SMART WORKING DELIVERS GREATER COST SAVINGS PERSPECTIVES Oil and gas industry insight Issue 01 | 2015 ALSO INSIDE: LEARNING FROM MACONDO A summary of 21 inquiries into the incident lags up key ways to reduce the risk of a repeat of the tragedy STAYING LEAN AND MEAN Lundin Norway called upon external expertise to get ready for operation on its journey to irst oil DEEPWATER SOLUTIONS Industry experts highlight strategies to boost returns on deepwater mega projects in a constrained climate
Transcript
SMART WORKING
DELIVERS GREATER
COST SAVINGS
PERSPECTIVESOil and gas industry insight Issue 01 | 2015
ALSO INSIDE:
LEARNING FROM MACONDO
A summary of 21 inquiries into
the incident lags up key ways to reduce the risk of a repeat of the tragedy
STAYING LEAN AND MEAN
Lundin Norway called upon external expertise to get ready for operation on its journey to irst oil
DEEPWATER SOLUTIONS
Industry 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 relect DNV GL’s views.
Experts from Shell, BP, FMC Technologies and Maersk Drilling highlight how standardisation, collaboration and better management of
technology deployment can boost inancial returns on deepwater mega projects in the new economic climate
10 Managing cost
Understanding the most signiicant root causes of cost inlation is vital to the viability of new offshore projects
14 Learning from Macondo
Five years after the Macondo incident in the Gulf of Mexico, a new summary of 21 inquiries into the tragedy lags up key ways to reduce the risk of a similarly major event happening
18 Regulatory outlook
Regulators can reduce the risk of major incidents by learning from each other
20 A roadmap to irst oilLundin Norway drew on DNV GL’s regulatory know-how when preparing operations for irst oil on the Brynhild ield
22 Floating production
Standardisation can deliver substantial savings
when fabricating newbuild loating unitswithout compromising quality and safety
24 Reducing pipeline expenditure
Pipeline 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 projects
Pipeline cracks, gas grid hydrogen and subsea documentation are among the themes targeted
by DNV GL’s current JIPs
30 Platform
The 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
conident about reaching proit targets plan different cost-management measures, taking a long-term approach to riding out the storm. ‘Proit 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 eficiency 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 justiications made for inal investment decisions. We also explain how our approach to selecting standards can support the industry to achieve greater cost eficiency 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 inlated 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
ield 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 eficiencies, while improving safety and reliability in projects and operations. I hope you ind the features in this edition of PERSPECTIVES useful as we tackle these challenges head on.
Elisabeth Tørstad
CEO, 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
DNV GL will play a combined role as independent veriication body (IVB) and third-party design veriication partner for Wintershall Norge AS on the Maria ield 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 irst oil is scheduled. It covers the subsea, umbilicals, risers and lowlines (SURF) elements of the project.
The IVB model includes all phases from design through to commissioning. The
third-party veriication 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 veriication is well known in the UK sector, but is less used in Norway. By being able to deliver both IVB and
third-party design veriication, 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 irst offshore platform installation using advanced dynamic positioning (DP) loatover technology. The successful installation took place in the eastern waters of the South China Sea for the
Enping oilields.
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 loatover 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 WARRANTY
CONTRACT WIN
OFFSHORE 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 lowlines and 20 manifolds complies with recognised guidelines, standards and the customer’s internal requirements. The lowlines and manifolds will connect 59 wells to two
very large crude carriers, currently being converted into turret-moored loating production storage and ofloading 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 beneits to the country and build upon our competence within Angola, supporting customers with a more proactive delivery of local MWS.”
Classiication and veriication work is underway with Eni Muara Bakau B.V. on the Jangkrik loating production unit (FPU) project offshore Indonesia. Jangkrik is one of the country’s irst deepwater gas developments.
In a joint venture partnership with state-owned PT. Biro Klasiikasi Indonesia (BKI), DNV GL will deliver veriication services for topside facilities and maritime classiication of the FPU – this is the start of our irst 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 Paciic 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 ield 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 suficient response capacity.”
To support the outcomes of the position paper, DNV GL is also initiating a new joint industry project (JIP) which will address qualiication 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
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 ield 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 ield 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 conirmed at the time of PERSPECTIVES going to print that it would proceed with the USD6bn development of a deepwater ield in the Gulf of Mexico alongside Chevron, Statoil and Nexen.2
DEEPWATER PROJECTS
FACE UP TO COST
CHALLENGE
Collaboration, 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 inding 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 signiicant factor in future project economics and inal 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 eficiency.”
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 ield 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
ISSUE 01 | 2015 | PERSPECTIVES 7
THE FUTURE OF DEEPWATER MEGA PROJECTS
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 standardisation
From 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 speciications 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 quantiied 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 beneits, including indirect cost reductions such as
safety through familiarisation,” he added.
Deepwater operators are aware of these potential beneits. 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’ ‘beneits 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 coniguration 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 technology
Technology 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 reined, 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-beneit 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
THE FUTURE OF DEEPWATER MEGA 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
ISSUE 01 | 2015 | PERSPECTIVES 9
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 eficiency 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 ield developments, including deepwater mega projects. “That time is now over and we need
to turn the industry’s creativity and energy towards more cost-eficient and reliable solutions,” he urged.
FMC Technologies has chosen DNV GL to perform independent third-party veriication 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 eficiency.
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.
THE FUTURE OF DEEPWATER MEGA PROJECTS
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 DRIVER
Deep understanding of what inlates cost is vital to control ield 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, inance director, Sakhalin Energy
“
PHOTOs SAKHALIN ENERGY
The offshore oil and gas industry has
regularly failed to stay within budgets
and timetables set out in inal investment decisions (FIDs) for ield 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 inlation of this kind accounts for only a third of increased project expenditure seen in recent years.”
Identify the right targets
Scope inlation 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 signiicantly on proitability.”
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 lat 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 justiications made for FIDs.
“Many projects fail to adequately address project risk during the planning phase and often have insuficient 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
ISSUE 01 | 2015 | PERSPECTIVES 11
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 inlation is rising customisation. A lack of replication or standardisation adds to complexity,” she added.
Romsom warned that, beyond a certain point, additional speciications 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 speciications dilute focus, introduce needless complexity, limit supply-chain eficiency or increase exposure during project execution and/or operations. We are seeing many examples of unnecessary and costly spec-inlation.”
A risk-based response
In 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
conlicting and superluous requirements that affect cost. These suggestions will
cover company internal speciications as well as regulations.
“Working with the industry has shown us potential areas for signiicant 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 speciications when building a rig to operate in harsh environments. It found that a similar
safety speciication 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-speciic requirements where prudent and practical. The method involves comparing each of the applicable company speciications against Class rules and voluntary notations.
Where Class rules hold an equivalent
standard of safety, company speciications could be eliminated with no impact on risk. Application of Class rules provide a cost reduction compared with company speciications 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 inlation” driving up costs’, Paul Cleary, The Australian, 9 March 2015
GRAPHIC BIG PARTNERSHIP
A core reason
for scope
inlation is rising
customisation. A
lack of replication
or standardisation
adds to
complexity”
Elisabeth Rose, head of section, project risk management, DNV GL - Oil & Gas
“
ISSUE 01 | 2015 | PERSPECTIVES 13
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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Co
st p
er
ba
rre
l o
f o
il (
US
D)
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 speciications 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-eficiency and safety impacts of incorporating such additional requirements.”
Share knowledge early
DNV 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 inal decisions,” explained Rob van Velden, inance director at Sakhalin Energy. The Russian operator faces signiicant 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 veriication of pre-FEED (front-end engineering design)
and FEED is one possible solution to identify issues that arise during these
stages and remedy laws in them,” Rose observed.
Once sub-optimum speciications enter the supply chain, it can take signiicant effort and time to correct them.
Examples in subsea have shown that correcting a speciication throughout the supply chain can take eight months, adding to lead time and costs.
“Standardisation that allows transparent certiication 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 TAKES
LESSONS FROM
MACONDO
Marking the ifth anniversary of the Macondo incident in the Gulf of Mexico, a summary of inquiries into the tragedy lags 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 indings 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 learned
Broad 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 sealoor. DNV GL made detailed recommendations2 regarding BOP
design and operation issues.
Among the most high proile 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 ire and >
LEARNING FROM MACONDO
TAble DNV GL, BIG PARTNERSHIP
ISSUE 01 | 2015 | PERSPECTIVES 15
LEARNING FROM MACONDO
CATEGORIES OF FINDINGS AND RECOMMENDATIONS
FROM 21 INQUIRIES INTO THE MACONDO INCIDENT
No. Inquiry PreventionBOP design
and operation
Contain and
respond
Management
and cultureUS regulatory
International
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
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 legacy
DNV GL’s summary of inquiries lags 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 recertiication; 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 deining 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 conidential 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 ire 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
ire and explosion lessons from Macondo have been made and are inding 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 response
There 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.
LEARNING FROM MACONDO
PHOTO DNV GLGRAPHIC DNV GL, BIG PARTNERSHIP
6 ‘Deepwater Horizon ire and explosion issues’, UK HSL, 2014
ISSUE 01 | 2015 | PERSPECTIVES 17
“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
deined performance standards.”
Download the report at: dnvgl.com/macondo
LEARNING FROM MACONDO
70 –
60 –
50 –
40 –
30 –
20 –
10 –
0 –
Nu
mb
er
of
reco
mm
en
da
tio
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
Uniied 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 FUTURE
Regulators 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 eficiently, 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 uniied trend towards global improved performance.
Global-local challenge
The indings 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
ISSUE 01 | 2015 | PERSPECTIVES 19
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 veriication
■ 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 identiication 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 ines for MAHs, and harmonisation of HSE regimes to reduce compliance costs and administration.
GAUGING THE PATH
OF REGULATION
Four 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 LEAN
External 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 ield offshore Norway. The ield is the company’s irst 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 oficer, 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 ield, 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 irst oil, which lowed 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 lying colours. We did not want to have any extra lowsheets, 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 deine something from scratch.”
When the Brynhild project was established in 2011, Lundin Norway had limited people with operational experience, observed Kari Nielsen, head of ield 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-deined
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
“
ISSUE 01 | 2015 | PERSPECTIVES 21
A ROADMAP TO FIRST OIL
Sailout in 2013 of the manifold template for Brynhild, a subsea tie-back to the Pierce ield 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 irst period of production; operation; logistics management; and technical integrity, inspection, monitoring, maintenance and modiications. 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 ield 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 deined, 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 ield 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 COSTS
South 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
signiicantly
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 loating and ixed 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 speciications 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 inal completion closer to the inal 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 oficer of HHI’s offshore and engineering division. “Other potential beneits 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 ADVICE
OPENS THE DOOR
TO 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 speciications.
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 classiication and independent third-party veriication 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 signiicantly reduce cost levels. It will also reduce the risk of project overruns, without compromising quality or safety," stressed Ellingsen.
A maritime approach
One example of cost reduction through standardisation comes from Norway, where DNV GL has studied1 savings from
applying maritime rules from classiication societies and maritime lag authorities – where possible – to offshore projects.
This ‘maritime approach’, accepted for certain loating offshore units in Norway, has allowed hulls and/or marine systems to be classiied under a maritime/classiication regime rather than the country’s Petroleum Safety Authority regulations. Maritime Class rules exist for many types of loating units. Shelf- state legislation will normally accept use of a lag/Class approach to areas of maritime character.
“Designers, yards and suppliers work more eficiently 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, classiication. Industry estimates for potential cost savings on construction of installations range well
into double-igure percentages.”
Sung-Geun Lee, EVP, chief strategy oficer, DSME, agreed that applying maritime regulations to loating units simpliies 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 speciications, as well as operation philosophies, and these may not be fully satisied 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 classiied 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 beneit cost-wise if a new international standard for engineering and construction can be agreed
24 PERSPECTIVES
Even a straightforward
project can become
signiicantly 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 inlators of pipeline budgets.
Richard Harrison, engineering manager — installation analysis and sealine
design, Saipem Ltd, said: “Even a straightforward project can become signiicantly 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 insuficient 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 identiied on the pipelay system, procedure and execution should be implemented at the earliest opportunity to improve eficiency and reduce schedule risk without compromising on safety.”
Harrison lagged up beneits 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-deined 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 eficiently 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 EXPLORES
PIPELINE PROJECT
CAPEX AND OPEX
Key indings could help control cost in projects and operation
ISSUE 01 | 2015 | PERSPECTIVES 25
REDUCING PIPELINE EXPENDITURE
RECOMMENDED
PRACTICES
REVISED
Pipelines 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 regulatory
Complex and changing iscal and regulatory regimes igured 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 inancial 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 inal investment.
“Our research will play a key part in redeining 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 eficiency, 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 TECH
INNOVATION CAN
BEAT CHEAP OIL
The 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; dificulty attracting the right technical or business
skills; competition; regulation; and adverse industry and economic trends.
Happy indeed is the oil technology start-up that inds 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 low to ramp up production.
Even if they make it through to trials in the real ield 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 wants
Major 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 aflicts 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 inding 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
ISSUE 01 | 2015 | PERSPECTIVES 27
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, eficiently and cost effectively.
We simulate hydrocarbon single
or multiphase low, and calibrate low meters of 1" – 32" diameter
We run the world’s largest ire 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 qualiication 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 beneitting backers.
“Some oil company participants can already pinpoint signiicant capital savings on ield 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 beneit 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 beneitted from some standardisation in
manufacturing.
Oil and gas companies seek to follow this example. Standardisation of speciications for materials, components and interfaces helps innovators in many ways. It becomes easier to deine 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’ speciic requirements. Diversity in material speciication 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 speciications are mainly due to more stringent
requirements rather than unique
speciications,” said Bjørn Søgård, segment director, subsea with DNV GL.
“Unifying these differences into an
acceptable common forging speciication 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
ISSUE 01 | 2015 | PERSPECTIVES 29
SOUR FLUIDS AND
PIPELINE INTEGRITY
Sour service luids 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 inancial savings to the industry.
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.
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 irst 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 lowlines (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).
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 ield services.
SINGAPORE LABS OFFER WIDE RANGE OF SERVICES
30 PERSPECTIVES
UNCONVENTIONALS
TO SHRUG OFF
CURRENT BLUES
The US industry still faces a bright future, says Richard Green
PLATFORM
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 ahead
Operators 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 resilient
The 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 proitable at USD50/b. Quicker drilling and well completion times have protected proit margins. In the Eagle Ford region, rig eficiency is 18 times greater than in 2008, and 65% more than in 2013.
Drilling eficiency is rapidly approaching a plateau, however. Most operators will need other ways to drive cost eficiency
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
ISSUE 01 | 2015 | PERSPECTIVES 31
PLATFORM
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
proit margins, operators have also invested in horizontal drilling and more eficient 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 signiicant 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 eficient 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 certiication 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 veriication.
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.
