Drilling for excellence on the North Sea

INFORMATION FROM DNV TO THE OIL, GAS AND PROCESS INDUSTRIES
NO. 3 – AUGUST 2003
Oil & Gas News
Canadian Natural Resources
<strong>Drilling</strong> <strong>for</strong> <strong>excellence</strong>
on the North Sea
Plat<strong>for</strong>m
Southern
■ Norsk Hydro optimises the Ormen Lange field
Ninian
■ BP cuts costs in the North Sea
view Aerial
■ ENI E&P questions the benefits of subsea processing
Chevron:
■ Statoil doubles the Åsgard C condensate export Photo:

A new risk reality
in the North Sea
Increased frequency
of gas
releases has lead
to greater risk of
large accidents
on the Norwegian
Sector,
according to the
Norwegian Petroleum
Directorate.
The operators
are now faced
with the challenge
of turning this trend around.
With mature fields, the oil companies in
the North Sea have to balance the tasks of
reducing costs while at the same time maintaining
or even improving safety. Internationally
the whole industry is in a period
of restructuring with mergers, internal reorganisations
and other initiatives to optimise
the efficiency.
The process is being watched with eagleeyes
by shareholders, the finance market
and society in general. These stakeholders
all demand robust economic results together
with the maintenance of high safety standards.
DNV believes the key to handling this
new scenario is to build safety improvement
work into the drive <strong>for</strong> higher efficiency. We
assist our customers in making use of a riskbased
approach to management, planning
and execution of projects, operations and
maintenance. The results of this approach
are encouraging – more streamlined organisations
can be better at achieving high reliability
and safety levels, when streamlining
leads to more focus on the critical elements
of the facilities and their operations.
Successful implementation of a riskbased
approach depends on how the organisation
views this matter and on the provision
of leadership. There is considerable
potential <strong>for</strong> operators to succeed if they
are willing to recognise the new risk reality
and do something about it.
Magne Tørhaug
Director of DNV Consulting Norway
2 OIL & GAS NEWS 3 2003
Optimising production
New concept increases
investment returns
The Norwegian state-owned company Petoro is evaluating
how investments in the new Smart Operations concept can
increase rates of returns from their offshore assets in the
North Sea. Preliminary results indicate a potential revolution
in the way future offshore operations could be per<strong>for</strong>med.
Smart Operations is a term used to
describe concepts where real time
data, new in<strong>for</strong>mation and technology
solutions are used to optimise offshore
field operations on the Norwegian
Continental Shelf. The methodology is
designed to offer complementary
opportunities to existing improvements
within drilling, production optimisation
and reservoir management,
as well as operations and maintenance.
Petoro project manager Roy Ruså
says: “We believe that Smart Operations
has the potential to improve drilling
operations and regularity, increase
hydrocarbon recovery, optimise offshore
operations and maintenance,
and improve the health, safety and
environmental indicators – but we are
not yet sure to what extent.
“The results of the project so far
have significantly enhanced our basis
<strong>for</strong> decision support. Smart Operations
can accelerate and increase the recovery
of hydrocarbons throughout the
life cycle of a field. Consensus has
been reached in Petoro on the focus
of the field prioritisation of our Smart
Operations investments. The improvements
that this concept will bring to
certain assets could revolutionise the
way our offshore operations will
be per<strong>for</strong>med in the future.”
Ruså continues: “There are considerable
opportunities to enhance the
existing infrastructure through the use
of fibre optic cables, SOIL, modern
instrumentation and control systems,
with improved and prolonged hydrocarbon
production as a result. New
investments are required to obtain the
full benefits, but we believe that the
payback period <strong>for</strong> investments in
Smart Operations is less than one year
in a large number of cases. We also
expect the rewards to be long-lasting
throughout an extended life cycle.”
DNV has been assisting Petoro in
assessing the effect of Smart Operations
on their portfolio, and preparing specific
business cases. This included
benchmarking and ranking the
licences relative to various economic
and technical key per<strong>for</strong>mance indicators.
DNV project manager Art Kenich
says: “The effects of new in<strong>for</strong>mation
and technology solutions, such as realtime
monitoring and operation per<strong>for</strong>med
from remote land-based locations
supported by risk centred maintenance
programmes, have a tremendous
potential. Reduced operating
costs, improvements in production
regularity, hydrocarbon recovery, production
life and safety are just some of
the benefits that will result in exceptional
levels of return <strong>for</strong> comparatively
small investments.”
Petoro has been successful in presenting
business cases to partners in
strategically selected licences as a support
to their ongoing work. Consequently,
several operators and partners
have agreed to include investment
provisions <strong>for</strong> Smart Operations in their
future plans.
For more in<strong>for</strong>mation, please contact:
Art.Kenich@dnv.com
FACTS
Petoro is a state-owned limited
company responsible <strong>for</strong> the
Norwegian State’s financial interests
on the Norwegian Continental Shelf.
One of Petoro’s main objectives is to
be a proactive partner in strategically
important licenses and originate and
develop initiatives like Smart
Operations that will lead to
maximised rates of return on the
State’s investments.

<strong>Drilling</strong> <strong>for</strong> <strong>excellence</strong>
on the North Sea
Aerial view of Ninian Southern Plat<strong>for</strong>m CNR´s Casey McWhan, left, and Richard Turnbull.
DNV is working with North
Sea newcomer CNR International
(UK), a subsidiary of
Canadian Natural Resources
(CNR) to help the company
realise its goal of <strong>excellence</strong>
in integrity management.
CNR is one of a number of Canadian
independents helping to maximise
the life of, and return from, mature
North Sea fields. Since entering this
market over two years ago, the company
has acquired several assets in the
East Shetland Basin, including three
plat<strong>for</strong>ms in the Ninian field and the
single plat<strong>for</strong>m in the Murchison
field.
Casey McWhan, CNR’s offshore
production operations manager,
believes there are a lot of opportunities
in the North Sea. “At present this
market is very similar to what Western
Canada was when CNR started out in
the early ‘90s. When the big oil companies
can no longer make a profit
due to high operating costs, we are
successful as we are a streamlined,
profit organisation that is focussed on
efficient delivery,” he says.
Ambitious plans
CNR expects to be in the North Sea
until at least 2020 and has ambitious
plans <strong>for</strong> its acquisitions. These plans
can only be realised with an assurance
of process integrity delivered through
a fully developed and implemented
strategy focussing on the specific
needs of mature assets.
However, like other new investors
in the North Sea, CNR found that
its recently acquired assets were not
in excellent condition due to cost
cutting measures and reduced maintenance
by the previous operators.
Richard Turnbull, facilities manager
at CNR, says: “Ninian South had problems
in areas we didn’t expect when
we took it over. Some of the lower risk
systems, such as the processed oil system,
gave us some problems.”
CNR has learnt quickly from this.
“We’re safety conscious and are now
refocusing on changes to the integrity
management system that was in the
process of being revamped. In recognition
of the business-critical nature
of the integrity management, we’ve
elected to bring that focus internally,”
says Turnbull.
Integrity management
DNV is able to provide a multi-discipline
integrity management team with
responsibility <strong>for</strong> offshore facility
integrity. Personnel from DNV Consulting
and DNV Technology Services
are now working offshore and within
CNR’s Aberdeen headquarters to help
the operator develop and implement
a detailed integrity management
system <strong>for</strong> all its North Sea assets.
Photo Caption: Chevron
This follows on from an earlier DNV
review of CNR’s integrity management
arrangements <strong>for</strong> pressure systems
and technical support during an
intensive programme of process
reconfiguration and inspection on the
Ninian South plat<strong>for</strong>m. “We had DNV
assist us in the early days of the Ninian
South problems. We saw a professionalism
there that could help us,” says
Turnbull.
DNV is currently assisting CNR to
identify needs and define best practices
<strong>for</strong> integrity management, and
CNR aims to have their new system
in operation by the end of this year.
“I don’t think that appropriate
focus has previously been placed
on integrity management by the
regulatory authorities, but its going to
become more prominent. We want to
make sure we run our plat<strong>for</strong>ms safely
and efficiently,” adds Casey McWhan.
For more in<strong>for</strong>mation, please contact:
Martin.Munday@dnv.com
Stuart.D.Brewer@dnv.com
OIL & GAS NEWS 3 2003 3

The Ormen Lange field is the
first deepwater discovery to be
developed offshore Norway.
Located 130 km from the west
coast of Norway at a depth of
about 1,000 metres, the development
of this field represents
a major challenge <strong>for</strong> the operator,
Norsk Hydro.
The challenge lies in the combination of
deep water, extremely rough seabed conditions,
a long tie-back distance and
demanding weather conditions.
DNV is involved in several aspects of
this project during the development
phase, such as looking <strong>for</strong> the best subseato-land
solution and setting reliability targets
<strong>for</strong> critical components.
Looking <strong>for</strong> the optimal subsea-to-land
solution
During the concept selection phase a
number of ways of developing the field
were considered, ranging from innovative
solutions like a novel subsea-to-land concept
that included subsea wells tied back
to an onshore terminal, to a more traditional
deepwater concept consisting of an
offshore processing facility with wet and
4 OIL & GAS NEWS 3 2003
Offshore operations
Optimising
solutions <strong>for</strong>
Ormen Lange
Setting reliability goals <strong>for</strong> the
downhole safety valves
The gas production at Ormen Lange is
scheduled to start in 2007. Due to the prolific
reservoir conditions, it is planned to
use big bore tubing (9 5/8 inch), high
flow rate wells (13 MSm 3 /day), with 7 inch
downhole safety valves <strong>for</strong> the first eight
pre-drilled wells, thereby limiting the
number of wells to be drilled later in the
life of the field.
The plans are to install deep set subsurface
safety valves as far down as 1,600m
in the wells. This unusual depth is due to
the risk of hydrate <strong>for</strong>mation after a shutdown.
The drive <strong>for</strong> reduction in well
count and the introduction of some ele-
The development of the Ormen Lange field represents a major challenge <strong>for</strong> the
operator Norsk Hydro.
dry wells. In December 2002, Norsk Hydro
announced the decision to use the subseato-land
concept.
The project has now moved into the
front-end engineering and design (FEED)
phase. DNV is assisting Norsk Hydro and
its partners to find the optimal subsea-toland
solution from the reservoir to the
market. This involves a holistic reliability
and maintainability assessment of the well
and downhole completion system, subsea
production and control system, onshore
plant processing system with utilities and
the transportation system to the consumers.
Several solutions will be assessed
based on a cost-benefit approach.
Deepwater exploration and develop-
ments of uncertain technology will make
the field very sensitive economically to
downhole valve failures. The qualification,
there<strong>for</strong>e, of these valves is particularly
important.
The valves are subject to the qualification
scheme in DNV’s Recommended
Practice RP-A203 Qualification Procedures
<strong>for</strong> New Technology. DNV is managing the
qualification, planning and execution of
three types of deep-set 7 inch downhole
safety valves in co-operation with the
industry. Identification of possible failure
modes and documentation of the margins
<strong>for</strong> safe operation based on experience,
numeric analysis and/or in-house tests are
being worked on, which combined with
ment is characterised by a high level of
investment, a long payback time and
potentially severe business disruption
costs. Engineers and managers are often
required to make million-dollar decisions
in situations where there is no time to
explore the upsides and downsides of
those decisions. Quantitative reliability
and maintainability assessments allow <strong>for</strong>
cost-benefit analyses. Through quantification
and factual understanding of the
costs and benefits of a design change,
sound economic decisions can be made.
For more in<strong>for</strong>mation, please contact:
Fredrik.Gustavsson@dnv.com
Remi.Eriksen@dnv.com
third-party tests comprise a systematic
qualification approach that goes beyond
traditional and current practice.
The main source of documented experience
is based on the database ‘WellMaster’,
which is a worldwide experience database
<strong>for</strong> downhole completion equipment.
It includes in<strong>for</strong>mation about downhole
safety valves from all manufacturers over
the past two decades. This experience is
used to set the reliability goals <strong>for</strong> the
Ormen Lange downhole safety valves and
to justify their selected configuration from
a range of options.
For more in<strong>for</strong>mation, please contact:
Ole.Rengard@dnv.com
Illustration: Hydro Media

BP cuts costs in the North Sea
As mature fields in the North Sea struggle to sustain profitability in a declining oil and
gas market, BP is finding success with help from DNV, using a risk-based approach.
Declining oil and gas reserves in the
North Sea have driven operators to evaluate
alternative scenarios, including sales,
outsourcing, changing or re-engineering
installations, as well as enhancing the
effectiveness of their organisation.
To meet the requirement of reducing
operating expenditures by 30% to reach
top quartile, BP decided to start a wide
range of improvements in the organisation.
As part of this process, BP is selling
the Gyda field to Talisman Energy and is
re-engineering the operation of the Ula
and Valhall fields.
DNV has assisted BP by per<strong>for</strong>ming
risk-based screening and analysis of activities
related to production support, both
on land and offshore. Measures to
increase operational safety and production
have also been identified. The project
identified options to streamline work
processes and technical modifications to
reduce annual operating costs by as much
as 10–15%.
Questioning the cost and
benefit of subsea processing
Compared to traditional
methods of handling well fluids
to onshore terminals, subsea
processing has the potential
benefit of increasing reservoir
recovery rate and reducing capital
expenditures.
However, this method can expose companies
to uncertainties in future cash flow.
DNV has been assigned by ENI E&P to
evaluate the pros and cons of subsea processing.
Subsea processing can significantly
reduce initial investments by removing the
need <strong>for</strong> expensive, manned floaters. A
concept based on subsea processing offers
companies the option to provide addition-
The use of risk-based methodology has
proven to be a very effective means of:
• Ensuring that high health, safety and
environmental standards are sustained
and leveraged throughout the change
process
• Identifying substantial economic opportunities
• Involving the organisation in the
change process
Together, BP and DNV are now preparing
to implement the identified opportunities
by developing new and more effec-
al energy to the well stream to reach treatment
facilities both offshore and onshore.
This is particularly important <strong>for</strong> the
exploitation of hydrocarbon reservoirs in
deepwater, where the need to provide
energy to the well stream is higher. The
potential benefit is realised by increasing
the ultimate recovery and acceleration of
the production.
In subsea processing, the anticipated
equipment per<strong>for</strong>mance and associated
operating costs are subject to uncertainty.
This is <strong>for</strong>tified in deepwater where subsea
interventions become more expensive and
are associated with longer waiting times
<strong>for</strong> the required intervention vessels. The
fundamental question about the process is
whether the reduced capital expenditure
of a subsea processing system is justified
Photo: BP
BP is reengineering the operation of the Ula (left) and Valhall (right) fields in the North Sea.
tive processes <strong>for</strong> BP’s new onshore organisation
in Norway.
DNV is also using its competence to
provide assistance on similar projects <strong>for</strong>
other major oil and gas companies
operating in the North Sea. These reengineering
projects are utilising DNV’s
risk-based methodology and broad range
of safety, asset operation and process
mapping services.
For more in<strong>for</strong>mation, please contact:
Hans.Petter.Ellingsen@dnv.com
by higher operational expenditures compared
to traditional systems.
ENI E&P, through its Norwegian affiliate
Norsk Agip, has asked DNV to develop
and demonstrate a methodology to assess
alternative subsea processing systems during
feasibility and concept screening phases.
The results of the studies will enable
ENI E&P to predict lifecycle cost elements
and associated uncertainties. It will identify
the main contributors to lifecycle costs,
and evaluate the costs and benefits of
different subsea processing systems and
maintenance strategies to find the most
optimal solution.
For more in<strong>for</strong>mation, please contact:
Ole.Rengard@dnv.com
Remi.Eriksen@dnv.com
Photo: BP
OIL & GAS NEWS 3 2003 5

6 OIL & GAS NEWS 3 2003
Onshore operations
First European gas export facility
on its way Statoil has on behalf of the Snøhvit licensee group commenced preparations
<strong>for</strong> the first export facility <strong>for</strong> liquefied natural gas (LNG) from the Snøhvit
field in the Barents Sea. The marine operations are expected to pose various
risks, and DNV has been assigned to verify all these operations during installation
in cooperation with London Offshore Consultants.
FACTS
INSTALLATION SCHEDULE
The Snøhvit gas field is located
70˚41’ north and 23˚30’ east in the
Barents Sea, approximately 140 km
north-west of Hammerfest in
Norway.
All verification work will be completed
in accordance with the DNV
Rules <strong>for</strong> Planning and Execution of
Marine Operations.
Preassembled units and racks
fabricated at Farbcom in Belgium
and two large slug catchers
fabricated at Heerema in Holland
will be transported to Hammerfest
during summer 2004.
The barge is being built by the Izar
Fene yard in Spain, and is expected
to be launched in August 2003.
It will then be towed to Dragados in
Cadiz, Spain to be grounded and
outfitted with most of the main
equipment (26,000 tons) <strong>for</strong> the
LNG plant and then transported to
Hammerfest within August 2005.
The LNG plant is scheduled to be
completed by the end of 2005.
Shipment of gas from the Snøhvit
field starts in 2006, and will
continue <strong>for</strong> more than 20 years.
The Melkoya Island near Hammerfest where the first European gas export facility will be located.
The Snøhvit gas field consists of a subsea development
connected to an LNG plant located
onshore near Hammerfest in Norway. Huge
volumes of gas deep beneath the Barents Sea
will be piped ashore, cooled down and shipped
by special gas carriers to Spain and the US.
Complicated transport
Approximately 60,000 tonnes of steel (prefabricated
units/modules) will be transported to
Hammerfest from various fabrication sites in
Europe. The transportation distances from the
fabrication sites are long and the transport is
complicated with short operational windows.
Statoil has there<strong>for</strong>e decided to make use of
third-party expertise to verify the various
marine operations. They have assigned this
work to DNV and London Offshore Consultants.
The risk picture
The marine operations are expected to pose
various risks during construction and installation.
Changing environmental conditions such as
wind, snow, temperature and light may be a
challenge during the shipment of 60,000 tonnes
of steel from Southern Europe to the northern
part of Norway, a distance of approximately
2,600 nautical miles.
Various risks are being considered related to
load-out, transportation and lifting. Possible
damage to equipment, vessel and personnel
safety issues are being considered. In addition,
the potential <strong>for</strong> delays and financial loss in
completing the plant are being analysed.
The verification task covers approval of engineering
documentation, procedures and survey
of load-out/float-out of all major structures,
tows and sea transportations, all heavy lift operations
and installation of permanent and temporary
anchor systems, bollards and winches.
There is an option <strong>for</strong> installation of subsea
structures, all rig moves on the field and installation
of pipelines and additional equipment
onshore.
Bror.Berge@dnv.com
Photo: Statoil, June 2003

Floating units in operation
Doubling Åsgard C
condensate export
The daily export rate of Statoil’s Åsgard C in
the North Sea is due to double from 2005.
DNV has helped to quickly identify the optimal
upgrade solution <strong>for</strong> increased availability.
In 2005, Statoil plans to store the condensate
production from the Kristin field
onboard the floating storage unit (FSU)
Åsgard C, which is currently receiving the
condensate production from the Åsgard
field. This will lead to a doubling of the
received production. Due to more frequent
shuttle tanker visits, the availability
of the FSU’s tandem discharge operation
will become vulnerable.
The selection of the optimal solution to
improve the availability of the unit
requires consideration of a complex set of
parameters, including:
• Technical feasibility
• Time window <strong>for</strong> conversion
• Personnel and environmental risk
• Production availability
• Regulatory issues
• Political issues
Statoil wanted an early
decision on the best course of
action <strong>for</strong> the upgrade, and
assigned DNV to assess the
conversion alternatives.
A major challenge of this
project was the limited timeframe
available to provide
documentation to evaluate the numerous
decision parameters and their interaction.
To meet this tight deadline, DNV made
use of resources from its various business
areas to implement a multidiscipline project,
including legislative studies, risk
assessment, and a cost/benefit study
assessing cost and time <strong>for</strong> optional conversion
alternatives. In addition, DNV
per<strong>for</strong>med stability, strength and fatigue
calculations. Through this approach, the
project was executed and concluded
Life cycle management
<strong>for</strong> FPSOs improved
DNV enhances its services <strong>for</strong>
deepwater production systems
to ensure operators benefit
from cost-efficient maintenance
and integrity management.
By combining current structural re-analysis
systems and risk-based inspection services
with software solutions developed by
DNV Software, DNV is now in a unique
position to work with the operators of
deepwater floating, production, storage
and offloading units (FPSOs) and tension
leg plat<strong>for</strong>ms (TLPs) to ensure cost-efficient
maintenance and integrity management.
The enhanced services will concentrate
on the following:
• Development of services related to
structural re-analysis systems to ensure
that unified services can be provided
locally in the operator’s home markets.
• Development of risk-based inspection to
include corrosion degradation models
that can be used in numerical prediction
of inspection intervals <strong>for</strong> FPSOs in
hot environments. This tool allows <strong>for</strong> a
proactive approach that will <strong>for</strong>ecast
future problems and allow different
repair strategies to be investigated to
obtain minimum maintenance costs <strong>for</strong>
steel replacement, coating repair and
anode replacement.
Photo: Arvid Steen
From 2005 the condensate production from the Kristin field
will be stored onboard the floating storage unit Åsgard C
(Jorunn Knutsen) in the North Sea.
within 20 days, providing Statoil and
its partners with a complete and independent
basis <strong>for</strong> a high-level business
decision.
Speaking to Oil&Gas News, Statoil
project manager Arve Lerstad says:
“DNV’s expedite deliverance of this comprehensive
study has made it possible to
continue the project on schedule. They
have done a very good job.”
Hans.Kristian.Danielsen@dnv.com
• Enhancement of inspection philosophy
based on present practice <strong>for</strong> inspection
and survey used by class.
• Further development of maintenance
strategy based on corrosion and coating
status determined by inspection.
Henning.Carlsen@dnv.com
OIL & GAS NEWS 3 2003 7

Health, Safety and Environment
DONG E&P expands
in the North Sea
As DONG Exploration & Production
(E&P) expands into the
North Sea, they are updating
their management system to
meet Norwegian regulatory
requirements and reflect
changes in DONG’s organisation.
DONG E&P has a long-term strategy of
enhancing their oil and gas activities in
the North Sea. Their growth strategy
involves partnerships in major fields,
operatorship of licences and smaller producing
fields. DNV is now assisting DONG
E&P in updating their management
system to fulfil the regulatory requirements
<strong>for</strong> offshore operation in Norway,
as well as to reflect changes in DONG’s
organisation.
Norway boosts HSE competency
Norway is the first country in
the world to offer a comprehensive
regulations awareness programme
<strong>for</strong> operators on the
Norwegian continental shelf.
The rising number of serious incidents
and accidents on the Norwegian shelf during
the past years has sparked this project,
which aims to increase the understanding
of Norwegian regulations and promote
greater awareness of health, safety and
environment (HSE).
Called Regulations Competency (RVK),
the project provides thorough in<strong>for</strong>ma-
DNV (Det Norske Veritas) is an independent,
autonomous Foundation working to safeguard life,
property and the environment. DNV comprises
300 offices in 100 countries, with 5,500 employees.
DNV services to the oil, gas and process industries
We help clients within the following service areas:
• Safety, health and environment
• Qualification and innovation
• Verification and classification
• Asset operations
• Enterprise risk management
8 OIL & GAS NEWS 3 2003
The Norwegian regulatory requirements
in health, environment and safety
are mainly functional, demanding operators
to take a proactive role in establishing
a structured approach <strong>for</strong> policies, objectives,
plans, execution and follow-up.
The regulations have a strong focus on:
• Safety culture and the emergency preparedness
organisation
• Barrier philosophy
• Employee participation and safety-delegate
function
• Acceptance criteria to be set in the management
system
• Environmental issues
• The duty of ensuring that sub-contractors
are complying with the requirements
• Documentation of continuous improvements.
DONG E&P has made a frame agreement
with DNV to provide quality, health,
tion to key players in the Norwegian
petroleum industry. It is backed by
national authorities and labour organisations.
RVK meets the requirements set <strong>for</strong>th
by the Norwegian government in 2001,
when it called <strong>for</strong> a comprehensive safety
and environment report every fourth year
and the implementation of specific safety
measures by the petroleum industry during
this interval period.
RVK partners include the Norwegian
Pollution Control Authority, Petroleum
Directorate, Health Inspectorate and
labour organisations such as the Federation
of Trade Unions (LO) and Federation
of Oil Workers.
Oil & Gas News
is a newsletter published by
Det Norske Veritas, Business Areas
Technology Services and Consulting
to the Oil, Gas and Process
Industries.
It is distributed to DNV customers
and stations worldwide. It is also
available at DNV’s web site.
Please direct any enquiries to your
nearest DNV station, or Oil & Gas
News e-mail: Oil&GasNews@dnv.com
Photo: Niels Åge Skovbo
The DONG operated Siri plat<strong>for</strong>m is being
reconstructed to start producing from the two
new satellite fields Nini and Cecilie.
safety and environmental-related services.
The work is undertaken through an integrated
joint team ef<strong>for</strong>t involving key
personnel from DONG E&P and DNV.
It covers the exploration, appraisal, development,
operation and decommissioning
activities related to the life-cycle of a field.
DNV is making use of a cross-functional
team from consulting and technology
services.
Espen.Cramer@dnv.com
RVK provides in-depth knowledge and
a common understanding of the health,
safety and environment regulations relating
to the petroleum industry. Built on
the active use of the regulations, RVK is a
plat<strong>for</strong>m granting continuous improvement
of HSE, economy and other values.
DNV is a key provider of lecturers to
the project and maintains that the success
of the initiative is largely dependent on
the “at work” application of knowledge
gained through a RVK course.
For more in<strong>for</strong>mation about the RVK project:
www.rvk.no
Espen.Cramer@dnv.com
Published by Corporate
Communications.
Editor: Beate V. Ørbeck
DNV
Head Office Norway
NO-1322 Høvik, Norway
Tel: +47 67 57 99 00
Fax: +47 67 57 99 11
Updated list of all regional offices at
DNV’s web site: www.dnv.com
7,000/08-2003 Design: DNVE Graphic Communications 0307-001 Print: GAN Grafisk