to commission the FPSO both during the 40-50-day voyage and subsequently on arrival through first production. This is what we did on Moho Nord for Total, when more than 200 riders were onboard the Vanguard still working to complete the platform.

Arrival of the BOKA Vanguard at the end destination Rio de Janeiro, Brazil.

No commissioning was undertaken during the transports of either the P-67 or the P-70, although riders were onboard both FPSO units in order to execute the preservation scope, ensuring that the systems would start-up on arrival. •

Presentations that travel so you don’t have to. Whether creating your own presentation or sponsoring an Offshore hosted webcast event, you’ll be able to interact with attendees wherever they are from wherever you are. Up to one hour in length, Offshore webcasts provide an interactive environment as if you were in the room. Conduct your own Q&A and polls, personalize your event introduction or wrap up, share videos, and upload white papers for guests to take away.

40

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

Create your interactive environment today. For upcoming sponsorship opportunities contact: David Davis | 713.963.6206 | [email protected]

2005OFF30-40_eci.indd 40 200401Petro_OFFWeb12h 1

4/28/20 11:38 AM 4/1/20 10:59 AM

PRODUCTION OPERATIONS •

In oil and gas, degradation is often dominated by metal loss as a result of corrosion. (Images courtesy Oceaneering)

Quantitative engineering analysis ensures assets remain safe, sustainable Fitness for service enables informed integrity management decisions PIETER VAN DER VYVER, OCEANEERING

AS THE WORLD CONTINUES to demand energy sources,

there is mounting pressure on hydrocarbon producers to find new reserves and extract more from existing assets. In recent years, the industry has made noticeable advancements in recovery techniques, using efficient technology to extend the life of mature fields. As these facilities are extended beyond their original design life and the burden for integrity verification and assurance steadily increases, it is essential to demonstrate continued safety and integrity of ageing assets. Any infrastructure which has been in service for an extended period, whether a pressure vessel, pipeline or machine component, has the potential to degrade until it no longer meets the original design requirements. Therefore, the first step in reviewing redevelopment programs

on ageing fields is to assess the condition of existing infrastructure and its ability to handle current operational loads. If a condition assessment indicates concerns, then further analysis is required to determine the appropriate remedial action to ensure continued, safe operations. FITNESS FOR SERVICE

Fitness for service (FFS) provides a quantitative engineering evaluation to demonstrate the integrity of a component to continue to operate under a specific set of conditions, potentially in the presence of a defect or degradation mechanism. It translates inspection results into quantifiable operational and safety risks, enabling informed integrity management decisions. FFS provides a basis for engineers to distinguish between

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM41

2005OFF41-50_prodOps.indd 41

4/28/20 11:38 AM

• PRODUCTION OPERATIONS acceptable and unacceptable defects and conditions, with principles based on internationally recognized procedures. Although many industry standards address some form of fitness for service assessment, the American Petroleum Institute (API) compiled the best practices into a single, modular assessment standard (API 579-1), which has become the authoritative publication on FFS.

pressure retention could leave operators exposed to a substantial risk. Performing at least basic FFS once the design requirements are no longer satisfied can reduce the risk and provide valuable insight into operating boundaries and future degradation, as well as highlight future requirements for advanced FFS and potential repair. DECODING DEGRADATION

CLEAR UNDERSTANDING OF RISK

The benefits of carrying out FFS assessments are clear: reduced downtime, improved safety, proactive maintenance, all the elements necessary for keeping continued operations as safe, compliant, and efficient as possible. However, the question often arises as to when FFS should and must be applied. Identifying the point of deviation from design intent is often more complex than expected due to the absence of detailed design information, changes in operating environments, and multiple or complex loading scenarios. Therefore, an FFS assessment should be considered as soon as any reported defects exceed the design code limits. For example, defect size exceeding the limit stipulated in the original fabrication quality control standard, metal loss exceeding the design corrosion allowance, material property degradation to below the material specification limits, or exposed to pressures and temperatures outside of original operating boundaries. In oil and gas, degradation is often dominated by metal loss as a result of corrosion. Operators tend to use the minimum allowable wall thickness (MAWT) as a guideline to initiate FFS. For piping components there is also a significant reliance on the API 574 guidelines for minimum structural wall thickness; although these do not consider material grade, span length, operating medium or support arrangements. For example, a 6-in. schedule 40 pipe system has a nominal thickness of 7.11 mm, inclusive of a potential 12.5% thickness under tolerance. If this is specified to have a 1.5 mm corrosion allowance, it results in a minimum design wall thickness of 4.72 mm. The API 574 Default Minimum Structural Thickness for a 6-in. carbon and low-alloy steel pipe is 2.8 mm. If designed for internal pressure of up to 50 bar (725 psi), the MAWT for pressure retention could be 1.21 mm (depending on material grade). If MAWT is used to initiate FFS assessment, there would be no possibility of a successful outcome for this hypothetical scenario, the remaining wall thickness would not satisfy the API 579 Limiting Thickness criteria. Similarly, if the API 574 structural thickness is used for initiating FFS assessment and the pipe system is operating at temperatures above 149°C (300°F), it could experience local thermal pipes stress levels requiring levels well in excess of the structural thickness. For pressure vessels it is even more complex due to local changes in geometry, localized reinforcement zones, major structural discontinuities, and loading complexities. Simply considering components based on thickness for 42

2005OFF41-50_prodOps.indd 42

The first step of assessing any defect is identification of the damage type. The assessment procedures are damage specific, with the API 579-1 standard providing assessment methods for 12 different types of damage. Understanding the damage is also important for predicting the progression and determining the remaining safe, operating life. For each damage type there is a subset of assessment methods, each with specific applicability and limitation criteria that needs considering. There are also different levels of assessment, with progressively increased accuracy and reduced conservatism, accompanied by an increase in required accuracy of input information: • Level 1 - very basic and aimed at quick screening of defects in simple components, normally considering pressure retention only • Level 2 - intermediate, for more complex components with additional loads, increased accuracy enables a reduction in design safety margins • Level 3 - advanced assessment of complex components or severe degradation using detailed mathematical modeling to determine structural stability. COMPONENT CLASSIFICATION

API 579-1 uses an alpha-numeric classification system based on component complexity and loading conditions to determine the appropriate minimum level of assessment: • Type A - is the most basic component, with a simple geometry and equation relating thickness to pressure, and simple loading conditions dominated by pressure. Type A components are perfectly suited for Level 1 assessment • Type B class 1 - have similar basic geometries and thickness equations to Type A components but requires consideration of additional loading conditions due physical size and/or exposure temperature. Type B class 1 components requires level 2 assessment as a minimum • Type B class 2 - are more complex components with thickness interdependencies requiring procedural design evaluation rather than simple thickness. Type B class 2 components requires Level 2 assessment as a minimum • Type C - have the most complex geometries and load distribution normally causing significant local structural or stress discontinuity requiring advanced mathematical analysis by means of the Level 3 assessment. ASSESSMENT IN ACTION

During a routine inspection localized corrosion under insulation (CUI) was detected above a horizontal stiffener ring in a WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

PENcus

Looking for a new way to promote your company? Look no further than PennWell custom publishing We provide high quality work from the leading publisher of the oil & gas industry. Put our expertise to work — use our first class writers, designers and photographers to create your own publication.

Our capabilities include: Custom publications covering significant oil and gas project developments Custom company and technology profiles within Oil & Gas Journal Custom high-level book projects for company milestones or other needs Custom marketing solutions to reach sales and brand awareness objectives Management of a company’s in-house publication Editorial development, management, and ad sales for association publications

Document your company’s growth and history

Foster relationships with both current and new customers

Capture your company’s history and highlight milestones

Custom market and product research

Corporate Profiles

History Books

the world’s natural resource

F. Jay Schempf

Let us do the work for you! Contact Roy Markum, VP Custom Publishing at [email protected], 713.963.6220 for details.

PENcus_petro_160414 1 2005OFF41-50_prodOps.indd 43

4/14/16 4/28/20 10:29 11:38 AM AM

• PRODUCTION OPERATIONS

large vertical vessel. Local metal loss spanned approximately 200 mm upwards from the stiffener ring covering locally the entire circumference of the shell. Accurate thickness measurements were not immediately possible due to surface condition, but estimates suggested only 7 mm remaining of the original 16 mm wall in the worst affected area. Oceaneering was contacted for advice on how to accurately assess the safety and ongoing operability of the equipment. The production facility had capacity for a short-term, partial shutdown of five days for surface preparation and inspection of the damaged vessel. Beyond this, if a longer repair time was necessary, the facility would require a complete shutdown, resulting in substantial financial loss. Primary concern centered around the immediate safety of personnel and equipment, followed by mitigation of any required downtime. FFS would provide valuable information on whether continued operation was safe and achievable, while a suitable repair strategy was investigated, designed, and implemented. The vessel dimensions did not satisfy the requirements for Type A component classification, as additional loading conditions had to be considered. The location of the defect, immediately adjacent to a stiffener also did not satisfy Level 2 applicability requirements, indicating finite element stress analysis would be required to evaluate the local stress and strain distribution. Therefore, advanced FFS (Level 3) was the only suitable assessment. 44

2005OFF41-50_prodOps.indd 44

The company quickly provided a preliminary (Level 2) assessment based on the initial information available, while the operator proceeded with short-term shutdown for surface preparation and detailed inspection. Although not suitable to certify the integrity, the indicative assessment provided a preliminary indication of the potential failure risk and the likelihood of a successful Level 3 assessment outcome, thereby enabling the operator to focus immediate efforts on recommissioning or repair. It also initiated geometric modeling for FEA to expedite the assessment process. The original vessel design included consideration of both internal pressure and vacuum conditions, with normal operation under partial vacuum. The company’s indicative assessment showed that the original design was governed by the vacuum loads, not internal pressure. It anticipated that the vessel would withstand internal pressures well in excess of the maximum design pressure, as well as full vacuum conditions, at the initially reported thickness levels. However, subsequent detailed inspection revealed the metal loss was substantially greater than originally stipulated, with remaining thickness of only 2.5 mm in the worst affected area. This increased the urgency for a Level 3 assessment, and reduced confidence in a successful outcome. To expedite results, a phased approach to assessment load cases was followed. Firstly, combined vacuum, weight, and thermal loads were assessed to demonstrate safety for

©2020_WPC_RA1

Fitness for service translates inspection results into quantifiable operational and safety risks, enabling informed integrity management decisions.

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

2003OF

PRODUCTION OPERATIONS •

continued normal operation. The limit load and buckling assessment indicated overall structural stability and adequate resistance to buckling under full vacuum, with no change in design buckling behavior in the presence of the defect, and no excessive plastic strains. The vessel was deemed fit for continued service for normal operation (partial vacuum) and preparations for recommissioning could commence, with appropriate protections to avoid upset conditions. Secondly, assessment of internal pressure, weight, and thermal loads during upset conditions were assessed. The assessment indicated potential structural instability and excessive plastic strains at pressures exceeding 70% of design maximum pressure, requiring derating of the vessel for potential upset conditions. Finally, assessment of wind loads indicated that vessel integrity would not be compromised at design wind speeds. Oceaneering concluded that due to the low minimum remaining thickness and the required derating for internal pressure, the vessel would not be able to sustain any significant further metal loss. It was deemed fit for short-term continued service, provided it was derated to 70% of its original design maximum pressure, that further degradation was inhibited by temporary corrosion protection, and a suitable repair is designed and implemented in a reasonable timeframe.

PROVEN BENEFITS OF APPLYING FFS

Due to the criticality and urgency associated with FFS, regular progress feedback and preliminary results are critical to enable accurate decision making without the need to wait for a final formal report. For the above example, the company provided the customer with indicative results and the ability to make an informed decision within three days, ensuring equipment could be safely recommissioned, in tandem with seeking repair solutions. In most cases, when FFS is conducted by competent industry advocates, the cost of the assessment is greatly outweighed by the benefits of gaining a more detailed understanding of the damage, potential risk, safe operating boundaries and likelihood of repair. FFS provides valuable insight into the risks associated with component and defect combinations and it supports effective future integrity management. Including FFS technology and assessment capabilities as part of asset management strategy can create substantial operational efficiencies, reduce the likelihood of unplanned and costly repairs. Ensuring that operators are fully aware of what FFS is and why it exists as part of a maintenance program budget can prevent extended shutdowns, enhance recovery, and keep assets safe for longer. •

©2020_WPC_RA1

Tap into the future of energy in Houston, this December. Gain access to game-changing technology and people providing cleaner, smarter, safer, more accessible solutions from 700 expert speakers spanning five days of everything oil and gas.

Learn More and Register Today at WPC2020.COM DEC 6-10, 2020 PRESENTED BY

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM45

2003OFF_WorldPetrolCong 1 2005OFF41-50_prodOps.indd 45

3/5/20 9:25 AM 4/28/20 11:38 AM

• PRODUCTION OPERATIONS

ABB provided integrated safety and automation, electrical and telecommunication systems to the Aasta Hansteen platform offshore Norway. (Photo credit: Roar Lindefjeld and Bo B. Randulff / courtesy Equinor)

Digital technologies leading industry toward autonomous operations Drivers include cost reduction, safety, sustainability MARTIN GRADY, ABB ENERGY INDUSTRIES

AUTONOMOUS OPERATIONS can help make systems safer,

more capable and reliable, as well as more cost-effective. Removing people from the process reduces the scope for errors and improves safety. The journey toward autonomous operations is happening in the energy sector, predominantly now where digital technologies are being used to sense, measure, and control connected assets. DRIVERS FOR AUTONOMOUS OPERATIONS

Drivers for autonomous operations are multi-faceted and can change from operator to operator depending on the exact asset or process to be automated. There are several trends that are driving exploration and production within the energy sector, with the most notable being the rise of digitalization and the need for companies to 46

2005OFF41-50_prodOps.indd 46

ensure their facilities are safer and more efficient. The strongest driver, that can be seen from several directions in the industry, is cost reduction. Since the oil price plummeted in 2014, reducing the capital and operating costs has been a key priority for energy companies. There has always been a focus on safety and the prospect of removing people from the hazards of offshore operations has been a tantalizing prospect for the oil and gas market. Then of course we are increasingly starting to evaluate how we can make operations more sustainable by reducing carbon intensity and improving efficiency. The desire to look at whether there are alternatives to the way things are done currently, with a more sustainable outcome. It is a challenge that the energy industry is actively addressing and will continue to address. However, it is not a journey the industry can jump into; it WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

PRODUCTION OPERATIONS •

is a steady progression rather than a revolution. Commonly it is seen as a five-step process starting with isolated operations that includes connectivity to shore automation and some on-board automation, moving through connected operations where on-platform sensors and servers are added, then integrated operations, remote operations, and finally achieving autonomous operations. An operator must ensure proper measures and competence are in place before moving from one level of autonomy to the next. In a highly regulated industry, input and collective decision making from technology providers like ABB, operators, and regulators is necessary to help the energy sector progress through the steps. REDUCING COSTS

A milestone on the journey toward autonomous operations came last year at the Aasta Hansteen platform. Located in 1,300 m (4,265 ft) of water in the Norwegian Sea and 300 km (186 mi) from land, automation was used to improve start up time and reduce capex costs. Digital solutions driven by the need to reduce costly schedule delays, served as the basis Aasta Hansteen’s fully automated first gas start-up process. To achieve this, a sequence of more than 1,000 manual interventions needed to be reduced to as few as possible. The outcome is a series of buttons that are as simple as starting a car. The teams went through the start-up steps, identified and defined obstacles that needed to be improved, then used the ABB Ability System 800xA simulator to do a virtual start-up of the plant. It was at this stage that a lot of improvements were made for starting up and operating the plant. Through automating much of the process the company managed to reduce a complex set of manual interventions to just 20. It is estimated that this process saved about 40 days in the commissioning phase of the project. SAFETY FIRST WITH PREDICTIVE MAINTENANCE

One of the most significant trends is the drive toward unmanned and autonomous operations of offshore platforms. This increase in the ability of platforms to run themselves, and to move the engineers who monitor them to onshore control rooms has resulted from cost reduction pressures, safety, and increasing environmental concerns. Supplying an offshore crew and flying them back and forth by helicopter is an expensive and inherently dangerous business. Ever more capable automation systems hold out the prospect of running a production facility either with no, or very low, staffing levels – like an old-fashioned lighthouse. One of the primary reasons for a physical presence in offshore and remote facilities is maintenance intervention. For offshore operators, reducing persons on-board by one can justify an investment of about $1 million.¹ Reducing the number of human operators also enhances plant safety by lowering the risk of on-site accidents, whatever the cause. Therefore, refining and reducing maintenance operations

is vitally important and a necessary part of operators’ journey toward autonomy. Traditional maintenance routines are based on service time, not actual requirements, despite the fact 70 to 90% of failures are unrelated to equipment age. The problem with such approaches is that considerable effort is devoted to devices that are working perfectly well. It also does not address the reality where 20% of the equipment tends to cause 80% of the issues. Furthermore, up to 40% of production losses can be attributed to preventable operator errors where, in a typical facility, this could account for 1 to 2% of facility’s total production capacity. The result of excessive maintenance can be that facilities become less reliable due to increased human intervention. Companies that use predictive maintenance, however, are alerted to issues that need addressing based on actual need. Failure modes are remotely monitored using sensors and dedicated analyses are performed to assess the equipment itself and/or its environment for clues to drive maintenance programs. When data is collected from a large amount of identical equipment operating under similar conditions, it becomes possible to build a precise model of that device’s degradation process. By reducing downtime for maintenance operations through a predictive approach, companies can optimize operations and avoid losses. In practice, ABB engineers have been helping Australian natural gas company QCG, now owned by Shell, whose upstream facilities stretch across the Surat basin, where coal-seam gas is gathered and transported along a 540-km (336-mi) underground pipeline, to an LNG plant on Curtis Island near Gladstone. All process facilities including control, safety, telecommunications, CCTV, electrical and maintenance systems are controlled and monitored via the ABB Ability System 800xA distributed control system allowing QCG total visibility of all assets and production. Live data gathered from its onshore unmanned operations, incorporating 24 field compression stations, six central processing plants, two water treatment plants, and two-training LNG export facilities are collated and reviewed at a central Collaborative Operations Centre, where advanced analytics on the health and performance of equipment, systems, and devices using the data can be assessed. TAKING THE SMART APPROACH

For autonomous operations to be successful, open access and the ability to process and analyze huge volumes of data remotely in real time is critical. The company’s advances in this area continued this year in partnership with Norwegian oil and gas producer OKEA. They are using digitalization and automation to achieve substantial productivity gains through agile and dynamic business models. Connectivity and the right infrastructure need to be in place as companies work toward increasingly autonomous operations. In the case of the Draugen platform, high-quality data is streamed to shore, creating a digital twin in real time. Unlike conventional digital twins of such systems, the data stream is transmitted right from the heart of the platform’s control

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM47

2005OFF41-50_prodOps.indd 47

4/28/20 11:38 AM

• PRODUCTION OPERATIONS

ABB and OKEA are using digitalization and automation to achieve substantial productivity gains through agile and dynamic business models. (Courtesy ABB)

system, without any sort of filtering or intermediate storage in databases. This ensures that the context is retained, allowing the users to recognize the data. The new streaming solution is called “Software-as-a-service” (SaaS), a widespread licensing and delivery model.

platform, and to do it in a way that needs less maintenance. Putting all of this on the seabed, by definition, means it must be autonomous. In late 2019, the company reached a key milestone in proving its subsea power technology. By powering pumps and compressors on the seabed, closer to the reservoir, ABB’s subsea power distribution and conversion technology can reduce power consumption. There is potential for substantial energy savings, with reduced carbon emissions using power-from-shore. The company’s subsea power technology can connect to any power source, enabling future integrations with renewable energy, such as wind and hydro power. Moving the entire oil and gas production facility to the seabed is no longer a dream. Remotely operated, increasingly autonomous, subsea facilities powered by lower carbon energy are more likely to become a reality as we transition toward a new energy future. THE PATH AHEAD

OKEA is looking to extend operations from the Draugen field until 2040. (Courtesy ABB)

MAKING OPERATIONS MORE SUSTAINABLE

Although not commonly spoken about in the road to autonomous operations, the role of electrification and the advent of subsea operations is a key step on the way. Power is a big part of the subsea story. There have recently been significant developments in subsea technology that support the drive for autonomous operations which has often been called a ‘race to the bottom.’ Understandably questions are growing about the level of CO2 emissions from oil and gas upstream operations. Generating power with a gas turbine, or diesel generator on the platform is less efficient than power generated onshore which could be from the renewable source. The company is delivering power-from-shore to the Johan Sverdrup field more than 200 km (124 mi) from the onshore grid on the Norwegian west coast. The four platforms that make up the first phase of the development are entirely powered from shore by the HVDC link supplied by ABB. In addition to the environmental benefits of powering the cluster of platforms from shore, the cable solution is safer and more energy-efficient than generating the power offshore using fossil fuels. With a lot of scenarios, the developments in autonomous operation and advances in subsea technology go hand in hand. The effect is to remove equipment from the 48

2005OFF41-50_prodOps.indd 48

Part of the story with autonomous activities is that with a very simple operation it is quite easy to make it autonomous. The challenge is to get that same degree of autonomy, on the complex, high hazard remote facilities in the offshore industry. To a large extent the technology is there, but the industry is only deploying a fraction of the technology that it could. There are several barriers, perceived and real, that reflect operators’ appetite to embark on the five-step cycle fully. Not least is convincing themselves, that their systems are robust enough to get to the final stage. It is a simple fact that if you do not set out to run something autonomously then it probably will not materialize. There must be a clear intent to move to autonomous operations from the outset. This is evidenced by a host of normally unmanned facilities in onshore operations and in the more benign environment of shallow water. Inevitably the decision-making processes involve balancing the cost and benefits against the drivers and the pressures that the operator faces at any time. It also depends on the circumstances in

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

PRODUCTION OPERATIONS •

ABB supplied the HVDC link that powers the Johan Sverdrup field from shore. (Photo credit Ole Jørgen Bratland / courtesy Equinor)

terms of the expected life of the asset and the reserves. There are layers of autonomy and benefits in the early stages and you need to go through these early stages to get more advanced. But that is where everyone must start. You are embarking on a journey that asks, how can we improve this

operation? How can we reduce manning levels? What is it that we need the operators to do and that process of analysis? This will guide you through the five levels and show you how far you need to go at each facility. To date plant operation technology has reached a level of

Time to move ...

Offshore motion? plastics! Strong, safe, light – turnkey e-chain systems for offshore, oil and gas ®

... Protected and guided by strong, safe and light e-chains ● 50 % lighter than steel, maintenance-free, corrosion-free, UV-resistant ● Resistant to seawater, to dirt and sludge, chemicals, extreme temperatures Failsafe cables for the offshore, oil and gas industry ... ● 36 month guarantee for every cable ● Sludge-resistant cables according to NEK606, certified by DNV GL ®

See video references at igus.eu/offshore plastics for longer life

®

igus GmbH Tel. +49-2203-9649-800 [email protected] ®

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM49 2005OFF_Igus 1 4/2/20 8:46 AM

2005OFF41-50_prodOps.indd 49

4/28/20 11:38 AM

• PRODUCTION OPERATIONS

Expand Your Knowledge in Other Industry Areas Our nontechnical series is tailored for energy industry professionals, especially those who lack technical training in an area, providing a basic understanding of the industry in a simple, easy-tounderstand language. Whether you need quick information for a new assignment or just want to expand your knowledge in other areas of the industry, we have your nontechnical needs covered. Best of all, our books and videos ft easily into your budget! Many M Ma any y ttop topics opic op opic icss to c choose hoos ho osse fr from, from m, in including: incl clud cl udin in ng: • Basic petroleum • Drilling • Financial management • Geology & exploration • Natural gas

• Petrochemicals • Petroleum production ! • Pipelines • Well logging

autonomy somewhere between levels 2 and 3. Other technologies will soon follow suit. Robotics, for example, is also taking its first steps in the industry. Advanced robotics exist that are made specifically for the inspection of equipment. These robots can replace the manual inspection of facilities, including inside tanks and pipes, as well as other parts of the platform. ABB works with its customers to provide digital solutions to assist them on the journey toward autonomous operations. From automated processes for plant start-up, through to simulators, remote operations, predictive maintenance and robotic inspection, the company can run data for analytics and enable autonomous engineering, operation and control for local optimizations and/or fleet management. REFERENCE

1. ABB White Paper: Next level oil, gas and chemicals. Harnessing the power of digitalization to thrive in the ‘new normal’ of low oil prices https://new. abb.com/images/librariesprovider94/ whitepaper/digital-oil-gas-and-chemicals.png?sfvrsn=93c3bd12_0 THE AUTHOR

Order Today! Visit our website for complete listings! www.PennWellBooks.com 1-800-752-9764 (toll free)

50 OGIBks23v_Petro_130605 1 2005OFF41-50_prodOps.indd 50

Martin Grady is Vice President and Global Industry Manager, Oil and Gas for ABB Energy Industries. He joined ICI plc in 1984 and held several engineering, production and senior management roles. He moved to ABB in 2001 as part of the acquisition of ICI’s engineering subsidiary, Eutech. Since then, he has held various senior management roles, including general manager of ABB’s Oil, Gas and Petrochemical business in the UK from 2011, which included responsibility for the Caspian region and major projects in Australia. From 2016 until his current appointment, he was a regional manager for ABB’s Oil, Gas and Chemicals business across nine countries. Martin holds a BSc degree in mechanical engineering from the University of Nottingham, UK. He is based in Billingham, UK. • WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020 6/5/13 1:59 PM 4/28/20 11:38 AM

May 2020

World Trends and Technology for Offshore Oil and Gas

FRANCE

SUPPLEMENT

Courtesy TOTAL

2005OFF51-62_FranceSup.indd 51

4/28/20 11:38 AM

• FRANCE

Eiffage Métal expanding offshore wind construction capability WIND FARM INVESTMENTS in Europe

remain heavily focused on the North Sea, but more projects are starting to emerge off France’s shorelines. Engineering and construction group Eiffage Métal is one of the more active players in both sectors. The company’s Belgian subsidiary Smulders has an EPCI contract, under a consortium with DEME, to supply 55 jackets for EDPR/ENGIE’s Moray East wind farm off northeast Scotland. All are three-legged structures, 85 m (279 ft) tall, and each weighing 1,000 metric tons (1,102 tons). Most of Eiffage Métal’s factories across Europe have been involved in the production process, including workshops and yards at Balen, Hoboken and Eilhems in Belgium; Lauterborg in France; and Zary in Poland. Fabrication of the consignment has entered the final phase, with the Wallsend yard on the River Tyne in northeast England handling assembly. According to Arnaud de Villepin, Industrial Division Director at Eiffage Métal, the main challenges have been the scale of the program, due to the large quantity of jackets involved; managing the logistics; the timeframe for delivery; and the industrial approach. Serial production of the jackets is completely different from a conventional offshore platform construction project. “Some specialist oil and gas fabricators are still entering this market, while others have tried but are now exiting because they have not succeeded. Although still relatively new, offshore wind is a more fiercely contested market than oil and gas because the price of the energy, which has to be competitive. The capex is having to be constantly reduced, because the revenue from wind farms compared with oil and gas - at least until the latest oil price crash - is lower, and government subsidies for these projects are also going down. So, this is not an open market: to 52

2005OFF51-62_FranceSup.indd 52

ABOVE: The Wallsend yard is completing assembly of the Moray East wind farm jackets. BELOW: The yard in Senegal is supporting construction of the Greater Tortue Ahmeyim LNG jetty. (Images courtesy Eiffage Métal)

compete, you need to have a big yard, a large installation capacity, and a well-developed supply chain.” Eiffage Métal is also collaborating with DEME on France’s first offshore wind farm, a 480-MW complex located between 12 and 20 km (7.5 and 12 mi) from the port of St. Nazaire on the Guérande peninsula on the west coast. The scope of the EPCI contract, awarded last year, covers the design, fabrication, transportation, and installation of 80 monopiles and transition piece foundations. Construction of the transition pieces is taking place at Smulders’ yard in Antwerp and of the monopiles at SIF in Roermond, the Netherlands. The completed structures will be transported to La Rochelle, south WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

FRANCE •

of St. Nazaire, then installed by DEME between spring 2021 and summer 2022. “The variable seabed soil conditions at the offshore location oblige us to use different installation methods for the monopiles,” de Villepin explained, with a specially-fabricated subsea waves protection device deployed from DEME Offshore’s installation vessel Innovation. “Some of the monopiles can be driven conventionally, while others have to be drilled, or in some cases drilled and driven. The dimensions of the monopiles will be strong enough for each case, this having been taken into account in the engineering phase.” A floating offshore wind farm market is also starting to emerge in Europe, led by Equinor’s Hywind projects offshore Scotland and in the Norwegian North Sea. Eiffage Métal is the EPCI contractor for a pilot floating wind farm project in the French Mediterranean Sea, which involves assembly of a floater designed by Principle Power Inc. Assuming contracts are awarded this year as originally planned, Eiffage Métal would fabricate three floater structures between 2021 and 2022. Each would weigh 2,000 metric tons (2,204 tons) and would operate in water depths of up to 70 m (229 ft), over an area of 3.5 sq km (1.35 sq mi). According to de Villepin, PPI’s concept is based on dynamic ballasting. Eiffage Métal would manufacture parts of the columns and bracings, then assemble these at its yard in Fos-sur-Mer. In addition, the company aims to submit bids for other planned conventional and floating wind farms off Le Tréport and Dunkerque in northern France; another close to the island of Noirmoutier off the west coast; and three offshore floating wind farms, one located off the coast of Britanny and the other two in the Mediterranean Sea. Before the sudden oil price collapse, the company had been monitoring potential oil and gas projects offshore Nigeria suited to its local living-quarter fabrication capability. These included Shell’s shallow-water Block H development and the quarters module for SNEPCO’s deepwater Bonga SW project. Another

development of interest was the proposed Phase 2 of BP/Kosmos Energy’s Greater Tortue Ahmeyim project off Mauritania and Senegal. This could involve an extension to the 1.2-km (0.75-mi) long Phase 1 LNG terminal breakwater jetty that Eiffage GC Marine is currently working on, possibly also a living quarter platform. For Phase 1, the company is using a yard in Senegal and the local supply chain to build the jetty’s 25 supporting concrete caissons, each weighing 16,000 metric tons (17,637 tons). The yard, part of a major development at the Port of Dakar, could also be used to bid for future local offshore projects. •

Eiffage Métal Our name represents more than a hundred years of experience acknowledged worldwide in the field of steel construction and civil engineering structures.

Oil & Gas and Renewable For over fifty years, our plateforms, modules and living quarters enable petroleum companies to explore and exploit petroleum fields. More recently, Eiffage has become the europeen leader of the foundations and the offshore substations for offshore wind farms. Quality - Satefy - Environment These are the essential priorities of our company, based on the expertise, competence, adaptability and dedication of our teams.

www.eiffagemetal.com

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM53

2005OFF_EiffageMetal 1 2005OFF51-62_FranceSup.indd 53

4/23/20 8:38 AM 4/28/20 11:38 AM

• FRANCE

Transfer of LNG ship to ship. (Image courtesy Excelerate Energy)

GTT membranes safeguard LNG on Prelude, Coral South MOST OF THE NEWBUILD FSRU and FLNG vessels either

in operation or under construction worldwide employ GTT’s membrane containment systems for their LNG/LPG cargoes. GTT (Gaztransport & Technigaz) was formed in 1994 following the merger between two French companies Gaztransport and Technigaz, both focused on the LNG shipping business. The company originally developed its membrane technologies to reduce the cost of LNG maritime transport by loading it in bulk in the LNG carrier’s holds. The holds are equipped with cryogenic coatings, or membranes, which contain the LNG at a temperature of -163°C (-261°F) and are sealed with an impermeable layer between the liquid cargo and the vessel’s hull. The design also limits cargo loss through evaporation, or boil-off. GTT’s sustained research and development efforts have led to it designing new solutions for the LNG offshore industry, especially for LNG floating storage and regasification units (FSRU) and floating liquefied natural gas vessels (FLNG). It is important for GTT to develop its technology to meet 54

2005OFF51-62_FranceSup.indd 54

their customer’s requirements which are changing and evolving quickly. More resistant insulation systems are necessary to enable operations offshore (FLNG, FSRU, etc.), in order to obtain more operational flexibility or even to transport gases which are heavier than LNG. In recent years the company introduced its Mark III Flex+ system, engineered to provide improved thermal performance. The design evolution involved the increase of the total thickness of the insulation by 20% compared to the established Mark III Flex system. Another on-going development, which received initial approval from Class in late 2018, is GTT NEXT1, which is designed to achieve a thermal performance equivalent to Mark III Flex while using proven materials and components of NO96 system (the other GTT’s technology). According to the company, over 30 FSRU vessels currently operate globally, with countries new to LNG imports generally favoring the concept as more economic than construction of WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

FRANCE •

full-scale onshore storage. The company claims that all units currently being built will also feature its technologies. As for FLNG ( floating LNG) vessels, only a few are in service: GTT equipped 10 Mark III tanks to Shell’s Prelude, the world’s largest FLNG vessel, and delivered systems for Petronas’ two smaller FLNG vessels operating offshore Malaysia. In addition, GTT technologies will be fitted to the first ultra-deepwater FLNG, under construction by Samsung in South Korea for Eni’s Coral South gas field in 2,000 m (6,562 ft) water depth in Area 4 of Mozambique’s offshore Rovuma basin. The facility is due to start operations from mid-2022, producing 3.4 MM metric tons/yr (3.75 MM tons/yr) of LNG over a designed lifespan of 25 years. GTT has licensed its membrane technology to leading Far East shipyards including Samsung, Hyundai Heavy Industries, DSME, Hudong Zonghua, and Jiangnan. Last December, it also signed a technical assistance and license agreement with Wison Offshore & Marine in China to equip FLNGs, FSRUS, floating storage, regasification and power generation units and other vessels with its membrane containment systems. Teams of the licensed partners are then trained by GTT in the principles of membrane installation. According to GTT’s Commercial Vice President David Colson, the company undertakes most of its R&D at its headquarters in St Rémy-lès-Chevreuse south of Paris. “We study the materials that go into the containment system: all selected materials and developed sub-assemblies then have to be qualified and tested at room and cryogenic temperatures. We then approve suppliers and shipyards for the fabrication process. “Our facilities include a liquid motion/sloshing laboratory with four machines designed to simulate all the different movements of the LNG vessel, with 6 degrees of freedom. We use a 1/40 scale tank, equipped with pressure sensors, to measure at laboratory scale how the liquid in the tank would behave on an offshore vessel or platform. We can then optimize the membrane system design through reinforcements or to propose modifications to the design of the platform itself through changes in the dimensions or adding stability. GTT also works with universities in Europe if we do not have the necessary equipment in-house. “Offshore ship-owners are less concerned about improving thermal performance to reduce the boil-off rate (a prime concern for LNG carriers; matching the boil off to the engine requirements). However, the thermal performance of tanks can be an issue for offshore re-gas applications as a resultant boiloff situation could halt a send-out of an FSRU.” A different approach is required for modeling sloshing on offshore re-gas/FLNG vessels, Colson explained. “With an LNG carrier, you typically operate it up to 10% of tank height when on ballast, and not below 70% on laden voyages. But for offshore vessels, you must be able to maintain the filling height in all conditions. So we must demonstrate to the client that our system can perform sufficiently well to meet all sloshing requirements under the offshore environment.” “At the start of FLNG development, some years ago”, he

continued “GTT’s technology was not viewed as optimal for for such a platform, particularly for withstanding sloshing in FLNG units, and the company had to demonstrate to Shell, amongst others that its membrane containment systems could be adapted to work on the Prelude project offshore northwest Australia. Instead of the conventional arrangement of one row of four to five LNG storage tanks, the design of a central cofferdam solution between two rows of five tanks extending the length of the platform was adopted. This solution reduces the risk of sloshing loads as well as acting as structural support for the platform’s very heavy topside. Other tank solutions, such as spherical tanks, would not afford enough flat deck space to accommodate the topsides.” Other alternative solutions which do feature a flat deck, have been, according to Colson, considered to be more expensive. “In a scenario of two banks of normally dimensioned 50-m (164-ft) wide tanks, there would be a potential for quite an important amount of liquid motion at certain filling levels. But if the tank breadths are halved, it reduces the sloshing effect significantly. In addition, FLNG vessels are massive, stable structures that do not move excessively in water compared to normal vessels.” The redundancy built into the design means that nine of the tanks can continue to operate normally while the other tank is taken off line to be emptied of gas. The process entails visual inspections and checks for tightness, with maintenance and repairs, if required, performed on site. “If there is an issue at the higher part of the tank,” Colson said, “our team may have to erect scaffolding in the tank on site, because the vessel cannot be brought ashore at any time for dry-docking.” “Our membrane systems on all our clients’ vessels are constantly monitored for any potential leak in the tank or barrier. We also conduct visual checks to verify that there are no objects in the tank which could become loose. A bolt which has become unbolted may lead to damage under sloshing in operation.” GTT has also been awarded a contract with Shell to maintain the tanks on Prelude on a five-yearly basis. For LNGC’s, FSRUs and FLNGs, GTT subsidiary Cryovision provides different types of membrane test services such TAMI (Thermal Assessment of Membrane Integrity) for testing the tightness of tank secondary barrier as well as other tightness tests (Primary barrier, Global tank test). The company may also use in-tank equipment to facilitate testing such as: MOON (Motorized BalloON) operates in similar fashion to a drone. In this case, a balloon is dispatched to inspect a tank’s primary membrane. TIBIA (Tank Inspection by Integrated Arm) is an arm-like tool developed by GTT that can roam around tanks on FSRUs and FLNGs and perform maintenance of the primary membranes. GTT continues to offer innovative services for monitoring and maintaining the membrane tanks offshore. Recently GTT North America signed a five-year global technical services agreement with Excelerate Energy to support maintenance of nine FSRUs equipped with NO96 membrane technology. •

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM55

2005OFF51-62_FranceSup.indd 55

4/28/20 11:38 AM

• FRANCE

Floating offshore wind tower. (Image courtesy DORIS Group)

DORIS maintaining focus on renewables, lower-cost production FRANÇOIS THIÉBAUD, DORIS GROUP

AGAIN, ANOTHER CRISIS for the offshore industry, or rather, two

crises, with COVID-19 and the oil price slump. However, DORIS is confident it can adjust to these unexpected market conditions, as it has done over the past 55 years, thanks to its diversified activity and R&D investments. Despite the recent developments, climate change remains a worldwide concern, and the reduction of greenhouse gases (GHG) in oil and gas production is now part of the group’s design remit, from conceptual to detailed design stages. One current project involves reducing GHG generation onboard four FPSOs off West Africa: DORIS is preparing recommendations to that effect. Another global priority is the replacement of hydrocarbons with other sources of energy. The group is participating in various initiatives, including carbon-free generation of hydrogen. Its UK subsidiary ODE is collaborating in the DOLPHYN project (Deepwater Offshore Local Production of HYdrogeN) to design the process equipment, electrical system, and overall technical safety requirements for the production of hydrogen from seawater. The facilities will be installed on a semisubmersible, supporting a wind turbine to provide carbon-free energy, with the hydrogen 56

2005OFF51-62_FranceSup.indd 56

piped to shore. Preliminary studies are complete and in February, the UK government launched the project’s next phase which involves developing a 2-MW prototype. Later, with a full-scale unit, a single offshore 10-MW floating wind turbine should be able to produce sufficient low-carbon hydrogen to heat around 2,500 homes, fuel over 120-240 buses, or run eight to 12 trains. OFFSHORE WIND FARMS

Renewables are also part of the solution. DORIS has developed two innovative concepts for floating wind, with the Nerewind semisubmersible suitable for deeper water, and the Articulated Wind Column (AWC) for intermediate depths. The group’s first project in this field dates back to 2002 with a pre-front-end engineering design (pre-FEED) study for a wind farm offshore Zeebrugge, Belgium. Since then, the group has provided engineering and associated services to developers for projects such as Ormonde, Scroby Sands, and Wikinger. The experience led the group to expand this service to Asia, with an office in Taiwan in 2016, followed by activities in Japan, Korea, Vietnam, and Boston, and prospects for further developments. WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

2005OF

FRANCE •

FACILITY LIFE EXTENSIONS

DIGITALIZATION

At the same time, the group remains active in more traditional oil and gas activities. One of the industry’s main challenges today is extending the lives of existing facilities that have reached their originally designed lifespan of 20-25 years, but which can still produce available reserves. DORIS is assisting several initiatives in Africa and the Middle East to assess the remaining life of equipment and structures and to recommend life extension modifications. Cost reduction remains the primary driver of most operators, and much more so in periods of depressed oil prices. One significant lever is the reduction of opex by converting facilities that were designed only a few years ago to operate manned to unmanned service. Through ODE, the group held operation and maintenance contracts for several platforms in the southern North Sea for over 15 years. It is now Duty Holder of two greenfield developments, and has expanded its Aberdeen office to target central North Sea operations. One idea is to design facilities with a once-yearly visit specification, such as the 2018 design the group produced for a wellhead platform offshore Argentina. New facilities can also be designed with disrupting technology and commercial choices, such as small-scale FLNG development in which DORIS is presently involved for various West Africa prospects.

Finally, and most importantly, the industry is finally catching up on the digitalization journey several years after the automobile, aerospace, and other sectors. Digitalization leverages huge amounts of data that oil and gas operators have compiled over the years in their operations through sophisticated instrumentation packages and control systems. Yet much of this data is either used ‘live’ or more often, not at all. It is rarely used through statistical analyses because the data is stored in multiple databases (PI, SAP, SharePoint, EMDS, etc.) with no linkage between them. But when assembled in a single location, the data can be mined to reduce opex and capex by decreasing design margins and potentially increasing revenues though production improvements. DORIS is developing solutions for digital twins with a view to producing prescriptive analytics for operators. This initiative started several years ago with ‘intelligent 3D-models,’ and is now moving into the pilot phase for actual greenfield and brownfield facilities. The group has also provided several digitalization proof of concepts to oil and gas clients from California to Africa to the North Sea. The present crises will change many industry activities to a new ‘normal,’ but DORIS aims to prepared for the next wave of upheavals via continued R&D initiatives and the contributions of its worldwide subsidiaries. •

ENGINEERING FOR

ENERGY CHALLENGING CONVENTIONAL THINKING IN TODAY’S COST DRIVEN MARKET

DORIS GROUP 58 A, rue du Dessous des Berges - 75013 PARIS - FRANCE Phone : +33 1 44 06 10 00 - Fax : +33 1 45 70 87 38 MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM57 www.dorisgroup.com

2005OFF_DorisGroup 1 2005OFF51-62_FranceSup.indd 57

4/20/20 11:38 8:22 AM 4/28/20 AM

• FRANCE

iXblue develops second Gaps USBL system for shallower-water subsea tasks NAVIGATION/POSITIONING specialist iXblue has expanded

its Gaps range of ultra-short baseline (USBL) systems for subsea operations support. The newly developed Gaps M5 is an omni-directional, medium-frequency USBL acoustic positioning system which like the established Gaps M7 does not require on-the-field calibration. It is designed for positioning and vertical/horizontal tracking of subsea infrastructure, from shallow-water to medium water depths (down to 1,000 m/3,281 ft), with a claimed accuracy of better than 0.5% of the slant range up to 995 m (3,264 ft). The motion sensor embedded within the system is a free-ofexport Octans Nano attitude and heading reference system, and is based on the company’s FOG (Fiber Optic Gyroscope) technology, said to ensure stable heading roll and pitch compensation and a true north reference. Gaps M5, with a weight of 14 kg, is smaller and more compact than Gaps M7 (17 kg), features that are said to further facilitate installation and operation. As with Gaps M7, after installing and turning on the system, it is ready for the user to operate. According to iXblue, when positioning a vessel at a distance of 500 m (1,640 ft), Gaps M5 is accurate up to a maximum of 2.5 m (8.2 ft), and the maximum operating range can be achieved even in noisy conditions. The export-free capability is said to be particularly advantageous for operations in strictly regulated offshore locations. Subsea applications range from tracking of divers, AUVs, ROVs and tow fish tracking to dynamic positioning, long baseline transponder ‘box-in’, subsea structure installation and pipelaying. Gaps M5 retains the main design features of the M7, but with shorter legs and an overall height around 12 cm (4.7 in.) lower. Its 3D four-hydrophone antenna has different leg lengths to enhance horizontal tracking and the acoustic capability is said to provide maximum aperture, allowing up to 200° omni-directional coverage without the need to tilt the antenna. This is claimed to be a major advantage in shallow water and horizontal tracking conditions, especially when multiple vehicles must be simultaneously located at 360°. The system can also be used for dynamic positioning as an acoustic transceiver, with one beacon in USBL mode or three or more beacons in LBL mode. Since iXblue introduced Gaps M7 as the first pre-calibrated USBL system in 2005, over 300 have been deployed worldwide. Gaps M7 remains the best option for more complex survey requirements such as subsea multi-beam and laser scan positioning, as it provides an accuracy that can reach 0.06% of the slant range up to 4,000 m (13,123 ft). According to Gary Bagot, iXblue’s Business Developer, Subsea Navigation & Energy Market, many of the company’s clients have confirmed this accuracy at a distance of 58

2005OFF51-62_FranceSup.indd 58

Gaps M5 under deployment. (Images courtesy iXblue)

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

FRANCE •

thousands of meters from the target. One application that benefits from this capability, he explained, is laying a pipeline in a field congested by structures and geohazards. “If the USBL is sufficiently accurate, it can be used to narrow down the optimum corridor for the pipeline. And therefore, unlock shorter safe pipeline routings and decrease sleepers dimensions.” Gaps M7’s USBL antenna and Phins Fiber-Optic-based inertial navigation system (the latter pre-calibrated at the company’s factory) are combined within the same housing. Its acoustic capabilities, which include wideband signals, are said to maximize performance even in the most problematic conditions, and the 3D acoustic array allows for tracking even at angles above horizontal. Offshore applications range from structure placement to ROV navigation, AUV operations, towfish tracking, cable/pipelay support, touchdown positioning, mattress placement, plough/trenching positioning, rig and anchor moves, riser positioning and OBC node placements for 4D seismic surveys. Both Gaps M7 and Gaps M5 are based on an open architecture with serial and Ethernet connectivity and Web control command, and according to iXblue both are also compatible with third-party equipment. Even if they operate on the same medium-frequency bandwidth, the two systems can be deployed simultaneously, Bagot added, typically as permanent and temporary subsea positioning systems. Application wise, the new Gaps M5 is perfectly suited for inshore applications, while Gaps M7 can cover all applications, from inshore to offshore, with ultimate performance. Among recent applications was a pipelay project where the lay barge already had a permanent USBL system onboard. “However, when the laying operation started, this could not provide the client’s requested accuracy. In this case, the situation was resolved by installing a Gaps on the vessel’s stinger. “For another project, in shallow water depths, the client wanted to install pipes in 20-m [65.6-ft] sections, one after the other. The operation, involving three divers, and an inspection ROV, was quite challenging

in terms of providing an overview of the situation - but the Gaps M7 was able to do it in such noisy environment. In addition, two transponders were installed on each pipe section allowing complete monitoring through iXblue’s Delph Roadmap Software’s 3D view, delivered with every product in the Gaps Series. “Another client used a Gaps M7 in combination with our 2D/3D visualization software on an offshore construction vessel to ensure safe placement of the structure on the seafloor.” •

Mini and mighty. OUR USBL FAMILY IS GROWING

NEW Gaps M5

Export-free and omnidirectional USBL system operating from the surface to medium water depths (995m).

MAY 2020   OFFSHORE

2005OFF51-62_FranceSup.indd 59

2005OFF_IxBlue 1

4/9/20 11:38 9:19 AM 4/28/20 AM

• FRANCE

Class survey plays its part in the conversion process. (All images courtesy Bureau Veritas)

Re-purposing gas carriers for offshore re-gas, storage roles JULIEN BOULLAND, BUREAU VERITAS

CONVERSION IS OFFERING a second life to gas carriers, but

repurposing these vessels as floating storage and regasification units (FSRUs) and floating storage units (FSUs) comes with technical and operational challenges for owners. The liquefied natural gas (LNG) market is growing as more countries turn to gas to meet their rising energy needs. In parallel, there has been an increase in the number of gas carriers providing LNG transportation and distribution. In recent years, numerous laid-up ships have become available for varying reasons: they may be nearing the end of their design lives, or may be outside of modern specifications, phased out, or off-charter for the market. Owners are seeking to repurpose their vessels and extend their lifecycle by converting them to FSRUs and FSUs 60

2005OFF51-62_FranceSup.indd 60

as more countries see the capex and opex-reducing potential these units bring compared to onshore LNG terminals. Furthermore, because they offer greater flexibility and are less infrastructure intensive, FSRUs can provide an intermediate solution (the time charter can be less than five years), during the length of time it takes to develop a permanent onshore solution. As the FSRU sector is still relatively new and developing, relationships between countries that require LNG and the FSRU providers can be complex. There are several key points that FSRU and FSU developers should consider to ensure their vessels are safe, fully compliant with environmental regulations, and appropriate for market demands. Regulatory questions at both flag state and class levels are a WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

FRANCE •

major consideration for FSRU/FSU conversions. Depending on the intended modifications, project specifications and conversion work, different systems may be decommissioned, removed, modified, or added. Project developers must account for all statutory and classification concerns, including International Marine Organization regulations such as the International Convention for the Safety of Life at Sea (SOLAS), the International Convention for the Prevention of Pollution from Ships (MARPOL) and the IGC Code, which ensure that vessels comply with safety and environmental requirements. Coastal state and local port authorities may also need to be consulted, and their requirements taken into consideration. Technical challenges abound. Gas carriers may need to undergo modifications to their power generation systems (e.g. boilers, generators), power distribution, propulsion, LNG cargo tanks, systems for cargo, cargo control, mooring, handling cranes and others. Owners looking to remove certain equipment must assess how this can be done safely, and under what conditions. From reviewing structural elements, to upgrading cargo containment systems, to adding new equipment, the list of technical challenges is considerable for conversion to FSRUs and FSUs. Compliance with local environmental regulations also needs to be considered. In many cases, an FSRU or FSU will be in a stationary position close to shore and potentially near to other marine users such as fishing vessels. FSRUs use considerable amounts of seawater to heat up the LNG during regasification and the change in temperature of the discharged water is considerable. Therefore, it is essential that the vessel operators are fully aware of and compliant with local regulations on water emissions as well as others relating to environmental issues such as air quality and noise. Another key question is how to keep a vessel on location for an extended period, potentially exceeding the typical five-year dry-docking regime. Project developers frequently seek a ‘no-dry dock’ approach,

ABOVE: Comprehensive structural analysis ensures fitness of candidate ships for conversion. BELOW: Thorough thickness measurement of the hull.

which has implications for conversion work on hull structure and equipment. Finally, there is the issue of cost, as owners seek to limit the price of on-site maintenance and minimize opex for their vessel’s extended lifecycle. HOW CLASSIFICATION SOCIETIES CAN HELP

Classification societies can perform a range of analyses for gas carrier hull structures, cargo tanks, machinery, mooring systems, and more. Evaluation of hydrodynamics, design loads and scantling data, as well as structural assessments, offer owners a clear picture of their vessel’s condition, and allow classification societies to assist in developing a full inspection program. However, it is important that the product developer engages and involves a classification society at the earliest opportunity in a project, and that the relationship is maintained throughout the design and build process. The classification society will be able to provide counsel and guidance from a regulatory perspective from the outset, to highlight potential challenges and how these may be overcome. By helping the product developer to avoid costly errors in regulation compliance and design early on, and by providing advice and expertise support along the way, the classification society can be seen as an enabler for the development of a safe, environmentally responsible, and cost-effective asset. •

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM61

2005OFF51-62_FranceSup.indd 61

4/28/20 11:38 AM

Les “Habitués” de OTC

1 2005OFFFrenchSup.indd 62 2005OFF51-62_FranceSup.indd 62

4/23/20 10:29 AM 4/28/20 11:38 AM

EQUIPMENT & ENGINEERING •

Air filtration system helps improve gas turbine performance on BP’s Clair platform GRAEME TURNBULL, AAF INTERNATIONAL

THE OFFSHORE oil and gas industry

has long focused on the importance of maintaining gas turbine engines, but a critical issue that often escapes attention is air filtration systems. Located at the front of the gas turbine, these systems can enhance gas turbine performance and availability, while promoting better compressor cleanliness and long-term part integrity. As seen on BP’s Clair platform in the North Sea, optimum air filtration systems can unlock considerable financial, operational, and environmental benefits. Gas turbines are essential to the production of oil and gas, running both mechanical drive and power generation applications on offshore platforms. However, they are repeatedly exposed to the most arduous atmospheric conditions. Air in the offshore environment contains numerous airborne particles that have the potential to harm gas turbines. These include water droplets, sea salt aerosols, salt in solution and sub-micron particulate, as well as industrial airborne particulates from burnt and unburnt hydrocarbons, drilling activities, mud burn, and grit blast. Cooling passages on the turbine blades in the hot end of the gas turbine must remain free of contamination and clear of blockages. If they are not suitably protected from the elements offshore and become blocked this will result in fatigue and cracking, causing significant damage, and incurring high costs and downtime for repair. When running with sour fuel, the components within the turbine section are also exposed to accelerated hot end corrosion. This phenomenon results from the combustion of sour fuel gas, which is rich in hydrogen sulphide and reacts with the salt from the intake air.

BP piloted N-hance on the Clair platform. (Courtesy AAF International)

LIMITED PROTECTION

When it comes to protecting gas turbines from offshore air, and all that is contained within, air filtration systems play a critical role, operating on the front line of defense. Currently, around 85% of offshore gas turbines are protected by small high velocity filtration systems that use low efficiency filter bags. These only provide protection against coarse particles, and fail to capture sub-micron particles offshore. It is worth noting that the air quality at platform level is significantly different to sea level. At the height of an offshore platform the majority of particles in the air are sub-micron in size. The vast majority of particles of this size will pass through high velocity filter bags, in fact only 5% will be captured. This can lead to lost production revenue, unplanned gas turbine shutdowns, reduced component and engine life, premature engine failure, and low turbine compression efficiency and high CO2 emissions; especially unwanted given today’s current market dynamics and the low price of oil. By contrast, high efficiency particulate air filter (EPA) 12 technology captures 99.95% of sub-micron particles. This protects and enhances the performance of expensive gas turbine components. As operators have become aware of the benefits of EPA E12 air intake filtration, there has been a push to upgrade existing high velocity units installed offshore. However, traditional EPA E12 filtration technologies - with much larger equipment envelopes - have necessitated that the air intake housing is replaced in its entirety. This increases foundation loads and incurs significant costs and down time. However, there is another route, using a new EPA E12 system which provides all the associated benefits of EPA E12 air filtration, but can be quickly and seamlessly installed within the existing high velocity air intake filtration system. BP’S CLAIR PLATFORM

BP’s Clair platform operates three Titan 130 gas turbines (GTs 1, 2 and 3) employed in power generation application to provide power to the asset. Each gas turbine was experiencing compressor blade fouling, corrosion and erosion, as well as

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM63

2005OFF63-68_ee.indd 63

4/29/20 11:39 AM

• EQUIPMENT & ENGINEERING turbine section hot gas path corrosion. Operationally, this resulted in poor engine reliability, reduced availability and premature engine overhaul and/or replacement. All of which severely impeded the long-term strategic planning for the platform for both production and maintenance. Eventually, the poor filtration provided by the high velocity bag system resulted in a catastrophic failure of GT2 after 12,000 operating hours, which equated to only one-third of the engine design life. The root cause of the failure being inlet guide vane seizure and in turn compressor section imbalance and ultimately blade liberation. This resulted in irreparable damage and a new replacement engine was required, incurring unplanned long-term shutdown and significant unbudgeted costs. BP was aware that AAF International was in the final stages of developing a new EPA E12 high velocity filtration solution. Critically this new design could be installed within an existing high velocity housing with no penalty in differential pressure (dP), therefore negating the need for a larger housing replacement. Because of this failure on GT2, BP was expediting the GT original equipment manufacturer (OEM) for fasttrack delivery of a replacement engine and approached AAF to determine if this new technology (N-hance) could

TAKE THE PLUNGE! Deepwater Petroleum Exploration & Production is the most comprehensive and authoritative text available on the business, engineering, science, and technology Best-Selling of this multibillion-dollar 2nd Edition! industry. NEW TO THE SECOND EDITION:

372 Pages/Hardcover/2011 New chapters on geology and geophysics, rigs, and service vehicles • Greater coverage of engineering and scientifc schemes used in deepwater • Final chapter presents the latest technology used in the “third wave” of industry evolution •

ORDER TODAY! VISIT WWW.PENNWELLBOOKS.COM OR CALL 800-752-9764! FIND US:

be urgently deployed in a field trial as a technology collaboration initiative. Thanks to a longstanding relationship between the two companies, BP was able and confident to pilot AAF’s N-hance technology. The N-hance filters and conversion parts were delivered to the operator within five weeks, and commissioned along with the new GT2 engine on the Clair platform in February 2017. The pilot delivered excellent results. There was an increase in engine availability resulting from a reduction in unplanned downtime and shortened shutdown periods. There was also a decrease in CO2 emissions improving sustainability, as well as retained power output (compressor efficiency) and heat rate. Critically, BP has also eliminated the risk of potential GT failure due to corrosion at just one-third of design life. Commenting on the project, BP’s asset team said: “The upgrade project has enabled improved reliability, cost savings and will feed into the reformation of outdated air filtration standards as well as playing a part in helping to achieve offshore asset efficiency of 90%.” NEW MECHANISMS TO DRIVE TECHNOLOGY ADOPTION

EPA E12 air filtration is currently available within low velocity systems and already in use on assets owned by super majors. However, few operators are aware that EPA E12 filtration is now supported within high velocity systems. This is partially due to the fact there needs to be significantly more support for the widespread adoption of the technology used on the Clair platform. This includes the adoption of EPA E12:EN1822 standards within OEM offshore turbine specifications to extend the life of all new gas turbines operating in the offshore environment and provide the operator with the added benefit of a small and lightweight filter housing in comparison to the traditional low velocity large E12 filter housings. Operators also have their part to play and need to question why they are repeatedly offered low efficiency filter bags for high velocity systems. The accepted norms of poor air filtration in offshore environments can be redefined, and operators can benefit from the improved technology. Immediately, the result will be to eliminate frequent water washing of the gas turbine, increasing production efficiency while at the same time providing a longer operational life of the gas turbine. Furthermore, a sustained effort is needed to communicate the evolution in filtration performance and demonstrate the findings, which support the use of new proven EPA E12 technologies. Collectively if adopted by the offshore oil and gas industry, these measures trigger a new “front end” approach to gas turbine reliability and availability, which is beginning to gain momentum in some areas of the sector. With cost control and environmental improvements, such as CO₂ reduction now more critical than ever, taking the necessary steps to address current technology adoption should be delayed no further. •

64 Dpep14v_petro_150723 1 2005OFF63-68_ee.indd 64

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020 7/24/15 3:52 PM 4/29/20 11:39 AM

2001OF

Month After Month.

Year After Year. Only the committed and information-hungry have gained the experience to help you survive over 65 years of cyclical storms in the marine/offshore industry.

E STA B L I SH E D I N 1 9 5 4

– The first choice for readers, the right choice for advertisers.

Technological expertise, dedication, and a wealth of knowledge gained in over 65 years makes Offshore magazine the information source for the marine /offshore oil & gas industry. Many publications are claiming to be a reliable provider of industry information. Yet to be a stable information source, a publication must be willing to weather all of the storms in order to consistently present credible editorial content. For over 65 years, Offshore magazine has never wavered from being the information source for the marine/offshore industry, in both the good times . . . and the bad. Offshore magazine provides more coverage of the world’s major offshore oil and gas producing regions than any other competitive publication. Timely updates are always accessible through print and digital magazines, global events, eNewsletters, maps, posters and online. For reliable, informative industry trends, analysis and insight into the evolving nature of the industry itself, there is still only one choice . . . 10300 Town Park Dr. • Suite 1000 Houston, Texas USA 77072 www.offshore-mag.com World Trends and Technology for Offshore Oil and Gas Operations

2001OFF_EndeavorOffshore 2005OFF63-68_ee.indd 65 1

1/2/20 11:39 1:26 PM 4/29/20 AM

• EQUIPMENT & ENGINEERING

Changing the fundamentals of subsea well completion New tree technology rethinks traditional system design JUDY MURRAY, CONTRIBUTING EDITOR

IN EARLY 2016, when the oil price dropped below $30/bbl, the oil and gas industry took a

close look at offshore development costs and realized things needed to change. Operators worked with suppliers to achieve cost reductions and cooperated in some cases to share services like crew transfers. Today, with oil prices at a 21-year low, making changes is even more critical, and the solutions that were feasible four years ago are not equal to the task. New technologies and new thinking are needed if offshore developments are going to be economically viable. DECREASING COMPLEXITY

According to Dril-Quip CEO Blake DeBerry, delivering better solutions does not mean tweaking components in traditional designs. “It is about rethinking how we do things to deliver permanent cost savings,” he said, “and that means new ideas.” DeBerry jumpstarted plans for differentiation when he became CEO in 2011. He ramped up the company’s R&D program and invested in full-scale testing of the entire subsea wellhead system. “This was our first foray into how to develop products that structurally change how customers drill wells offshore,” DeBerry said. The decision to pursue a different direction for the subsea vertical tree was initiated by a comment from a frustrated operator. The operator’s question was simple: “Why can’t we run the tubing hanger in the wellhead without regard to orientation, lock it down, get a good test and land the tree at any orientation required? “That was an ‘aha moment,’ DeBerry said. “It seemed to me that, compared to traditional systems, there had to be a simpler and less complicated solution.” DeBerry and his team of 30 engineers and designers began brainstorming about how to land the tubing hanger, and five days later, Dril-Quip filed a provisional patent. “Then, the real work started,” he said.

In-house validation testing of the VXTe system. (Images courtesy Dril-Quip)

DESIGNING A BETTER TREE

There are several challenges with traditional subsea vertical tree designs. Wellhead interfaces must be capable of handling the stack-up tolerances of casing hangers, and the tubing hanger must be oriented relative to the flowline connection system. Most conventional systems use a tubing head spool, which creates the need for temporary well barriers and additional BOP trips. Alternatively, other complicated means of orienting the tubing hanger within the BOP can be performed, enabling the tubing hanger to be installed directly into the wellhead. Dril-Quip’s new concept needed to simplify the landing and connection processes without introducing additional risks or hazards. The VXTe system addresses those challenges with the industry’s first non-oriented 15 ksi, in-the-wellhead completion, vertical tree design. This unique tree allows operators to move from drilling to completion without pulling the BOP stack. One of the most critical design elements of the tree is that it eliminates the tubing head, DeBerry explained. For conventional systems, installing a tubing hanger in the wellhead requires the use of BOP pins, rotational orientation tools or other equipment to align and run the tubing hanger. The Dril-Quip tree system eliminates the need for orientation because the stab sub assembly on the tree allows the tubing hanger to be installed like a casing hanger without regard for orientation and allows drilling and completion to be 66

2005OFF63-68_ee.indd 66

The VXTe system allows drilling and completion to be carried out without pulling the BOP stack.

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/29/20 11:39 AM

EQUIPMENT & ENGINEERING •

carried out without temporary well suspension or pulling the BOP stack. It also removes the need for well barriers, which eliminates risk and saves time. The stab sub-assembly – with 7-in./10 ksi, 5-in./15 ksi, and 5-in./20 ksi ratings – uses the same sealing interface for the stab to the tubing hanger. “A single tubing hanger running tool works for all these systems,” he said. The coupler body housing element of the stab assembling contains the hydraulic and electric couplers. It can rotate +/- 180 degrees to allow the 13 hydraulic and two electrical coupler lines to connect to the corresponding couplers in the tubing hanger. This exceeds IOGP specification requirements for nine downhole hydraulic functions and one electrical function, providing optionality for future innovations in smart completions that could require more downhole lines. Automatic space-out adjustment is another design advantage, DeBerry said. The tubing hanger of the VXTe contains a mechanism to automatically adjust to variances in the hanger’s position. When the tubing hanger is landed, a pressure test verifies the hanger is in the correct position. Then, a hanger lock mandrel is placed with a tubing hanger running tool, creating a flat lock mandrel-to-lock ring interface. “The tubing hanger can be picked up and loaded against the shoulders of the wellhead to establish a known elevation, and the VXTe tubing hanger adjustment mechanism automatically activates and removes any gaps,” he said. A 15-ksi rated annulus isolation valve inside the tubing hanger provides a reliable barrier in place of a wireline plug for installation and interventions. The annulus flow path isolates the hydraulic and electrical couplers, which protects the wellhead gasket from contact with the annulus fluid and adds another barrier between the annulus fluid and the environment. The ingenuity of the VXTe system earned it a Spotlight on New Technology Award from the 2020 Offshore Technology Conference (OTC).

a tubing hanger in the same lead time as a wellhead so when we mobilize rigs to the drill site, the installation process is streamlined. There is no rig remobilization. And if I can push drilling closer to the time I’m going to complete the well, it improves IRR because the money has been spent in a narrower window,” he said. TAKING RISKS OUT OF THE EQUATION

While time and cost savings were critical design considerations, according to DeBerry, minimizing safety risks was also a “must have” for the new vertical tree. The ideal solution would reduce the amount of required hardware and necessary trips and keep workers out of harm’s way. “A seasoned worker told me when I started in this industry, ‘Don’t ever run something down the hole if you don’t have to,’” he said. “If you eliminate running things, you eliminate risk.” This was the primary driver for a design that simplifies the installation process, eliminating placing pins in the BOP stack to orient the tubing hanger or having to install a tubing spool, which requires a 40-ton piece of hardware to be maneuvered into place. Removing components and shortening the installation process also delivers environmental gains. “ESG (environmental, social and corporate governance) is important for our industry,” DeBerry said, “so our designs are created with the goal of reducing waste and carbon footprint in any way we can.” By designing a vertical tree that does not use a tubing spool, the company has eliminated 40 tons of steel and the associated cost of manufacturing it, moving it, and installing it. The reduction in hardware and tooling within the VXTe eliminates more than 30,000 HSE heavy lift touch points. “By itself, it isn’t huge, but every little bit helps,” DeBerry says. “Although there is a lot of focus toward renewables, oil and gas will be around for a long time. We need affordable, reliable energy, and we should put the least amount of carbon into the atmosphere to get it.” THE VALUE OF STANDARDIZATION

CAPTURING COSTS

“We are proud of the elegant engineering and what that delivers to the end user,” DeBerry said, explaining that the innovative design eliminates multiple steps in the installation process and reduces the time from FID to first oil production. “Being able to eliminate steps is as valuable as reducing capex. A 10% reduction in capex and a 10% reduction in time have a similar impact on the breakeven point.” According to DeBerry, one operator calculating the potential value of Dril-Quip’s VXTe in terms of reduced installation time estimated savings at $3 million to $4 million per development well. “The Dril-Quip design can deliver savings of $30 million to $40 million on a 10-well drilling program – and that’s meaningful,” DeBerry said. The interesting thing about the economics, he said, is that when rig rates go up, the value of installing the VXTe goes up. “If the spread cost is $600,000 per day, and this technology saves a day and a half, it has delivered $900,000 in savings. If the spread cost is $1 million, the same product delivers $1.5 million in value.” Additional savings can be captured by sequencing the drilling program differently because running the tubing hanger is exactly like running the casing hanger. “Our objective is to manufacture

The introduction of the VXTe sets new expectations for flexibility and efficiency, DeBerry says, delivering a product that provides standard functionality with exceptional benefits and allows predictability in installation. This sets an expectation for operators by standardizing installation and improving project economics through enhanced delivery schedules, reduction in engineering, manufacturing and installation costs, and less risk in project execution. Dril-Quip intends to standardize the VXTe with a single tubing hanger with multiple ports, some of which will be plugged if they are not required. This will allow the company to deliver the tubing hanger with the other wellhead equipment more quickly, he said. Making this shift requires a willingness on the part of operators to reevaluate some of the components they used to have tailor made, DeBerry said, but the savings in time and installation will be strong drivers for adoption. Dril-Quip has sold the first VXTe tree which is scheduled for installation at year-end. “What Dril-Quip is doing is something totally different,” DeBerry said, “we are fundamentally changing the norm for the industry.” •

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM67

2005OFF63-68_ee.indd 67

4/29/20 11:39 AM

• EQUIPMENT & ENGINEERING

Slim stop collar intended for close-tolerance applications ESPEN SØRBØ, ACE OIL TOOLS

THE SECURE PLACEMENT of tools and accessories along both

well construction and completion strings is an essential component of all successful downhole applications. Traditional stop collars, while inexpensive, are susceptible to failure due to limited holding force on the pipe. Slippage on the pipe of any kind risks damage, increases the chance of junk downhole, and undermines the structural integrity of the well. While centralizer subs offer an alternative solution to stop collars, they are more expensive and impose limitations on string design. Ace Oil Tools wanted to create a new cost-efficient solution that worked under all conditions. Removing the risk of slippage on the pipe, while also increasing the holding force for operators looking to centralize the pipe, the Ace Ratchet Collar (ARC) brings unrivalled holding force to the market. With the ability to be installed under all operating conditions without affecting drift, it can be used with any third-party centralizer or casing accessory. The ARC was built around the company’s proprietary ‘ratcheting’ mechanism. Simple and innovative in design, the ‘ratcheting’ mechanism works by pressing the female and male parts of the collar together, creating a self-locking device. The carefully-designed teeth are machined on the male part, which generates the holding force by gripping onto the pipe. Reliably anchoring accessories to the casing without a complex installation process, each unit can be easily installed offline. Therefore, it requires no pipe preparation or transportation offsite for installation. A bespoke installation tool is used to securely fix the ratchet collar to the outside of the pipe. With minimal HSE impact to workers and environment, the full process usually takes less than a minute per unit. Since it was developed in 2012, the ARC has been installed on projects across 27 countries and five continents. Smart and cost-effective, the ARC technology adds reliability and efficiency when attaching tools to the pipe. It typically results in cost savings of up to 80%, while also protecting equipment downhole. The ARC locks together to deliver a holding force equivalent to more than 90,000 lbs. Tested to withstand axial loads up to 180,000 lbs, while meeting passthrough requirements, its slim design has been specifically intended for close-tolerance applications. This is important especially in cases where it needs to pass tight restrictions and effectively manage surge and swab. The slim design also allows for faster running speeds, even in formations with narrow mud margins. The collar makes minimal impression on the pipe and can rotate independently of the casing or liner string. It is available in standard, slim, and ultra-slim models. ARC works as a stop collar to hold both solid body and bow-spring centralizers or other accessories on the liner. The Ace Drilling Centralizer 68

2005OFF63-68_ee.indd 68

The ‘ratcheting mechanism’. (All images courtesy Ace Oil Tools)

The Ace Ratchet Collar pre-installed on casing in the workshop.

(ADC) is a rotating, solid-body centralizer for use in casing and liner drilling. The Ace Tracer Carrier (ATC) houses and protects tracer elements conveyed into the wellbore on the production string. For a major operator in Senegal, a stop collar with a slim design was required to be installed on a 11¾-in. casing, pass through a drift restriction of 12¼ in., and to provide a holding force under all operating conditions. Forty ARCs and 20 centralizers were installed offline at the pipe yard on 10 joints. The pipe was sent to the rig, then run down to a total depth of 2,776 m (9,108 ft). The casing annulus was circulated clean and cement was pumped. The company prevented centralizer movement while the ARC was running in hole. The cost savings of using the collar was in the range of $80-$150,000. • WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/29/20 11:39 AM

BUSINESS BRIEFS •

Subsea Tieback Forum Advisory Board

Standing from left to right: Karl Schnakenburg, BHP; Mark Carter, OneSubsea; Ian Ramsay, Murphy Oil Corp.; Nancy Chafe, Anadarko, a wholly owned subsidiary of Occidental Petroleum Corp.; Daniel Byrd, Total; Steve Whitaker; Hess Corp.; Aaron Weber, Talos Energy; George Zener, BP; Mike Ellis, Oceaneering International; John Smiley, Shell; Randy Seehausen, INTECSEA; Bruce Crager, Endeavor Management; Tony Matson, Trendsetter Engineering; Antonio Critsinelis, Chevron Energy Technology Co.; Chris Egan, TechnipFMC; Jeremy Woulds, Subsea 7 Sitting from left to right: Chris Tam, Saipem; James Wiseman, Noble Energy; Ron Ledbetter, College of Engineering - TAMU; Advisory Board Chairman Pete Stracke, Equinor; Erin Balch, Wood; Conference Director David Paganie, Offshore Not pictured: Joey Clements, McDermott International; Don Underwood, Dril-Quip; Maria Bulakh, Aker Solutions

LEFT: Best Presentation award winner Mark Farrow RIGHT: Best Presenter award winner Michael Dupre

The 20th anniversary of the Subsea Tieback Forum was held Feb. 18-20, 2020 at the Henry B.

Gonzalez Convention Center in San Antonio, Texas. Two speakers were awarded by the Advisory Board. The Best Presentation award is based on content and Best Presenter for delivery. Mark Farrow of LLOG Exploration won the Best Presentation award for “Buckskin: Extending LLOG’s Growth in Deepwater Gulf of Mexico”; and Michael Dupre of Shell won the Best Presenter award for “The Seven Unsolvable Problems of Appomattox.” The annual event will be held March 2-4, 2021 in Galveston, Texas.

PEOPLE

CNOOC Ltd. has appointed Hu Guangjie as president and an executive director. He succeeds Xu Keqiang, who remains an executive director and CEO. MODEC Inc. has appointed Ryo Suzuki as executive officer. ClassNK has appointed Hiroaki Sakashita Sakashita as president and CEO and Koichi Fujiwara as chairman of the board of directors. Grant Creed has stepped down as CFO of Seadrill Partners

to support Seadrill Ltd. on a full-time basis. John T. Roche, CEO of Seadrill Partners, will assume the responsibilities of CFO in addition to his current role until a replacement is found. The African Energy Chamber has appointed Elizabeth Rogo as president for East Africa and Leoncio Amada Nze as executive-president for the Central African Economic and Monetary Community. President João Lourenço has reappointed Diamantino Pedro Azevedo as Minister of Mineral Resources, Petroleum and Gas of the Republic of Angola.

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM69

2005OFF69-72_bob.indd 69

4/28/20 11:38 AM

• BUSINESS BRIEFS

Lloyd’s Register has named Mark Darley as Marine & Offshore COO. National Oilwell Varco has named David Reid as corporate vice president and chief technology officer. He succeeds Hege Kverneland, who has retired. Atkins has appointed Karen Blanc as operations director for its Resources business in the UK, Europe and Middle East. Dr. Andy Samuel will continue as the chief executive of the Oil and Gas Authority for two more years. The Petroleum Equipment & Services Association has elected Rod Larson as chair and Michael Reeves as vice chair for 2020-21. Pearl Chu, Karen David-Green, Robert Drummond, Doug Polk, and Warren Zemlak were selected for a first term on the board of directors. Matt Armstrong, Chuck Chauviere, Galen Cobb, Mike Kearney, Craig Lange, Rod Larson, Michael Reeves, Kirk Shelton, and Andrew Way were reelected to the board of directors. Melissa Cougle, Barry Glickman, Stefan Radwanski, Gabriel Rio, and Etienne Roux were approved as new members of the PESA Advisory Board. Edward Bayhi, Jeff Boettiger, Marco Caccavale, David Christmas, Kevin Crowley, David de Roode, Todd Ennenga, Bonnie Houston, Michelle Lewis, Scott Livingston, Josh Lowrey, Jill Massonne, Quay McKnight, Kyle O’Neill, David Paradis, Dan Pratt, Kyle Ramachandran, J. Wayne Richards, Bruce Ross, Sanjiv Shah, Tom Shepherd, S. Soma Somasundaram, Dave Warnick, Jim Wicklund, D. Lyle Williams, and Donald Young were reappointed to the Advisory Board. Ron Krisanda has joined Survitec as executive chairman. The Huisman Supervisory Board has appointed David Roodenburg as CEO. He succeeds Theo Bruijninckx, who will remain the company’s CFO. Ingrid Due-Gundersen has joined Ocean Installer as CFO. ASCO has appointed Gary Paver as CFO. Applied Petroleum Technology has hired Carl Peter Berg as CFO. Rovco has appointed Reena Rowan as CFO, Martin Young as chief technology officer, Iain Wallace as chief scientific officer, Ian Bryan as consultant COO, and Simon Miller as general manager of Rovco Scotland. Motive Offshore Group has named David 70

2005OFF69-72_bob.indd 70

Darley

Krisanda

Berg

Villa

Viator

Lacey

Leith as rentals division manager. Carsten Plougmann Andersen, Jean Cahuzac, Yves-Louis Darricarrere, and Florence Weingarten have joined the Société Phocéenne de Participations Supervisory Board. Shi Wenchao has joined LOC China as managing director. Captain Jaimie Jones has joined LOC Doha as marine manager. OspreyData has promoted Charissa Santos to product manager. Sercel-GRC has named Alejandro Villa as global customer support engineer. Stratagraph has promoted Elizabeth Viator to controller and human resources manager. Alan Kiraly, Bentley Systems’ senior vice president for asset and network performance, has been elected to the board of MIMOSA. Quality Companies has hired Wayne Lacey as vice president of operations for Zadok Technologies. Technical Toolboxes has appointed Joseph Ladner as engineering performance advisor. COMPANY NEWS

Flowline Specialists has launched a service and maintenance division. It will operate from the firm’s existing workshop facility at its Oldmeldrum headquarters and use existing personnel. AeonX Ltd. has signed a partnership agreement with WFS Technologies to promote and deliver the full range of Seatooth products for asset integrity and flow assurance monitoring to existing and new clients in Nigeria. Dolfines and CIMC Raffles have signed a memorandum of understanding to boost floating wind in Europe and Asia. AqualisBraemar has opened a new office in the Port of Tyne. STATS Group has opened a new workshop, storage and testing facility in Muscat, Oman. The company also secured a two-year extension to a master services agreement with Petroleum Development Oman to provide pipeline isolation and hydrostatic testing services. Unique Group has signed an exclusive rental agreement with UK-based OTAQ Offshore to represent the latter’s technology and products across the Middle East, APAC and the Americas. Add Energy’s Asset and Integrity and Management division has opened an office in Calgary, Canada. ABS Group has launched an eLearning training platform to provide educational tools and offer a catalog of professional training courses to technical personnel worldwide. The new training solution will feature on-demand courses to augment classroom training in the practice areas of cyber security, risk management, asset reliability, compliance management and process safety, and to support excellence in organizational performance. •

Ladner WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

ADVERTISERS’ INDEX • The index of page numbers is provided as a service. The publisher does not assume any liability for error or omission. Alimak Group Sweden AB

19

Allseas Group Sa

3

Ariel Corp

7

SALES OFFICES

Doris Group SA

57

Dril-Quip

C4

10300 Town Park Drive, Suite S1000 Houston, TX 77072 PHONE +1 713 963 6206 FAX +1 713 963 6228 David Davis (Worldwide Sales Manager) [email protected]

Eiffage Metal

53

Igus Gmbh

49

Ixblue Inc

59

Noia

33

United States • North America • Central America • South America

Nylacast

21

Oceaneering.

25

ENDEAVOR BUSINESS MEDIA PETROLEUM GROUP

David Davis [email protected] PHONE +1 713 963 6206

UNITED KINGDOM • SCANDINAVIA •THE NETHERLANDS • MIDDLE EAST 10 Springfield Close, Cross, Axbridge, Somerset, United Kingdom BS26 2FE PHONE +44 1934 733871 Graham Hoyle [email protected]

FRANCE • BELGIUM • PORTUGAL • SPAIN • SOUTH SWITZERLAND • MONACO • NORTH AFRICA

Offshore Magazine

65

Offshore Subscription

29

Offshore Webcasts

40

Rm Young Company

23

Tetra Technologies

C3

Weatherford

C2

Wilhelm Layher Gmbh & Co Kg

5

World Petroleum Congress

45

961 Camp Redon, 83830 Callas, France PHONE +33 (0) 6 2123 6702 • FAX +33 (0) 4 8981 9982 Stefania Piciotti Thompson [email protected]

GERMANY • NORTH SWITZERLAND • AUSTRIA • EASTERN EUROPE • RUSSIA • FORMER SOVIET UNION • BALTIC Sicking Industrial Marketing Kurt-Schumacher-Str. 16, 59872 Freienohl, Germany PHONE +49 (0) 2903 3385 70 • FAX +49 (0) 2903 3385 82 Andreas Sicking [email protected]

ITALY • TURKEY • GREECE • CYPRUS • MALTA

Silvera Mediarep Viale Monza, 24 - 20127 Milano, Italy PHONE +39 (02) 28 46716 • FAX +39 (02) 28 93849 Ferruccio Silvera [email protected]

CHINA • SOUTHEAST ASIA • AUSTRALASIA • JAPAN

19 Tanglin Road #05-20 Tanglin Shopping Center Republic of Singapore 247909 PHONE +65 9616 8080 • FAX +65 6734 0655 Michael Yee [email protected]

FOR ASSISTANCE WITH MARKETING STRATEGY OR AD CREATION, PLEASE CONTACT: Endeavor Business Media Marketing Solutions David Davis PHONE +1 713 963 6206 EMAIL [email protected]

BY WILLLIAM L. LEFFLER “I can think of no one bbetter tt tto ttranslate l t th the complexities l iti off natural gas liquids into a more easily understandable subject.” — Frank H. Richardson, President and CEO, Shell Oil Company, Retired

Natural Gas Liquids: A Nontechnical Guide is a comprehensive overview of NGLs from production in the oil patch to consumption in the fuels and petrochemicals industries. Learn what is behind natural gas liquids: • How they are produced • How they are transported • How they are consumed in the fuels and petrochemicals industry • Profles of successful NGL companies

ORDE OR DEER YO YOUR UR C COP OPYY TO OP TODA DAYY AT DA W W. WW W PE PENN NNWE NN WELL WE LLBO LL BOOK BO OKS. OK S.CO S. COM CO M ORR C CAL ALLL 8000AL 0-75 75275 2-97 297764 6

226 Pages/Hardcover/2014

MAY 2020   OFFSHORE | WWW.OFFSHORE-MAG.COM71 NGLGui_Petro_150625 1 2005OFF69-72_bob.indd 71

6/25/15 1:45 PM 4/28/20 11:38 AM

• BEYOND THE HORIZON

Sea change: securing the future of offshore energy with MPD CHANGES BROUGHT ABOUT by the coronavirus pandemic

and the recent oil price collapse have highlighted the need for readily available solutions that further optimize cost and efficiency, while at the same time minimizing risk and liability in this volatile global business environment. The innovation culture that the energy industry has fostered has frequently produced and developed solutions appropriate for the times when they are needed most, and such is the case for managed pressure drilling (MPD) technology today. The offshore energy industry is beginning to broadly realize the economic and environmental benefits of MPD, which leverages technology that closes the well in while simultaneously allowing for drill pipe rotation to enable quick precise annular pressure adjustments while drilling. Originally invented more than 50 years ago, MPD core technologies and solutions have been consistently deployed on and is now prevalent in land rigs. Offshore operators are also recently and more frequently requiring MPD-ready drilling rigs in their tenders, and current industry uptake is pointing to a not-too-distant future in which a majority of the drilling rigs offshore will be MPD-equipped. While MPD has proven essential for meeting the challenge of tight drilling windows between pore (or hole stability) pressure and fracture pressure, there is quickly emerging a more pervasive MPD future: as an effective and reliable performance-enhancing and risk-mitigating solution with significant implications for operators, drilling contractors and service companies. For operating companies, the positive implications of requiring MPD technology on the drilling rigs they procure are focused on drilling risk mitigation and operational and cost certainty. Studies have repeatedly shown that a large portion of non-productive time (NPT) events such as kicks, losses, stuck pipe, and even sidetracks and lost wells in offshore drilling operations are due to pressure-related causes. The automation and digitalization advancements inherent in current MPD technologies provide conventional drilling rigs with better system monitoring and pressure control capabilities that keep the time and cost impact of these events to a minimum, helping ensure that the commercial and technical objectives for the wells are met. Used to its fullest potential, MPD can even be further leveraged to optimize the well architecture and perform technical feats only possible with MPD. These advances can provide further economic and strategic advantages for operators that choose to wield the technology for their benefit. For drilling rig contractors, aside from the technological

superiority and the increased rig marketability that comes with it, MPD solutions provide an increased level of safety and operational performance that enables better red-zone management and lesser personnel on board (POB). MPD algorithms and control systems used in conjunction with real-time remote support from subject matter experts augment the operational experience and knowledge of existing drilling personnel, helping address the skilled labor shortage of an industry that has seen its worst prolonged downturn in a generation. Once assimilated into an existing drilling rig system, an MPD investment immediately provides value through early kick detection and control. This drastically reduces the risk of loss of well control and helps safeguard the corporate reputations of the drilling contractor that has purchased the MPD system, as well as the operator that has utilized the same. For technology service companies, the increased use and adoption of MPD technologies provides an opportunity to refine and optimize technical solutions and the commercial models in collaboration with partners. With an increase in volume of MPD use, the industry stands to achieve and benefit from the standardization of platforms, processes and procedures as well as provide opportunities for the training and development of technology specialists. From a data science and analytics perspective, this will provide a larger data set of operational experience that can be leveraged to develop better iterations of the technology, which in turn will help achieve economies of scale to sustain the organizations and systems that support it. And for the energy industry, the implications of increased MPD adoption in the offshore space are a vast reservoir of untapped potential. Growth in the adoption of MPD has produced operational benefits that have flattened the curves of cost and risk and opened new areas and depths to offshore exploration and development. Among deepwater drilling rigs, there has been a marked increase in the use of MPD technologies and solutions, bringing the adoption rate from zero to ~15% today in the span of a decade since it was first used. History is replete with countless examples of technology serving as the linchpin in the engine of growth that has continuously spurred the energy industry onwards and upwards. Today, MPD technology stands ready to accept that challenge. KEVIN FISHER, VICE PRESIDENT FOR MANAGED PRESSURE DRILLING, WEATHERFORD

This page reflects viewpoints on the political, economic, cultural, technological, and environmental issues that shape the future of the petroleum industry. Offshore Magazine invites you to share your thoughts. Email your Beyond the Horizon manuscript to David Paganie at [email protected]. 72

2005OFF69-72_bob.indd 72

WWW.OFFSHORE-MAG.COM | OFFSHORE   MAY 2020

4/28/20 11:38 AM

Novel High-Density, Solids-Free Completion Fluid Solutions for Environmentally Sensitive Wells START WITH TETRA CS NEPTUNE® COMPLETION FLUIDS Our innovative high-density TETRA CS Neptune completion fluids are free of priority pollutants. Our fluids help address the environmental challenges facing offshore oil producers seeking an alternative to zinc brines. Costing significantly less than alternative completion fluid chemistries, they can also be used as the basis for low solids reservoir drill-in fluids or in other applications where a high density, environmentally acceptable fluid is required. Visit tetratec.com/neptune for more information or contact us at [email protected].

TETRA CS Neptune® Completion Fluids Portfolio TETRA CS Neptune® Divalent Completion Fluids

To 15.4 lb/gal • 350°F (177°C)

TETRA CS Neptune® High Density Divalent (HDD) Completion Fluids

To 15.7 lb/gal • 290°F (143°C)

®

TETRA CS Neptune Extra High Density Divalent (XHDD) Completion Fluids

To 17.5 lb/gal • 350°F (177°C)

TETRA CS Neptune® High Density Monovalent (HDM) Completion Fluids

To 13.1 lb/gal • > 350°F (171°C)

®

TETRA CS Neptune Extra High Density Monovalent (XHDM) Completion Fluids

To 15.7 lb/gal • > 350°F (177°C)

04/2020 © TETRA Technologies, Inc. All Rights Reserved.

2005OFFC1-C5.indd 3 2005OFF_TetraTech 1

4/29/20 11:50 AM 4/24/20 4:56 PM

... and time is money DrffilffiQuffip’ffi ffiffiffiluffiffiffiffiffiry ffirffillffiffiffi ffiffiffi SPS ffiffiluffiffiffiffiffi ffiffiffiblffi yffiu ffiffi wffirk fffiffiffiffir ffiffiffi ffimffirffiffir – wffiffih lffiffiffi ffipffirffiffiffiffiffiffil ffiffiffi ffiffiffiffirffiffimffiffiffiffil rffiffik – and ffipffiffiffi lffiffiffi mffiffiffiy ffiffiffiffiffi ffiffi! Lffiffi uffi ffiffimffiffiffiffirffiffiffiffi Jffiffiffi uffi fffir ffiffi ffiffilffiffiffi ffiffiffimffiffiffiffi prffiffiffiffiffiffiffiffiffiffi ffiffi lffiffirffi hffiw wffi ffirffi fuffiffiffimffiffiffiffilly ffihffiffiffiffiffiffi ffihffi wffiy wffillffi ffirffi ffirffillffiffi ffiffiffi ffiffimplffiffiffiffi ffiffi ffiffiffiffi yffiu pffirmffiffiffiffiffi ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi

DrffilffiQuffip ffiffiffi fully ffipffirffiffiffiffiffi ffiffiffi rffiffiffiy ffiffi hffilpffi

the power of

TM

dril-quip.com/power-of-e ©2020 Dril-Quip, Inc. All rights reserved. Dril-Quip logo and

2005OFFC1-C5.indd 4 2005OFF_Drip-Quip 1

TM

are trademarks of Dril-Quip.

4/29/20 11:50 AM 4/22/20 4:42 PM