PERSPECTIVES Issue 01/2015

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SAFER, SMARTER, GREENER

SMART WORKINGDELIVERS GREATERCOST SAVINGS

PERSPECTIVESOil and gas industry insight Issue 01 | 2015

ALSO INSIDE:

LEARNING FROM MACONDOA summary of 21 inquiries into the incident flags up key ways to reduce the risk of a repeat of the tragedy

STAYING LEAN AND MEANLundin Norway called upon external expertise to get ready for operation on its journey to first oil

DEEPWATER SOLUTIONSIndustry experts highlight strategies to boost returns on deepwater mega projects in a constrained climate

2 PERSPECTIVES

contents

CONTENTS

Disclaimer: DNV GL prides itself on providing accurate information but makes no claims or guarantees about the accuracy, completeness or adequacy of contents in this publication, and disclaims liability for any errors or omissions. The authors’ views here do not necessarily reflect DNV GL’s views.

PERSPECTIVES 01.2015 © DNV GL AS 2015Published by DNV GL ASNO-1322 Høvik, NorwayTel: +47 67 57 99 00

EDITORRobert Stokeswww.cmapsglobal.org

EDITORIAL TEAMCathrine Torp, Robert Coveney,Joyce Dalgarno, Alison Cowie,Richard Crighton

DESIGN AND LAYOUTThe BIG [email protected]

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04 NewsThe latest updates from DNV GL

06 The future of deepwater mega projectsExperts from Shell, BP, FMC Technologies and Maersk Drilling highlight how standardisation, collaboration and better management of technology deployment can boost financial returns on deepwater mega projects in the new economic climate

10 Managing costUnderstanding the most significant root causes of cost inflation is vital to the viability of new offshore projects

14 Learning from MacondoFive years after the Macondo incident in the Gulf of Mexico, a new summary of 21 inquiries into the tragedy flags up key ways to reduce the risk of a similarly major event happening

18 Regulatory outlookRegulators can reduce the risk of major incidents by learning from each other

20 A roadmap to first oilLundin Norway drew on DNV GL’s regulatory know-how when preparing operations for first oil on the Brynhild field

22 Floating productionStandardisation can deliver substantial savings when fabricating newbuild floating unitswithout compromising quality and safety

24 Reducing pipeline expenditurePipeline experts share insights on how improved project planning can rein in capex and opex

26 Technology Strategies to help commercialise new technologies in the oil and gas sector

29 Joint industry projectsPipeline cracks, gas grid hydrogen and subsea documentation are among the themes targeted by DNV GL’s current JIPs

30 PlatformThe future of the US unconventional oil and gas sector in the face of an industry-wide downturn

ISSUE 01 | 2015 | PERSPECTIVES 3

WELCOME

We must learn

from previous

downturns...

Savings are best

achieved through

smarter working”

“

TAKING A LONGER-TERM VIEW

The oil and gas industry is divided over how to respond to lower oil prices. DNV GL’s research on the outlook in 20151 found those who are most confident about reaching profit targets plan different cost-management measures, taking a long-term approach to riding out the storm. ‘Profit pessimists’ are more likely to take short-term cost-cutting measures.

We must learn from previous downturns and avoid knee-jerk reactions that will harm our sector later on. Savings are best achieved through smarter working. Reducing complexity and using standardisation to streamline processes, materials and documentation will help the industry to adjust to lower margins.

In this latest PERSPECTIVES, we report on how Shell, BP and FMC Technologies are looking to improve efficiency through standardisation and collaboration when planning capital-intensive projects in the deepwater industry (page 6).

We show how understanding cost drivers offers opportunities to more closely align performance with justifications made for final investment decisions. We also explain how our approach to selecting standards can support the industry to achieve greater cost efficiency in offshore projects (page 10).

South Korea’s leading shipyards explain why they hope a new joint industry project led by DNV GL will lead to cost

savings through international engineering and construction standards for offshore oil and gas projects (page 22).

Meanwhile, a survey of pipeline experts has highlighted the importance to cost management of monitoring the early phases of a project (page 24). We discuss how budgets can be inflated by lack of detailed front-end engineering design, as well as other factors.

Smart solutions to managing costs are also a high priority for companies planning a project’s transition into operation. Lundin Norway details its approach to remaining ‘lean and mean’ while meeting regulatory requirements associated with bringing the Brynhild field online (page 20).

While striving to save money, we cannot compromise on safety. Our summary of inquiries into the 2010 Macondo incident stresses the importance of dedicated efforts to improve safety, and how we must learn from accidents (page 14).

Although the market remains tough, DNV GL continues to support the oil and gas industry in realising cost efficiencies, while improving safety and reliability in projects and operations. I hope you find the features in this edition of PERSPECTIVES useful as we tackle these challenges head on.

Elisabeth TørstadCEO, DNV GL - Oil & Gas

DNV GL headquarters, Høvik, Norway

1 ‘A Balancing Act: The outlook for the oil and gas industry in 2015’, DNV GL. Download at: dnvgl.com/balancingact

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NEWS

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VERIFICATION FOR MARIA DEVELOPMENT

DNV GL will play a combined role as independent verification body (IVB) and third-party design verification partner for Wintershall Norge AS on the Maria field development project offshore Norway.

The contract has a potential value of NOK30 million (USD3.95m) and is expected to run until the end of 2018, when first oil is scheduled. It covers the subsea, umbilicals, risers and flowlines (SURF) elements of the project.

The IVB model includes all phases from design through to commissioning. The third-party verification role covers design and options for involvement in the fabrication, manufacturing, installation and commissioning phases.

Sture Angelsen, business development manager at DNV GL - Oil & Gas said: “This approach to handling verification is well known in the UK sector, but is less used in Norway. By being able to deliver both IVB and third-party design verification, we are able to help streamline a quality and timely project execution.”

The Maria oil discovery is located in the Haltenbanken region of the Norwegian Sea.

FIRsT DP FLOATOVER INsTALLATION IN ChINA

Our Noble Denton marine assurance and advisory team has assisted China National Offshore Oil Corporation (CNOOC) with the country’s first offshore platform installation using advanced dynamic positioning (DP) floatover technology. The successful installation took place in the eastern waters of the South China Sea for the Enping oilfields.

The load-out weight of the topside for CNOOC’s HZ25-8 drilling product platform exceeded 13,000 dry weight tonnes, the largest transverse load-out in China to date. DNV GL supported the customer in optimising load-out operational procedures and ballast through transverse load-out and DP of the floatover installation, while saving time, manpower and material resources.

Ruhua Yuan, vice general manager of CNOOC subsidiary China Offshore Oil Engineering Corporation (COOEC) said: “This is a perfect realisation of applying world-class offshore structure installation technology in the South China Sea area. Our cooperation with DNV GL has enabled the new breakthrough of our technology and competence in offshore installation.”

MARINE WARRANTYCONTRACT WINOFFshORE ANGOLA

DNV GL’s Noble Denton marine assurance service will deliver a marine warranty services (MWS) contract for Total E&P Angola’s ultra-deepwater Kaombo project.

MWS activities will focus on a review of design documentation and execution of critical marine operations. The contract will ensure that transportation and installation of 300 kilometres of flowlines and 20 manifolds complies with recognised guidelines, standards and the customer’s internal requirements. The flowlines and manifolds will connect 59 wells to two very large crude carriers, currently being converted into turret-moored floating production storage and offloading vessels.

DNV GL has previously worked with Total on the CLOV, GirRI and Dalia projects in Angola.

“Our team will comprise competent Angolan nationals who will be trained to support the development of MWS in the region,” said Sergio Garcia, area manager for Sub Saharan Africa, DNV GL - Oil & Gas. “This will deliver long-term benefits to the country and build upon our competence within Angola, supporting customers with a more proactive delivery of local MWS.”

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CNOOC’s HZ25-8 drilling product platform

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DNV GL assisted Total’s CLOV FPSO project


NEWS

Classification and verification work is underway with Eni Muara Bakau B.V. on the Jangkrik floating production unit (FPU) project offshore Indonesia. Jangkrik is one of the country’s first deepwater gas developments.

In a joint venture partnership with state-owned PT. Biro Klasifikasi Indonesia (BKI), DNV GL will deliver verification services for topside facilities and maritime classification of the FPU – this is the start of our first mega project in Indonesia.

The large scope of work will be provided by DNV GL’s teams in Korea, Singapore and Indonesia.

Once operational, the newbuild spread-moored FPU will have the capacity to treat 450 million standard cubic feet of gas per day plus condensates. The unit is scheduled to start production in 2017.

“This project will provide a major boost to Indonesia’s national gas production,” said Richard Bailey, director for Asia Pacific and the Middle East, DNV GL - Oil & Gas. “The contract will showcase DNV GL’s capabilities to this burgeoning market.”

Eni is operator of the block with a 55% interest, partnered by GDF Suez which holds the remaining 45% interest.

FIRsT MEGA PROjECT AWARD IN INDONEsIA

ARCTIC EMERGENCY REsPONsE AND REsCUE sTRATEGIEs

A new DNV GL report looks at the feasibility of emergency preparedness solutions in an Arctic region and calls for the industry to collaborate on new response concepts.

In ‘Emergency response for offshore operations in the Barents Sea’, we examine the effects of wind speed, wave height and the presence of sea ice on the availability of evacuation and rescue resources. It also analyses the long-range rescue capability provided by search and rescue helicopters.

As offshore field developments in the North and Norwegian Seas face maturity, operators on the Norwegian Continental Shelf (NCS) are looking to the more remote areas of the Barents Sea for further development. Here, harsher environmental conditions, prolonged periods of darkness and long distances to shore make evacuation and rescue of personnel on Arctic offshore installations more challenging.

Many questions about emergency response in the north of the region remain unanswered, according to Liv Hovem, director for Europe and Africa, DNV GL - Oil & Gas.

“We aim to help close that gap with this research,” she explained. “A coordinated approach to exploration activities in remote areas would help ensure safe offshore operations in the Barents Sea. Operators could share emergency response resources and their associated costs to ensure sufficient response capacity.”

To support the outcomes of the position paper, DNV GL is also initiating a new joint industry project (JIP) which will address qualification of Arctic emergency response concepts. The aim of the JIP will be to determine which types of emergency concepts result in a satisfactory level of safety. It will also assess and compare the different levels of economic feasibility.

A copy of DNV GL’s report ‘Emergency response for offshore operations in the Barents Sea’ is available to download at: dnvgl.com/arcticresponse

DNV GL is calling for collaboration on Arctic emergency response and rescue strategies

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6 PERSPECTIVES

We need to turn

the industry’s

creativity and

energy towards

more cost-efficient

and reliable

solutions”

Dr Kevin Kennelley, vice president – facilities technology, BP

Deepwater mega projects typically cost billions (bn) of US dollars each, and their risk grading is the highest for all field development types. So it is no surprise that lower oil prices have caused industry commentators to ask whether companies will press ahead with active and planned deepwater projects. There are also question marks over future development and deployment of new enabling technologies such as subsea compression.

“A reduction in operators’ willingness to engage in capital expenditure (capex) intensive projects will limit further field trials and severely impact the spread of relatively unproven technologies,” according to analysts Douglas-Westwood.1

While cost cutting by operators has slowed some deepwater mega projects, the majority remain on track, according to Norway’s INTSOK, an offshore industry and government networking and knowledge exchange.

Even as oil prices slumped, US operator Hess confirmed at the time of PERSPECTIVES going to print that it would proceed with the USD6bn development of a deepwater field in the Gulf of Mexico alongside Chevron, Statoil and Nexen.2

DEEPWATER PROJECTS FACE UP TO COST CHALLENGECollaboration, standardisation and technology are long-term responses to lower oil prices

“

THE FUTURE OF DEEPWATER MEGA PROJECTS

Shell has operations in 14 deepwater basins including the Gulf of Mexico. It remains “positive about finding the right mix of synergies to develop such projects cost effectively”, according to Dr Ajay Mehta, technology delivery manager – deepwater projects, Shell International Exploration and Production.

Mehta was speaking at INTSOK’s deepwater mega projects conference3 in Houston, US, an event that provided a timely indicator of industry thinking on this theme.

“Oil prices will remain a significant factor in future project economics and final investment decisions (FIDs),” Graeme Pirie, vice president, business development, North America at DNV GL - Oil & Gas, told the conference. “However, we feel the greater challenge is cost efficiency.”

Compared with capex eventually authorised, original FIDs underestimated costs for deepwater projects by 45% on average between 2009 and 2014.4

“What has made the industry successful in the past two decades is not enough,” Mehta said. “Rapid cost escalation is a problem that developed before the current drop in oil prices, and it has to be solved no matter what the oil price is. Our projects need to be credible, competitive and affordable.” >

PHOTO FMC TECHNOLOGIES

1 Douglas-Westwood research note, December 20142 ‘Hess announces plan to develop stampede field in the deepwater Gulf of Mexico’, Hess, 28 October 20143 Deepwater mega projects: INTSOK US-Norway Technology Conference, February 20154 ‘380 projects to change the world – top 380 trip highlights a disconnect in two supply chains,’ Goldman Sachs, May 2013



Standardised subsea interfaces are a boon to equipment makers such as FMC Technologies. The company’s deepwater riserless light well intervention stack, pictured aboard an intervention vessel, boosts production from seabed wells

8 PERSPECTIVES

Collaboration and standardisationFrom an original equipment maker’s (OEM) perspective, Brad Beitler, vice president, technology at FMC Technologies said his company wanted to work closely with customers to reduce costs per well, keep deepwater development sustainable, and draw on economics of scale together.

Speakers from two oil supermajors signalled willingness to collaborate on cost challenges. “We have to work more with our suppliers in the early stages, not just hand specifications to them,” Shell’s Mehta said.

Similarly, Kevin Kennelley, vice president – facilities technology, BP, commented: “We need to work much more closely with OEMs, yards and others, and at much earlier stages, to identify savings and things that can be done just a little differently yet still yield great savings. There is a lot of potential here.”

Such views echo analysis showing the value of improving front-end loading of projects to make savings (page 10).

Turning to the key topic of standardisation, Mehta said: “We have to be less accommodating to one-offs and to tweaks that may seem innocent enough by themselves, but which

destroy any standardisation achieved up to the point where that tweak is made.”

The potential value of standardisation was quantified by FMC Technologies’ Beitler. He said that, generally speaking, the cost reduction delivered by making something more than once is roughly 20%. “There are so many other benefits, including indirect cost reductions such as safety through familiarisation,” he added.

Deepwater operators are aware of these potential benefits. For example, US oil company Anadarko’s offshore deepwater platforms in the Gulf of Mexico demonstrate greater standardisation in practice, with an existing design concept being reused.5

DNV GL’s Pirie indicated that standardisation underpins “the most important” cost reduction initiatives being launched, or underway, and of relevance to deepwater mega projects. He cited Statoil's standardisation of subsea factory interfaces; FMC Technologies’ ‘benefits from subsea standardisation’ initiative; the Society of Petroleum Engineers’ subsea standardisation initiative; the Norwegian Oil & Gas Association (NOGA) report on subsea standardisation; and DNV GL’s joint industry projects (page 29) and standards.

“We would like to see the ‘plan one, build many’ concept re-evaluated to determine how it could work in our industry where nearly every facility is unique,” Pirie added. Beitler suggested one way in which it could work: A modular approach involving custom configuration of standardised modules can address most needs, he said.

BP’s Kennelley expressed optimism about achieving agreement around standards despite the increasing complexity of projects and the growing number of people involved. “It is possible to take a group of, say, metallurgists into a room and not come out until they have agreed on an acceptable standard. I have seen it happen.”

Managing technologyTechnology in general, and subsea in particular, is a great enabler for deepwater projects. But while making full use of innovative technology can do “wonderful things” in deepwater, the management of its deployment needs to be more refined, suggested Caroline Marie Alting, team lead in Maersk Drilling’s technical organisation.

She explained: “It needs to be evaluated more thoroughly, not just from a cost-benefit perspective, but also from the likelihood of it actually being used,

Shell’s Ajay Mehta (l), FMC Technologies' Brad Beitler, and Caroline Marie Alting (r), Maersk Drilling, discuss ways to improve the economics of deepwater projects


PHOTOs DNV GL, FMC TECHNOLOGIES

5 ‘A Balancing Act: The outlook for the oil and gas industry in 2015’, DNV GL. Download at: dnvgl.com/balancingact


and the associated training and familiarisation needs, as well as the buy-in of personnel that may or may not use the technology. There is probably a lot of waste in this area.”

Aside from big themes such as collaboration, standardisation and technology, there is scope for cost reduction in many individual ways, Kennelley stressed. “We need to chip away at the elephant one piece at a time and to have our eyes on total cost of ownership,” he said. “For instance, running offshore supply vessels at three-quarters throttle usually results in at least 50% savings in fuel costs.”

Maybe the best efficiency that can be realised is related to regulation (page 18), he suggested: “Global standardisation and the use of internationally-recognised standards could be based on a common global regulatory framework.”

The ‘take home’ message from Kennelley was that the industry is creative and asks for much more than it needs for field developments, including deepwater mega projects. “That time is now over and we need to turn the industry’s creativity and energy towards more cost-efficient and reliable solutions,” he urged.

FMC Technologies has chosen DNV GL to perform independent third-party verification of a 20,000 pounds per square inch (psi) high pressure, high temperature (HPHT) subsea completion, production and workover system for the Gulf of Mexico. FMC Technologies is coordinating this as a joint development agreement (JDA) with international oil companies Anadarko, BP, ConocoPhillips and Shell. Its aims are product standardisation and greater cost efficiency. Breaking the 20,000psi HPHT barrier at extreme depths has for years been the objective of taskforce groups of the best and brightest engineers within many of the oil majors. It is seen as a vital long-term capability for maximising development of deepwater and ultra-deepwater resources.

The establishment of the JDA led by FMC Technologies shows an industry that is now pragmatically collaborating as a response to increasing costs and a falling oil price. DNV GL is involved in several HPHT projects in the US.


DNV GL WINs WORK ON 20,000PsI hPhT PROjECT

Subsea standardisation widens the applicability of tools on remotely operated underwater vehicles

Long-term collaboration with pump makers such as Sulzer Pumps assists development of high-performance, reliable and cost-effective solutions, such as this multiphase subsea boosting system for FMC Technologies’ customers

10 PERSPECTIVES

COMPLEXITY IS THE KEY COST DRIVERDeep understanding of what inflates cost is vital to control field development project expenditure

MANAGING COST

For capital

projects, I see

more focus

around us, and in

Sakhalin Energy,

on standardisation

and replication”

Rob van Velden, finance director, Sakhalin Energy

“

PHOTOs SAKHALIN ENERGY

The offshore oil and gas industry has regularly failed to stay within budgets and timetables set out in final investment decisions (FIDs) for field development projects. Compared with authorised capital expenditure (capex), FIDs underestimated costs by 16% on average, and more for deepwater (45%) and heavy oil (50%) developments, over the period 2009 through 2013.1

Lower oil prices are focusing minds on cost. A DNV GL survey2 of more than 360 senior oil and gas professionals worldwide found the percentage of respondents planning increased capex this year had fallen from 40% to 12% between October 2014 and January 2015.

“It is important to develop detailed understanding of cost drivers,” said Etienne Romsom, strategy and business development director, DNV GL - Oil & Gas. “Sometimes, answers that seem obvious – salaries, steel prices and so on – are not the whole picture. Cost inflation of this kind accounts for only a third of increased project expenditure seen in recent years.”

Identify the right targetsScope inflation is a major issue, he stressed: “Greater development complexity further increases the cost per barrel produced. Companies that fail to understand this risk addressing targets less likely to impact significantly on profitability.”

Deferring projects or squeezing suppliers may not always be the best approach, he suggested. “The solutions lie in working smarter, for example through collaboration, sharing of assets, standardisation, digital technology and joint innovation, and in taking a risk-based approach across the project and asset lifecycle.”

Many companies now need to identify these opportunities. “While future oil prices remain hazy, the cash wheel is getting stuck,” said Romsom. “Project cost escalation pre-2011 was partially offset by rising oil prices, but this evaporated as prices stayed flat before plunging.”

Unit costs in exploration and production have showed compound annual growth of 11% since 2000.3 This has shrunk return on investment in real terms. The combined cash return on cash invested by global supermajors ExxonMobil, Shell and BP was around its lowest for 40 years by the end of 2013, and was forecast to decline further, even at assumed future oil prices at USD100 per barrel.4

DNV GL has looked closely at opportunities to assist the industry to align performance with justifications made for FIDs.

“Many projects fail to adequately address project risk during the planning phase and often have insufficient understanding of uncertainty related to scope >

1 ‘380 projects to change the world – top 380 trip highlights a disconnect in two supply chains,’ Goldman Sachs, May 20132 ‘A Balancing Act: The outlook for the oil and gas industry in 2015’, DNV GL. Download at: dnvgl.com/balancingact3 Analysis by Barclays based on International Energy Agency data4 ‘Global offshore prospects’, Douglas-Westwood presentation at The Energy Institute, London, September 2013


The Piltun-Astokhskoye-B platform in the Sakhalin-2 Project which faces costs related to harsh climatic conditions

MANAGING COST

12 PERSPECTIVES

MANAGING COST

changes,” said Elisabeth Rose, head of section, project risk management, DNV GL - Oil & Gas. “A core reason for scope inflation is rising customisation. A lack of replication or standardisation adds to complexity,” she added.

Romsom warned that, beyond a certain point, additional specifications do little to reduce risks. “They just continue to add cost and erode value,” he said. “They can even start to increase risk as added specifications dilute focus, introduce needless complexity, limit supply-chain efficiency or increase exposure during project execution and/or operations. We are seeing many examples of unnecessary and costly spec-inflation.”

A risk-based responseIn addressing these challenges, DNV GL is working with the industry on project risk, standardisation and innovation. The company has taken the initiative to investigate solutions for cost challenges related to variations in technical requirements seen from both suppliers’ and oil companies’ perspectives. The outcome will be suggested improvement initiatives and changes to reduce conflicting and superfluous requirements that affect cost. These suggestions will cover company internal specifications as well as regulations.

“Working with the industry has shown us potential areas for significant cost reduction through smart choices of standards and company requirements,” Romsom said.

For example, DNV GL assisted an operator to assess the difference in impact between using industry standards and company specifications when building a rig to operate in harsh environments. It found that a similar safety specification could be achieved at about half the cost through a risk-based selection of standards.5

This ‘gap analysis’ of standards for offshore rigs in harsh environments aims to eliminate company-specific requirements where prudent and practical. The method involves comparing each of the applicable company specifications against Class rules and voluntary notations.

Where Class rules hold an equivalent standard of safety, company specifications could be eliminated with no impact on risk. Application of Class rules provide a cost reduction compared with company specifications as the former leverages on standardised work processes throughout the supply chain.

Sakhalin Energy intends to source more skills locally to cut logistical and other costs of using remote providers

5 ‘“Spec inflation” driving up costs’, Paul Cleary, The Australian, 9 March 2015

GRAPHIC BIG PARTNERSHIP

A core reason

for scope

inflation is rising

customisation. A

lack of replication

or standardisation

adds to

complexity”

Elisabeth Rose, head of section, project risk management, DNV GL - Oil & Gas

“


MANAGING COST

RELATIONshIPs BUILD VALUE

Operators can gain more long-term value from sustaining business relationships with suppliers rather than squeezing them or retendering work in a downturn, says Eric Janvier, head of the capital projects practice at SBC, the management consulting arm of global oil services group Schlumberger. “When you work long-term with a supplier on one solution with intelligent incentive, you can actually drive the costs down and the performance up through the years from project to project,” he said in an interview for DNV GL. “It’s like trying to win a football game by changing the team and trainer each time you play: you do not have the continuity. In my opinion, this is what oil and gas has missed but the car industry has not. You simply could not build cars anymore by redesigning everything in a car for every model. Things would not work.”

Capital expenditure per barrel of oil soared in the upstream oil and gas industry after 2000 as the compound annual growth rate (CAGR) of capex rose sharply

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Upstream oil: capital expenditure per barrel of oil 1985–2013Source: Barclays from IEA data

0.9% CAGR(1985–1999)

10.9% CAGR(1999–2013)

“If company specifications include requirements beyond the intention or scope of internationally-recognised codes and standards, the criticality of such a gap will need to be understood,” Romsom said. “A lifetime perspective will be required to fully understand the cost-efficiency and safety impacts of incorporating such additional requirements.”

Share knowledge earlyDNV GL recommends that the process for risk-based evaluation and selection of standards starts even before the concept selection phase in the project lifecycle.

“Proper front-end loading of a project is important to help you think through your options and total cost of ownership (TCoO) before making final decisions,” explained Rob van Velden, finance director at Sakhalin Energy. The Russian operator faces significant cost challenges in its oil and gas projects in harsh climatic conditions on the remote Sakhalin Island. “Front-end loading, and multi-disciplinary and independent reviews of the project at certain stages/decision gates, helps Sakhalin Energy to avoid issues on projects,” he added.

“Appropriate technical verification of pre-FEED (front-end engineering design)

and FEED is one possible solution to identify issues that arise during these stages and remedy flaws in them,” Rose observed.

Once sub-optimum specifications enter the supply chain, it can take significant effort and time to correct them. Examples in subsea have shown that correcting a specification throughout the supply chain can take eight months, adding to lead time and costs.

“Standardisation that allows transparent certification services lets operators reduce uncertainty, lead time and cost,” Rose said.

“For capital projects, I see more focus around us, and in Sakhalin Energy, on standardisation and replication,” said van Velden. “Reinventing the wheel is always costly and not always worth it. We are getting more careful here, and are less open for engineering creativity if there is no solid business case.”

It is not just about capital expenditure, he added. “On TCoO I note that capex is important, but also the operational expenditure after project start-up. It is not uncommon that a more expensive but easier-to-operate project generates more value to stakeholders.”

14 PERSPECTIVES

Many key

recommendations

have been

adopted in one

form or another”

Peter Bjerager, director for the Americas, DNV GL - Oil & Gas

“

OIL AND GAS TAKESLESSONS FROMMACONDOMarking the fifth anniversary of the Macondo incident in the Gulf of Mexico, a summary of inquiries into the tragedy flags up key ways to prevent a repeat

1 ‘Summary of Macondo inquiries’, DNV GL, 2015. Download at: dnvgl.com/macondo2 ‘Forensic examination of Deepwater Horizon blowout preventer, Vol I and II (appendices)’, DNV GL, 20113 National Commission on the BP Deepwater Horizon oil spill and offshore drilling – main report and multiple topic papers, 20114 Report of the chief counsel to the National Commission on the BP Deepwater Horizon oil spill and offshore drilling, 20115 ‘Deepwater Horizon lessons learned and follow-up’, Norwegian Oil & Gas Association, 2012

Much has been done to reduce the risk of another major incident such as the Macondo tragedy, but more change is needed. This is a key message in a new summary1 by DNV GL of findings and recommendations by 21 major inquiries into the BP Deepwater Horizon drilling rig explosion and oil spill in the Gulf of Mexico in 2010. The inquiries were conducted by governmental, industry and independent organisations in the US, UK, Norway and the Republic of the Marshall Islands.

“We have carried out this review because no single investigation provides a full overview of the actions recommended to prevent another Macondo,” said Peter Bjerager, director for the Americas, DNV GL - Oil & Gas. “There will doubtless be further investigations, particularly around long-term environmental effects of the spill. The US Chemical Safety Board (CSB) intends to address organisational and human factors. Five years on though, it is timely to review key lessons and recommendations.”

Lessons learnedBroad subject headings for the recommendations from all 21 inquiries are summarised in the table to the right. Among technically-focused investigations, the US Justice Department commissioned a DNV GL forensic examination of

the Deepwater Horizon rig’s blowout preventer (BOP) recovered from the seafloor. DNV GL made detailed recommendations2 regarding BOP design and operation issues.

Among the most high profile studies, the US Deepwater Horizon Commission3 and its chief counsel4 included lessons learned for industry, government and energy policy. The Commission stressed how culture was a key factor for enhancing safety and discussed issues affecting BP, its contractors, and the industry in the Gulf of Mexico generally.

The organisation and response by US federal and state agencies, and the cooperation of BP and the whole industry, was commended by the national incident commander, Admiral Thad Allen.

In other nations, the Norwegian Oil and Gas Association (formerly OLF), led an inquiry for which DNV GL reviewed regulatory differences between the US and Norway. This concluded that the Norwegian Continental Shelf had robust legislation and safe operations.5 It made 45 recommendations for improvements to prevention, intervention and response, and summarised those related to well control and response issues.

In the UK, the Health and Safety Laboratory (HSL) studied fire and >

LEARNING FROM MACONDO

TAble DNV GL, BIG PARTNERSHIP



CATEGORIEs OF FINDINGs AND RECOMMENDATIONs FROM 21 INqUIRIEs INTO ThE MACONDO INCIDENT

No. Inquiry PreventionBOP design

and operationContain and

respondManagement and culture

US regulatoryInternational

regulatory

01 DWH Commission – main 02 DWH chief counsel's report 03 BP investigation 04 Transocean investigation 05 US Coast Guard 06 BOEMRE 07 Republic of the Marshall Islands 08 Admiral Thad W Allen report 09 DNV GL forensic investigation 10 Chemical Safety Board (US) 11

Center for Catastrophic Risk Management (US)

12National Academy of Engineering (US)

13 National Research Council (US) 14

US District Court Eastern Louisiana

15Norway Petroleum Safety Authority – interim

16Norway Petroleum Safety Authority – final

17 OGP 18 OLF 19 SINTEF 20 UK HSL 21

US Transportation Research Board

AbbreviationsBOP: Blowout preventer01 and 02 DWH: Deepwater Horizon06 BOEMRE: US Bureau of Ocean

Energy Management, Regulation and Enforcement (now BSEE and BOEM)

17 OGP: Now the International Association of Oil and Gas Producers

18 OLF: Now the Norwegian Oil and Gas Association

19 SINTEF: Stiftelsen for industriell og teknisk forskning (Norwegian independent research organisation)

20 UK HSL: UK Health and Safety Laboratory

16 PERSPECTIVES

explosion issues related to Macondo. HSL relied on key investigations elsewhere, mainly in the US, and found that recommendations from these generally matched those for offshore UK.6

The legacyDNV GL’s summary of inquiries flags the legacy of reforms to reduce risk and improve occupational and process safety. “Many key recommendations have been adopted in one form or another,” Bjerager said. He cited the emergence of two new US regulatory entities: the Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Ocean Energy Management (BOEM). This has separated safety oversight from resource management. “The set-up now emphasises goal-based safety and includes increased numbers of inspectors to boost presence offshore in both safety and environment.”

BSEE has issued new requirements for: drilling safety; BOP recertification; negative pressure tests; professional engineer sign-off on casing and cement; and for a compulsory estimate of worst-case blowout events.

The American Petroleum Institute (API) and the International Association of Drilling Contractors have worked on an interface requirement between rig

lessees and drilling contractors. Several new API standards are available. SEMS I & II have been implemented with the new Center for Offshore Safety defining the protocols and approving third-party audit service providers.

BSEE has provided guidance on safety culture, and is working with another US federal agency to implement a confidential reporting system for offshore incidents and near misses. The Bureau has also established the Ocean Energy Safety Institute within Texas A&M University. This will research longer-term issues such as risk, reliability data, and the best available and safest technologies.

The US Coast Guard service has issued guidance on additional fire and explosion assessments that it would like to see introduced, and has highlighted safety culture issues. Two response consortia have been established in Houston (MWCC and Helix). The International Association of Oil and Gas Producers (formerly OGP) has set up consortia at four international locations to provide emergency response support. API and the Norwegian Technology Centre, which develops NORSOK standards, have updated standards for drilling and well control, and have made their safety standards

freely available. “Detailed assessments of fire and explosion lessons from Macondo have been made and are finding their way into designs,” Bjerager added.

CSB investigated the BOP failure after DNV GL’s forensic examination. It concluded that regulations should be updated to identify critical parts of safety equipment and ensure that these all operate reliably. The co-chairs of the Deepwater Horizon Commission maintain the oscaction.org website to monitor progress on implementation of its recommendations, and issue annual progress reports. “Generally it concludes that industry and the executive branch of the US government have done a good job implementing recommendations, but US Congress lags behind,” said Bjerager.

Global responseThere has been change elsewhere. The European Union (EU) is adopting a safety-case approach similar to that of the UK, for all EU offshore developments. Australia has expanded coverage of its regulator, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA), to address drilling and environmental impacts because of Montara and Macondo, and to move closer to the goal of having a single offshore regulator.


PHOTO DNV GLGRAPHIC DNV GL, BIG PARTNERSHIP

6 ‘Deepwater Horizon fire and explosion issues’, UK HSL, 2014


“The UK and Norway believe their goal-setting approaches were not challenged by Macondo, but that many detailed aspects of drilling safety needed enhancement. The UK Health and Safety Executive (HSE), Norway’s Petroleum Safety Authority and the International Association of Oil and Gas Producers are working on these issues,” Bjerager said.

“Still, some important recommendations for the US regulatory system have yet to be adopted. The US appears not ready to adopt mandatory risk assessment with a risk target nor, at least as a partial step, to nominate safety-critical items with defined performance standards.”

Download the report at: dnvgl.com/macondo


70 –

60 –

50 –

40 –

30 –

20 –

10 –

0 –

Num

ber

of r

eco

mm

end

atio

ns

Recommendation count and types from ten major Macondo inquiriesData source: Norwegian Oil and Gas Association

Key: (see page 15 for abbreviations)

1 BP investigation

2 National Commission report

3 US Coast Guard investigation

4 BOEMRE report

5 SINTEF report

6 Norway Petroleum Safety

Authority report

7 OGP oil spill response

8 OGP report

9 National Academy of Engineering

10 Proposals from OLF

1 2 3 4 5 6 7 8 9 10

Capping and containment

Cementing

Competency

Environmental impact

Management systems

MODU* design

N/A

Oil spill response

Unified command

Well control

Well planning and execution

Working environment

*MODU: Mobile offshore drilling units

Report number

18 PERSPECTIVES

REGULATORY OUTLOOK

PHOTO DNV GL

STUDY PROJECTS REGULATORY FUTURERegulators and operators can learn from each other to reduce the risk of major incidents, says Graham Bennett

Oil and gas industry regulatory regimes are evolving, allowing both active and planned offshore operations to progress efficiently, while ensuring that due attention is given to health, safety and environmental (HSE) performance.

Discussion of the history and future for regulation around the world is described in a new DNV GL report: ‘Regulatory Outlook: The way forward for offshore regulatory safety regimes’. It outlines possible future developments and what DNV GL believes an effective offshore safety regime should look like.

Occupational safety has improved greatly in recent years, explained Graham Bennett, business development manager for UK & Sub Saharan Africa, DNV GL - Oil & Gas. “Our analysis of data from companies’ annual and sustainability reports shows a ten-fold reduction in reportable incidents per 200,000 man hours over the last 20 to 30 years when lost-time injuries are excluded. The industry deserves to be congratulated for this.”1

“However, while occupational safety as measured by reportable incidents has improved in general, major accidents and near-misses still happen, and more could be done to reduce the risk

of these occurring,” he stressed. “The industry should also strive to learn and share more from what it is successful at in major accident management.”

Analysis of the European Union (EU) major accident report system (MARS)2 and the US Environmental Protection Agency risk management plan-star (RMP-Star)3 databases shows a steady frequency of major accident events and no reduction in their level of severity.

Similarly, insurance broker Marsh4 examined insurance claims for property damage losses in the hydrocarbon industry between 1974 and 2013, and found no clear reduction since 1994.

Statistics from the country performance project of the International Regulator’s Forum (IRF) for Global Offshore Safety also supports this picture. Fatalities per million hours worked from 2008 to 2012 do not show a unified trend towards global improved performance.

Global-local challengeThe findings of more than 20 major inquiries following the 2010 Macondo incident are summarised in a newly published DNV GL report (see page 14). “The data points to the need to identify new ways to reduce major accident hazards,” Bennett said. “Social, political

We have been

able to present...

our views on

what an effective

offshore safety

regime should

look like”

Graham Bennett, business development manager for UK & Sub Saharan Africa, DNV GL - Oil & Gas

“

1 DNV GL internal study on occupational HSE performance, data based on the annual reports and sustainability reports of key companies, 20142 ‘Offshore major accident safety: Is SEMS enough?’, Pitblado R and Bjerager P; DNV GL. OTC-130TC-P-412-OCT, 20133 ‘Accident epidemiology and the RMP rule: Learning from a decade of accident history data for the US chemical industry’, Kleindorfer PR;

Lowe RA; Rosenthal I; University of Pennsylvania, Wharton Business School, Final report for cooperative agreement; R-83033301, 20074 ‘The 100 Largest Losses – 1974-2013, 23rd edition’, Marsh & McLennan Companies, 2014


REGULATORY OUTLOOK

and economic frameworks for regulation vary considerably worldwide and may evolve in different directions,” he added. “Therefore, oil and gas companies operating globally must not only increase oversight where requirements are less developed, but also proactively align global operating standards and procedures towards unique local regulatory changes.”

In its ‘Regulatory Outlook’ report, (download at: dnvgl.com/regoutlook)DNV GL assesses offshore regulatory frameworks in Mexico, Brazil, the EU, Angola and Australia. It also covers the Arctic from an international regulatory perspective, as well as nationally for Alaska (US), Canada, Greenland, Norway and Russia.

“The report discusses possible scenarios for regulatory developments in these jurisdictions. The company mapped these scenarios to its safety model5 to identify key factors that could help reduce major accident hazards (MAHs) in each region.

The DNV GL safety model incorporates six interconnecting performance levers and dependencies which, if recognised, should lessen the probability of a major accident occurring. In no particular sequence, these are:

■ Existence of performance-based regulations and independent verification

■ Clear roles and responsibilities for safety, including ensuring that stakeholders share common goals

■ Information sharing from monitoring safety performance

■ Advanced barrier management that includes mitigating as well as preventive barriers

■ Stakeholder access to a tool that records up-to-date risk identification and provides a complete view of risk exposures for an asset, asset cluster, project or company

■ Interaction between people, technology and the organisation.

“We cannot say with certainty how national or regional regimes will develop, but we have been able to present a range of possible future developments and our views on what an effective offshore safety regime should look like,” Bennett said.

A global safety scenario, where each major accident is reviewed and lessons learned by all regulators and industry players, includes many elements of DNV GL’s preferred approach. This scenario also envisages large fines for MAHs, and harmonisation of HSE regimes to reduce compliance costs and administration.

GAUGING THE PATH OF REGULATIONFour fundamental scenarios for the development of regulatory regimes are analysed in DNV GL’s new ‘Regulatory Outlook’ report.

Global safety: Each major accident in the industry is reviewed and learned from globally by both industry players and regulators.

New moral imperative: Governments recognise society's unwillingness to tolerate major accidents, so operators' responsibility for safety is increased.

Operators rule: Governments are reluctant to improve their regulatory capability, and rely on operators’ global experience.

Local safety: Regulators focus on improving their own safety regimes.

These scenarios correspond to varying degrees with current regulatory regimes and are not intended as accurate illustrations of the future. However, they are a useful starting point for discussing how safety regimes should develop, particularly when used in conjunction with DNV GL’s safety model.

5 ‘Enhancing offshore safety and environmental performance’, DNV GL, 2013. An updated version of the DNV GL safety model in this publication is being published in 2015 in the DNV GL report ‘Offshore safety – initiatives to improve major accident hazard performance’

20 PERSPECTIVES

REGULATORY ADVICE HELPS NEW OPERATOR TO STAY LEANExternal planning expertise assisted Lundin Norway’s transition from capex to opex in developing Brynhild

PHOTOs LUNDIN NORWAY

A ROADMAP TO FIRST OIL

Staying lean and mean organisationally, while meeting regulatory requirements in two nations, was a priority for Lundin Norway when developing its Brynhild field offshore Norway. The field is the company’s first development as an operator.

“We are a relatively small company and we want to build the competences of our own team while also using external providers to do non-core business tasks. This avoids us having to build huge support functions internally,” chief operating officer, Erik Sverre Jenssen explained.

Brynhild is not a complex development, but it does involve numerous stakeholders and crosses international boundaries. It is a subsea tie-back to the Pierce field, operated in the UK sector by Enterprise Oil. The production facility for both Brynhild and Pierce is the Haewene Brim FPSO, operated by Bluewater on behalf of Shell.

Lundin contracted DNV GL to help develop a ‘ready-for-operation’ (RFO) roadmap early in its journey to first oil, which flowed in December 2014, from Brynhild.

“DNV GL has good oversight of regulatory requirements in Norway and the UK,” said Torstein Sanness,

who became chairman of Lundin Norway in April. “We were open in saying that this was not going to be about what is nice to have. It had to be just enough so that the next time we do it in Norway or the UK, we pass with flying colours. We did not want to have any extra flowsheets, bureaucracy or procedures.”

A clean start Lundin saw Brynhild as a perfect project for its ‘lean and mean’ philosophy, while evolving from pure exploration to become a fully integrated exploration and production company.

“Having no project management systems installed was a challenge, but also an opportunity, because we did not carry a backlog of existing bureaucracy,” said Jenssen. “It was a rare chance to define something from scratch.”

When the Brynhild project was established in 2011, Lundin Norway had limited people with operational experience, observed Kari Nielsen, head of field operations. “We had to build the Operations organisation, and to establish all necessary systems to become a prudent operator.”

DNV GL was engaged to help Lundin Norway establish a plan for Brynhild Operations. The scope involved Lundin and DNV GL creating a well-defined

Most companies

these days are

actively seeking

good advice

because no-one

has any choice

but to do things

smarter and

cheaper”

Torstein Sanness, chairman, Lundin Norway

“


A ROADMAP TO FIRST OIL

Sailout in 2013 of the manifold template for Brynhild, a subsea tie-back to the Pierce field with production for both handled by the Haewene Brim FPSO vessel

transition path, including identifying the most common and support tasks essential to an operator along the road to planned production.

The roadmap was developed based on reference documentation from Lundin, regulatory requirements and DNV GL’s experience and knowledge of operational best practice. This allowed Lundin to simultaneously build an organisation and to deal with documentation and other administrative tasks.

“During Phase I in early 2012, DNV GL helped us to identify a high level plan highlighting the most important tasks and obstacles to planned production start,” Nielsen recalled. “Later that year, we started Phase II, and DNV GL made a detailed plan for RFO and ensured all regulatory requirements were met.”

Elements considered in the RFO roadmap to meet regulatory requirements included tasks and obstacles under key headings such as: handover to Operations; the first period of production; operation; logistics management; and technical integrity, inspection, monitoring, maintenance and modifications. Primary activities analysed in detail under each of these headings included: production operations; development; reservoir; drilling and completion; facilities; health, safety, environmental and quality (HSEQ);

and logistics. Support activities were also covered.

“When DNV GL created the detailed plan for RFO, our Operations team consisted of only three people, so DNV GL’s involvement was fundamental,” Nielsen said. “The plan was good and we followed it. It was also used as the basis for planning development of the Edvard Grieg field offshore Norway.”

Learning points“The process of starting up a new operation or organisation was more complex than expected,” said Nielsen. “We needed DNV GL’s experience in that phase. The commissioning phase had also not been clearly defined, so the plan helped with that.”

Asked whether insights from the experience with the Brynhild roadmap for RFO are applicable in other projects, Sanness said: “In the past, if you had some good ideas, they were hard to sell. Most companies are now actively seeking good advice because no-one has any choice but to do things smarter and cheaper.”

Lundin Norway will continue to learn from Brynhild, Sanness added: “We have a slogan in this company: ‘There is no best procedure, but there is always a better practice’. There will be a continuous

Kari Nielsen, head of field operations, Lundin Norway

follow-up on what we have established, a continuous learning experience. Then we will want to implement any changes not only on Brynhild, but also for Edvard Grieg and for any other projects that we have in the pipeline.

“We are in this for the long haul. Let us take this opportunity while the oil price is low to get some necessary changes and keep optimistic about proving up new resources.”

22 PERSPECTIVES

NEW DRIVE TO TRIM NEWBUILD COSTSSouth Korean shipyards support a project to promote standardisation in engineering and construction of offshore oil and gas installations

FLOATING PRODUCTION

PHOTO CORBIS

Using international

standards more

widely... has

potential to

significantly

reduce cost levels”

Hans Petter Ellingsen, group leader for offshore risk advisory, Korea, DNV GL - Oil & Gas

“

South Korean shipyards are market leaders for construction of floating and fixed offshore oil and gas installations. They are world-class competitively, but even greater savings could result from addressing variations in owner, operator and regulatory requirements during engineering and construction for such projects.

Less familiar specifications and processes result in “re-work, delays and misunderstandings in yards worldwide,” observed Hans Petter Ellingsen, group leader for offshore risk advisory, Korea, DNV GL - Oil & Gas.

Operators address this through on-site teams of up to 300 people, and sometimes move units from Asian yards for final completion closer to the final destination or offshore.

DNV GL has initiated a JIP to establish a new international industry standard for offshore oil and gas projects.

The JIP is based on discussions between Hyundai Heavy Industries (HHI) and DNV GL. It is now being discussed with operators and other Korean fabricators, such as Samsung Heavy Industries (SHI) and Daewoo Shipbuilding and Marine Engineering Company (DSME), and with

the Korea Offshore and Shipbuilding Association and the Korea Marine Equipment Research Institute.

“We hope that it will lead to standardisation that helps to reduce design periods and minimise design changes,” said JongBong Park, senior executive vice president (SEVP) and chief operating officer of HHI’s offshore and engineering division. “Other potential benefits include reduced material costs resulting from decreased expenses for material purchase, manufacturing and testing. A shortening of materials purchasing lead-time would be expected as more could be held in stock. Surplus materials could be used in other construction projects.”

“The complexity and range of standards, regulations and requirements create a big challenge for contractors,” observed Dr Younsang Won, SEVP and head of offshore production operations, SHI, and chairman of DNV GL’s Korea Technical Committee. “It takes much effort to clarify and implement these requirements, and there are sometimes omissions, inconsistencies and misinterpretations. This can generate a lot of changes and revisions, even when the design has already been frozen and fabrication/installation has started.”

Issue 01 | 2015 | PeRsPeCTIVes 23

FLOATING PRODuCTION

EXPERT ADVICEOPENS THE DOORTO BIG SAVINGS

One fabrication yard that consulted DNV GL experts expects cost savings of 30% to 50% from offshore projects equipment being ordered to maritime rather than offshore specifications.

The ‘maritime approach’ model to executing offshore projects has been successful in the North sea, a challenging regulatory environment.

Brazil and Africa are less challenging in this regard. Therefore, they are even more suitable — where possible — for taking this approach. In these cases, standardised ship solutions can be used.

It takes in-depth knowledge to predict how regulators will decide whether a system comes under maritime or offshore oil and gas rules. DNV GL’s experience of classification and independent third-party verification helps companies to understand and comply with regulations and to determine when a maritime approach may be possible and desirable.

“Using international standards more widely in offshore oil and gas projects has potential to significantly reduce cost levels. It will also reduce the risk of project overruns, without compromising quality or safety," stressed Ellingsen.

A maritime approachOne example of cost reduction through standardisation comes from Norway, where DNV GL has studied1 savings from applying maritime rules from classification societies and maritime flag authorities – where possible – to offshore projects.

This ‘maritime approach’, accepted for certain floating offshore units in Norway, has allowed hulls and/or marine systems to be classified under a maritime/classification regime rather than the country’s Petroleum Safety Authority regulations. Maritime Class rules exist for many types of floating units. Shelf- state legislation will normally accept use of a flag/Class approach to areas of maritime character.

“Designers, yards and suppliers work more efficiently when projects apply standards with which all players are experienced,” Ellingsen explained. “Our ambition is to establish a standard for oil and gas projects that builds on the well-established approaches of, and

experiences with, classification. Industry estimates for potential cost savings on construction of installations range well into double-figure percentages.”

Sung-Geun Lee, EVP, chief strategy officer, DSME, agreed that applying maritime regulations to floating units simplifies engineering, procurement and construction procedures.

“Standardisation through a maritime approach is welcomed, but should be approached with caution,” he advised. “Individual operators and companies have varying regulations and specifications, as well as operation philosophies, and these may not be fully satisfied through maritime standards.”

The risk is that a common standard developed on the basis of harsh environments, such as the North Sea, could end up raising the requirements for “more benign” seas, he added. “We must also account for local content regulation in various regions.”

That said, he hoped that the JIP will provide the initiative for the standardisation movement in the offshore industry.

For more information, visit: dnvgl.com/offshorestandardisationJIP

1 ‘Use of DNV GL classified units on Norwegian Continental Shelf: The maritime approach’, Erik A M Henriksen, DNV GL, May 2014

Future newbuild FPSOs could be among offshore oil and gas projects to benefit cost-wise if a new international standard for engineering and construction can be agreed

24 PERSPECTIVES

Even a straightforward

project can become

significantly more

complex and costly if

timeframe constraints

do not allow best use

of skills and resources”

Richard Harrison, engineering manager— installation analysis and sealine design,Saipem Ltd

REDUCING PIPELINE EXPENDITURE

A recent survey of pipeline industry players asked what drives capital and operating expenditure (capex and opex) for complex projects as developments in deepwater and more extreme environments become more common. The aim was to encourage better models of project planning.

The feedback from 52 respondents across 37 companies at DNV GL’s Pipeline Day in October 2014 was presented and discussed in February at the annual Pipeline Integrity Forum in London, UK.

Time was a constant theme in survey responses, both the time allotted and taken for projects, as well as the timing of key phases. One clear message was that poor project management and lack of detailed front-end engineering design (FEED) due to time constraints can be key inflators of pipeline budgets.

Richard Harrison, engineering manager — installation analysis and sealine design, Saipem Ltd, said: “Even a straightforward project can become significantly more complex and costly if timeframe constraints do not allow best use of skills and resources to plan and prepare for risk management of critical aspects of the project.”

It was felt that innovation has helped to stabilise or slightly reduce opex, but responses also suggested that, in general, the industry had underestimated lead-times for technology to become operational.

“While some respondents felt there has been insufficient project quality control, others said there has been a substantial increase in documentation due to internal and external procedural requirements,” explained Ali Sisan, DNV GL’s business development manager for pipelines in the UK & Sub Saharan Africa.

To optimise planning and management of installation, Dan Lee, engineering manager with Heerema Marine Contractors UK Ltd, added: “Improvements identified on the pipelay system, procedure and execution should be implemented at the earliest opportunity to improve efficiency and reduce schedule risk without compromising on safety.”

Harrison flagged up benefits to be gained from an engineering, procurement, construction, and installation (EPCI) contracting strategy that communicates commercial considerations to EPCI contractors. “It allows synergies to be developed throughout the course of the project phases. A well-defined invitation-to-tender scope provides the best opportunity for the EPCI contractor to assess the risks and provide an optimum value for taking this risk.”

Technical challenges naturally increase in deepwater and harsh conditions. “To efficiently execute another deepwater pipeline project, lessons learned from previous projects must be captured and documented, and applied at different phases of the project,” Lee explained.

Skills and capacity shortages, and higher salaries, were among eight key drivers

PHOTO SHUTTERSTOCK

“

SURVEY EXPLORESPIPELINE PROJECTCAPEX AND OPEXKey findings could help control cost in projects and operation


REDUCING PIPELINE EXPENDITURE

RECOMMENDEDPRACTICESREVISEDPipelines must meet changing regulatory and business demands, and respond to technological advances. Recommended practices (RPs) should also respond to change. Latest revisions to two RPs for the sector will ensure that best practice is observed and that decision-makers have the most appropriate guidelines.

Revisions to DNV-RP-F101 aim to introduce improved and updated methods to estimate and manage threats to the integrity of ageing pipelines. The approach involves thorough probabilistic evaluation and corrosion development evaluations over time. Assessment techniques include calculating the pressure resistance of pipelines affected by patterns of internal corrosion such as long axial grooving.

Updates to the RP for integrity management of submarine pipeline systems, DNV-RP-F116, present more comprehensive guidelines on carrying out risk assessments. They will provide a valuable framework to deliver risk evaluations for planning integrity management activities.

of capex, and seven of opex, that emerged from the survey.

Harrison also expressed concern that knowledge transfer between generations was at risk as experienced employees retire or leave, and a large knowledge gap becomes apparent with less experienced and recent graduate recruits. “Without a detailed and robust information knowledge database, the application of lessons learned, and re-application of know-how, will depend on the continuity of personnel in each organisation.”

Business and regulatoryComplex and changing fiscal and regulatory regimes figured among both capex and opex drivers. Companies questioned the usefulness of ever-increasing guidelines and procedures.

Respondents felt that, post-Macondo, industry and investors require increased assurances on risk mitigation, and that greater scrutiny of design and financial processes consequently raise costs. Allied issues raised included demand for greater robustness and operational reliability, both putting upward pressure on projects in the opex phase.

It was generally held that business models need revisiting, and that pipeline owners should take a longer-term view of operations, particularly for strategic management of ageing assets.

For example, respondents suggested that more joint ventures (JVs) should be considered in response to complexity and geographical span among larger pipeline projects. However, they conceded that costs can creep up due to JV stakeholders’ different approaches delaying final investment.

“Our research will play a key part in redefining future business models to increase opportunities for the entire industry,” said Asle Venås, DNV GL's global pipeline segment director. “By taking a longer-term view to reduce cost drivers, the industry can promote efficiency, create more transparent interfaces and connect experts to increase competency and assurance globally.” DNV GL will be running a number of workshops throughout 2015 to understand more fully how the industry can drive down the lifecycle cost of pipeline projects.

Download the full survey results at: dnvgl.com/pipelinesurvey

26 PERSPECTIVES

SUSTAINED TECHINNOVATION CANBEAT CHEAP OILThe risks of not pursuing new technology are too rarely considered, says a leading expert on commercialising innovation

TECHNOLOGY

INFOGRAPHIC BIG PARTNERSHIP

The journey between concept and commercialisation of technologies and processes is often called 'the valley of death'. It has many pits into which innovation can disappear.

These may include lack of affordable capital at critical stages; difficulty attracting the right technical or business skills; competition; regulation; and adverse industry and economic trends.

Happy indeed is the oil technology start-up that finds a major customer who believes in its product, provides an opportunity for live trials, and actually places orders that validate the technology and generate essential cash flow to ramp up production.

Even if they make it through to trials in the real field environment, potentially game-changing innovations may never be tested to all extremes, thus limiting their market potential. There is natural nervousness among operators and contractors that trials will disrupt production or introduce potential health, safety and environmental risks.

Professor James Woudhuysen, author, journalist and public speaker on innovation, observes this and other kinds of caution about innovation across many industries. He urges companies to take a wide view of the advantages and disadvantages of encouraging the commercialisation of potentially game-changing inventions.

“The risks of not pursuing new technology are too rarely considered,” he said. “The costs of adopting it are usually overcome by the higher productivity it affords, and the competitors it drives out of business.”

What the industry wantsMajor energy companies spend heavily on R&D to boost competitiveness and reduce risks and/or costs of exploration and production. They also tap into innovation by contractors.

When the corporate venture wings of supermajors look elsewhere for technology, they still want solutions that are “big enough to move the needle” inside their own companies, Geert van de Wouw, managing director of Shell Technology Ventures explained in a 2013 interview.1

Lower oil prices could make it harder for new tech to reach market, Woudhuysen noted. "The short-termism that afflicts much of industry today will slow the journey. Yet, only sustained innovation can beat low prices and general price volatility.”

He suggested that appropriate responses could include finding new funds for R&D; leadership and tenacity in the face of setbacks; a disciplined approach to experiments and prototyping; and “faith in human prowess”. >

Short-termism…

will slow the

journey from lab

to drill platform”

James Woudhuysen, former professor of forecasting and innovation at De Montfort University, UK

“

1 ‘Where the “smart” money goes’, Petroleum Review, September 2013


TECHNOLOGY

PUTTING OUR EXPERTIsE TO ThE TEsT

NORWAY

NEThERLANDs

GERMANY

CzECh REPUBLIC

UK

Us

sINGAPORE

DNV GL operates 18 laboratories across three continents, offering a broad range of testing services. By combining advanced testing with technical expertise and industry standards, we help customers to apply technology safely, efficiently and cost effectively.

We simulate hydrocarbon single or multiphase flow, and calibrate flow meters of 1" – 32" diameter

We run the world’s largest fire and explosion test site

Our facilities mimic all relevant corrosive conditions such as sea water, H2S and CO2

We weigh modules up to 20,000 tonnes

We investigate more than 100,000 marine organisms

We test power transmission and distribution equipment rated up to 1,200 kilovolts

DNV GL investigates 70% of onshore pipeline failures in North America

Our experts perform more than 50,000 standard mechanical tests

We can cycle full-size offshore components to fatigue failure, allowing life extension by more than ten years

Environmental laboratory services

Flow testing and calibration

Failure investigation

Materials qualification and testing

Full-scale testing

Hardware-in-the-loop (HIL) testing

Whether we are investigating failure of inch-long valves, conducting full-scale validation tests to a load of 2,500 tonnes, or retrieving seabed organisms, we provide global insight and local expertise for safer, smarter and greener operations.

Battery and energy storage testing

High-power/high-voltage testing

Key

28 PERSPECTIVES

TECHNOLOGY

Collaborative ventures, such as joint industry projects (JIPs) and national initiatives, are two responses. DNV GL has proposed 60 new JIPs to tackle oil and gas industry technical challenges this year.

Companies can reap rewards from collaboration before any technology becomes fully commercial. For example, the GBP1.13 million (USD1.67m) Fullwave Gamechanger research project, coordinated by the sector’s international Industry Technology Facilitator (ITF), aims to transform subsurface imaging capability.

This involves 15 major oil and gas operators working with Imperial College, UK. Launched in 2012, it remains in development, but is already benefitting backers.

“Some oil company participants can already pinpoint significant capital savings on field appraisal projects, through avoiding unnecessary and expensive drilling expenditure by using our technology to better target hydrocarbons in their reservoirs,” said project director Professor Mike Warner, Imperial College.

Standards benefit technologyLow predictability of quality control criteria throughout the oil

and gas supply chain is another challenge to new technologies.

Woudhuysen points out that there are hurdles to achieving standardisation in many spheres of commercial and public life. “Problems can emerge when endless negotiations around standards block expeditious progress,” he said.

Still, he noted, the automotive and aerospace industries have benefitted from some standardisation in manufacturing.

Oil and gas companies seek to follow this example. Standardisation of specifications for materials, components and interfaces helps innovators in many ways. It becomes easier to define markets, to meet the requirements of a broader range of potential customers and regulatory regimes, and to achieve economies of scale in production and in sourcing components and sub-assemblies. Standardised quality assurance processes also bring clarity about the hurdles that new technologies will have to jump.

One example is standardisation of steel forgings, a high priority initiative by the Norwegian Oil and Gas Association (Norsk Olje & Gas) and the Society of Petroleum Engineers, US.

In response, DNV GL, alongside 21 companies represented by key operators, contractors and manufacturers, has developed a new recommended practice (RP), DNVGL-RP-0034, on ‘steel forgings for subsea application’.

These are the building blocks of subsea components and are often tailored to meet end-users’ specific requirements. Diversity in material specification results in long delivery times and repeated follow-ups by all involved.

The RP complements existing industry codes for subsea equipment and its implementation will provide for reduced lead-time, enhanced stock-keeping, interchangeability of forgings, and will help improve and obtain consistent quality.

“Our initial research found that differences in forging specifications are mainly due to more stringent requirements rather than unique specifications,” said Bjørn Søgård, segment director, subsea with DNV GL.

“Unifying these differences into an acceptable common forging specification can reduce the lead-time by up to a year. This will make a positive contribution to the overall economics of a project," Søgård explained.

DNV GL laboratories, including our environmental laboratory in Høvik, take part in many oil and gas industry innovation programmes

PHOTO DNV GL


sOUR FLUIDs AND PIPELINE INTEGRITYSour service fluids cause a reduction in fracture toughness of pipeline material due to hydrogen-assisted cracking. A DNV GL JIP is developing a methodology to evaluate fracture toughness using a single edge notched tensile (SENT) test. Eight participants are involved; others would be welcome.

SENT tests simulate loading and crack depths similar to pipelines under normal operating conditions. DNV GL laboratory research shows that results can vary widely dependent on numerous environmental and test parameters.

The project will provide better understanding of key parameters known to impact fracture-toughness test results. This will allow development of a guideline that could become a recommended practice to provide technical, logistical and financial savings to the industry.

Contact: Steven Chongproject [email protected]

GETTING hYDROGEN INTO GAs GRIDsNatural gas transmission and distribution system operators (TSOs and DSOs) want to increase renewable gas access to infrastructure. However, no guidelines exist on how to prepare networks for injecting hydrogen (H2) from renewable sources.

DNV GL has initiated HYREADY, a global JIP, to encourage development of practical processes and procedures. It will deliver broadly-supported guidelines for what TSOs and DSOs should consider when planning to prepare grids reliably for H2.

The two-year JIP involves four work packages: transmission systems; distribution systems; end-user infrastructure and appliances (domestic and industrial); and design of a hydrogen injection facility. Technology providers and stakeholders from the natural gas value chain have expressed interest. The project remains open to others.

Contact: Onno Florissonproject [email protected]

sTREAMLINING sUBsEA DOCUMENTATIONDocumentation demanded for subsea operations is time-consuming, complex and costly to deliver. Amid low prices, pressure is growing to address this.

DNV GL has taken a major step forward in addressing this global issue with the first draft of a recommended practice. These guidelines aim to standardise the vast set of documents for designing, approving, manufacturing, verifying, operating and maintaining subsea equipment. It is part of a wider drive to streamline the global subsea sector.

The next phase of the JIP will extend the current scope to include subsea, umbilicals, risers and flowlines (SURF), and to further address documentation requirements between contractors and suppliers. We have also released a recommended practice on standardising steel forgings for subsea (page 28).

Contact: Jarl S Magnussonproject [email protected]

JOINT INDUSTRY PROJECTS

Working with its customers, DNV GL runs joint industry projects (JIPs) to develop new solutions, standards and recommended practices (RPs) that tackle the industry’s technical challenges. The company has proposed 60 joint industry initiatives in 2015, providing an independent arena for collaboration and innovation. Below are examples of current JIPs and the RPs that they have generated or aim to.

COLLABORATION ACHIEVES MORE

Our Singapore laboratories are involved in the SENT JIP alongside the DNV GL Singapore Deepwater Technology Centre and our laboratories in Ohio, US.

The Singapore research and testing facility at Gul Circle was tripled in size last year as

part of DNV GL's commitment to being an integral part of this growing marine and offshore cluster. Structured in four service areas, the laboratories undertake a broad range of services – from microstructure to mega structure, and from laboratory testing to field services.

sINGAPORE LABs OFFER WIDE RANGE OF sERVICEs

30 PERSPECTIVES

UNCONVENTIONALSTO SHRUG OFFCURRENT BLUESThe US industry still faces a bright future, says Richard Green

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PHOTO SHUTTERSTOCK

An oil price above USD100 per barrel (/b) drove exponential growth of US unconventional oil production until late 2014. Oil prices have more or less halved since then, but this output is still expected to continue rising through mid-year.

Some estimates1 project US crude oil output from all sources will top 10 million barrels per day (b/d) during 2015, largely because of still rising unconventional oil output. This would match or exceed Saudi Arabia’s recent daily oil output, which was itself near record levels.2

All things considered, US unconventional reserves could provide a secure and robust source of hydrocarbons for more than a century at current extraction rates, even with existing technology. Their contributions to security and affordability of supply remain a game-changer for US industry and consumers, and for global energy markets.

The challenge aheadOperators admittedly face market pressures. There has been a surge in non-OPEC oil production in recent years while key markets in developed and developing economies have slowed, stagnated or fallen.

Saudi Arabia has maintained oil output and will presumably keep pressuring

US producers to drop production. The Middle Eastern state’s oil pumping costs are low, but the social cost of its oil production exceeds USD100/b. It uses cash reserves to cover the difference between that and oil prices.

Global oversupply has depressed exploration for US unconventional oil, while production has also been affected. Growth in US unconventional oil output in April 2015 was expected to be the slowest in more than four years.3 It is still growing though, and one reason to be optimistic about its long-term future is that the industry entered the oil price slump in good shape.

Sector is resilientThe sector has proved it can deliver spectacular production growth through technical and operational innovation, replication and learning. Around 50% of oil-rich shale plays are now profitable at USD50/b. Quicker drilling and well completion times have protected profit margins. In the Eagle Ford region, rig efficiency is 18 times greater than in 2008, and 65% more than in 2013.

Drilling efficiency is rapidly approaching a plateau, however. Most operators will need other ways to drive cost efficiency

The sector has

proved it can

deliver spectacular

production growth

through technical

and operational

innovation,

replication and

learning”

Richard Green, senior principal consultant — unconventional oil and gas, DNV GL

“

1 'Annual energy outlook 2015', US Energy Information Administration (EIA), April 2015 2 ‘Oil gains as dollar decline bolsters appeal to investors’, Bloomberg, 24 March 20153 EIA Drilling Productivity Report, March 2015


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and/or to increase production. Subsurface well optimisation is one. Innovations here include better down-hole monitoring, reduced fracturing pressure and chemical use, improved well-spacing, non-aqueous fracturing, and enhanced oil recovery methods such as CO2 injection. Buoyed by high profit margins, operators have also invested in horizontal drilling and more efficient management of surface assets.

There is substantial upside to be gained from reducing cost in the highly fragmented supply chain. We expect that performance-enhancing measures, such as better management of suppliers, and greater standardisation, will become more common.

Unconventional oil and gas operators can bounce back nimbly from a period of low oil prices. Onshore operators have an advantage over offshore counterparts in that land rigs can be quickly re-deployed in favourable economic conditions. Though drilling of new onshore wells has slowed, there is a stock of drilled but uncompleted wells ready to be re-activated. Rig supply will likely fall throughout 2015.

On current scenarios, we now expect a period of healthy consolidation in the US unconventional oil and

gas sector. Producers in the 50% of plays that involve less hydrocarbon-rich rock need sustained prices of USD70–80/b to service debts. Small, heavily indebted players are particularly vulnerable to lower oil prices, and producers are planning for 12 to 18 months before a significant oil price rise. It is crucial for companies to use this period of reduced activity to review their operations and create robust strategies for safe, sustainable and efficient long-term operations.

Regulation is evolvingWhile it adjusts to market conditions, the industry is getting to grips with the demands of regulation and risk management. The regulatory regime is driven by federal agencies and implemented by 50 equivalent bodies in states, which sometimes add requirements. Safety and environmental regulation are largely prescriptive, relatively easily enforced and cover various industries.

Multiple agencies have considered adopting risk-based regulation that would include event likelihood, recognise a limit to resources and prioritise events by risk criteria. This seems less likely to be broadly adopted, though efforts are underway to address cross-jurisdictional regulatory differences.

We also see scope for government and industry to accept more self-regulation and certification to ensure that operational risks in unconventionals are adequately managed.

Regulation and operators’ practices, have mitigated most environmental, safety (process and occupational) and operational risks. However, there is continued opposition to hydraulic fracturing based on real or perceived risks stemming from its operations and from its social impacts. Bans are in force in some cities, such as Denton, Texas; in some counties; and in some states, such as New York and Vermont.

DNV GL is well positioned to help alleviate the environmental, safety and social risks that may impact sustainable development. We are seeing continued demand for services related to optimisation of surface assets, subsurface innovation/optimisation, implementation of our software tools and third-party verification.

This massive hydrocarbon market will also require innovative business development approaches, including using industry expertise to collaborate with customers on problem-solving through challenge selling, cross-organisational services and joint industry project solutions.

Documents

PERSPECTIVES Issue 01/2015