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September 2010 Issue 26
Deepwaterexploration - afterDeepwater Horizon
Electromagneticsurveys - how goodare they really?
When to tellcolleagues to "getover it"
How to cut drilling costs 50% Does the industry need standard IT architecture? Hosting documents on the cloud
™
Associate MemberSilver sponsor
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Sept 2010 Issue 26
September 2010 - digital energy journal
Digital Energy Journal is a magazine for oil andgas company professionals, geoscientists, engi-neers, procurement managers, IT professionals,commercial managers and regulators, to helpyou keep up to date with developments withdigital technology in the oil and gas industry.
Subscriptions: Apply for your free print or elec-tronic subscription to Digital Energy Journal onour website www.d-e-j.com
Printed by Printo, spol. s r.o., 708 00 Ostrava-Poruba,Czech Republic. www.printo.cz
Digital Energy Journal213 Marsh Wall, London, E14 9FJ, UKDigital Energy Journal is part of Finding Petroleumwww.findingpetroleum.com www.digitalenergyjournal.comTel +44 (0)207 510 4935Fax +44 (0)207 510 2344
Editor Karl Jefferyjeffery@d-e-j.com
Consultant editorDavid Bamford
Technical editorKeith Forwardforward@d-e-j.com
Finding Petroleum London ForumsThe oil industry and carbon - September 15Exploration, Technology and Business - October 7The 'capability crunch' November 23Collaboration and the digital oilfield - December 9Advances in Seismic - January 25, 2011
Social networknetwork.findingpetroleum.com
Advertising and sponsorshipAlec EganTel +44 (0)203 051 6548aegan@onlymedia.co.uk
1
Cover photo: ROV control station onboardDiscoverer Inspiration as the pilots install thecapping stack July 12, 2010 © BP p.l.c
David BamfordConsultant Editor, Digital Energy Journal
Highlighting newinnovation
I noticed in today’s Times (29th July
2010), in the Business Editor’s commen-
tary, the comment that the Governor of
the Bank of England “has an undisguised
preference for those who make their liv-
ing out of building ordinary businesses
over those who sit behind computer
screens playing with their braces”.
Now I will be the first to admit that
in my long employment in the confines
of the Upstream business at BP, I met
very few of the former and none of the
latter and no customers either; in fact
when I was a Business Unit Leader my
annual performance review contained the
comment ‘David has never knowingly
met a customer’ from my boss’s boss….I
think he thought a spell in the Refining
& Marketing business would do me
good….but I digress!
Since I left BP 7 years ago, I’ve had
the privilege of working with two ex-
traordinary entrepreneurial
business–builders in Aidan Heavey,
founder and CEO of Tullow Oil plc, and
Jørgen Hallundbæk, founder and CEO of
Welltec a/s, both of whom from the tini-
est of beginnings, with a great idea but
little capital, have built very successful
companies, leading in their field, that are
respectively very different from the ‘big
battalions’ of the Majors and the oil field
service behemoths*.
I am sure that there are a few oth-
ers ‘out there’ who could be just as suc-
cessful. In fact I’m encountering more
and more would be business-builders,
with great ideas but next to no capital,
whose struggles to get airborne match
those of the baby red kite that has been
hatched by its watchful parents at the
bottom of my Thames-side garden. In
particular, small companies that have
new technology to offer seem to find it
very difficult to attract funding from in-
vestment banks, private equity houses
etc, as compared say to exploration com-
panies that want to drill a dry hole in
some exotic, previously unregarded, lo-
cation. Energy Ventures of Norway is an
admirable exception to this trend.
Recently I’ve also met quite a few
David Bamford is non-executive direc-tor of Tullow Oil, and a past head of ex-ploration, West Africa and geophysicswith BP
“braces twiddlers” and here’s where I
have to be careful what I say as we at
DEJ can’t afford a libel action! Howev-
er, let me say this – if we wait for the fi-
nancial industry to support fledgling oil
& gas technology companies, with one
or two honourable exceptions we will
wait a very long time and get very used
to hearing something like that sucking-
of-teeth sound you encounter when an
engineer arrives to look at your malfunc-
tioning dishwasher!
One unfortunate consequence is
that many small companies that are get-
ting underway with a good idea are one
way or another soon sucked into the
maw* of one of the bigger oil field serv-
ice companies, typically – I would ob-
serve – at the wrong time in the small
company’s development.
So what is to be done (to paraphrase
Lenin)?
One simple thing is that it seems to
me that we can use Finding Petroleum –
our Digital Energy Journal and our Fo-
rums and Conferences - to try to identify
some new technologies with real poten-
tial, and to allow others the opportunity
to do this too. We will also be unable to
afford the legal fees should somebody
take objection to our damning their new
technology as hopeless or useless or ex-
orbitant in price….and so we will damn
by omission – only technologies that
seem to us to have the potential to truly
reduce risk, or reduce costs or reduce cy-
cle-time will appear.
We try hard but we cannot spot
everything that’s promising – please get
in touch via the Finding Petroleum web-
site if you have something to tell us.
* I thought about writing ‘the maw
of a behemoth’ but it seemed the mixture
of Old English and Old Hebrew seemed
excessive!
DEJ26_28pages:Layout 1 16/08/2010 17:28 Page 1
Mer
ak P
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Impa
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3September 2010 - digital energy journal
Contents
Centrica uses cloud document hosting serviceUK energy company Centrica has signed an Enterprise deal with 4Projects to use its document web hosting service across its wholeupstream oil and gas business - which means the documents will be hosted on a cloud typeservice
Microsoft initiative for standard IT infrastructureMicrosoft has launched what it calls the “Microsoft Upstream Reference Architecture Initiative” together with 20 partners to date – a kind ofmanual for how to do IT for the upstream
Julian Pickering establishes Digital Oilfield SolutionsJulian Pickering has set up a new oil and gas IT consultancy “Digital Oilfield Solutions Ltd”, which will focus partly on helping companies withreal time drilling data, and working out strategies to implement the Energistics’ WITSML and PRODML standards
Zedi´s flowmeter for sandy gas wellsZedi of Alberta has developed a gas flowmeter with a very smooth throat – which means it suffers much less damage if there is sand in theflowline, compared to conventional flowmeters
DOF - when to tell colleagues to ´Get over it´It may be surprising to see how much better the organization will work with a leader having the guts to say it like it is, says Dutch Holland,Holland & Davis LLC
Pushing more data through your offshore fibreUK telecoms consultancy Metrodata has helped a UK North Sea rig operator get more capacity out of their existing fibre opticcommunications - by using different protocols, carrying data from three offshore rigs
23
Production
22
Exploration
16
6
12
14
25
8
11
27
26
Leaders
SMT deepens its relationship with OpenSpiritGeosciences software company SMT wants to make it easier for customers to work on their projects using a range of different software tools.SMT is working together with OpenSpirit to make this easier to do
Neuralog - log files data management Neuralog of Houston has developed a system to help people manage their well log data and well files
Electromagnetics - how good is it really? Electromagnetic survey company EMGS tried to quantify exactly how useful electromagnetic surveys can be in helping derisk exploration -by comparing what the electromagnetic analysis suggested to what was actually found
Arctic seismic surveys without damaging the environmentCGG Veritas explains how it minimises disturbance to wildlife, environmental damage and risk of marine accidents, when conducting itsArctic seismic surveys
Kongsberg´s new 3D reservoir softwareKongsberg of Norway was asked to develop 3D reservoir simulation software for Saudi Aramco which can handle up to a billion cells. It isnow making it available to everyone
Understanding formation pore pressureHaving a better understanding of formation pore pressure can help you predict problems you might incur when drilling. Gary Yu, chieftechnology officer of Geotrace, explains what you can do
5Geoprober: a new system for drillingGeoprober Drilling of the UK is developing a method to drill in deepwater at 50 per cent less cost than conventional drilling, using lighterdrilling equipment, but which will actually improve safety and reduce environmental impact. Technical director Tony Bamford explained howit works at the May 26 Finding Petroleum deepwater forum
Using marine fibre optic seismic acquisition technology on landShell is working together with seismic technology company PGS to develop a fibre optic seismic system for land surveys with the potentialto be left permanently – which can record with a million channels. It uses technology originally developed for recording at the bottom of theocean
Deepwater - where the industry goes nowNeil McMahon, senior analyst with Bernstein Research, presented an overview of where the oil and gas industry is with deepwater, at the May26 Finding Petroleum forum in London
28
19
18
DEJ26_28pages:Layout 1 16/08/2010 17:29 Page 3
THE 6TH INTERNATIONAL CONFERENCE ON INTEGRATED OPERATIONS IN THE PETROLEUM INDUSTRY, 28–29 SEPTEMBER 2010
Partners in the Center for Integrated Operations in the Petroleum Industry:
Cooperating academic partners:
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eFieldsSmart FieldsDigital Oil FieldsFields for the Future
International meeting place for business and science: www.ioconf.no
Alan B. Lumsden Cristina Pinho Dag Ola Lien Marta Duenas Diez Meshal Al-Buraikan Paul CarlileProfessor & Petrobras Royal Norwegian Repsol SaudiAramco Boston UniversityMedical Director Air Force Academy School of Management
SessionsIO10 will highlight the next generation of real time technologies and management for better productivity and safety.
Sponsoring organization:
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DEJ26_28pages:Layout 1 17/08/2010 14:32 Page 4
Leaders
September 2010 - digital energy journal 5
Geoprober: a new system for drillingGeoprober Drilling of the UK is developing a method to drill in deepwater at 50 per cent less cost thanconventional drilling, using lighter drilling equipment, but which will actually improve safety and reduceenvironmental impact. Technical director Tony Bamford explained how it works at the May 26 FindingPetroleum deepwater forum
Geoprober Drilling of the UK is developing
a method to drill in deepwater at 50 per cent
less cost, using lighter drilling equipment,
but which will improve safety and reduce en-
vironmental impact including fuel consump-
tion, the company claims.
Technical director Tony Bamford ex-
plained how it works at the May 26 Finding
Petroleum deepwater forum.
The company has been working on the
project for 7 years, supported by Chevron
and StatoilHydro, but would like $50m in-
vestment in order to develop the complete
system including the deployment equipment.
The company plans a test of the lower part
of the system with Statoil in the North Sea
in 2011.
“We’re probably about 2.5 years away
from fully testing the system - if we found
the money tomorrow,” he said.
On 2004 data, the company estimates
that the cost of a well drilled like this could
be $5.73m, compared to $13.9m for a con-
ventional Gulf of Mexico well.
The system has much less equipment
on the seabed than with conventional
drilling, and it can be installed in a single
trip. The seabed equipment weighs 30 tons.
The conductor is combined with the
casing hanger and wellhead is connected to
dual shear rams. The assembly is run to the
seafloor on 7-5/8” casing and jetted in. Once
installed on the seabed, drilling can com-
mence straight away. “You’re in the reser-
voir in perhaps 12 days,” he said.
The idea is to drill to the first pressure
containing point, then connect the casing on
the seabed to the blow out protector suspend-
ed just beneath the vessel (ie so the surface
casing and riser are the same diameter all the
way to the surface. The 7 5/8inch casing is
then cemented in place. The next hole size is
6-1/2” where a 5-1/2” liner is set. Finally
drilling into the prospective reservoir con-
tinues with a 4 ¾ inch bit.
This section is all drilled by 2 7/8 inch
coiled tubing. The coiled tubing is equipped
with a data cable and it can be rapidly
spooled through the water column to run a
variety of slim hole formation evaluation
tools.
Well control protection is provided by
a “Near Surface” blow out protector which
is suspended below the vessel, and the high
pressure casing riser from the seabed to this
blow out protector is strong enough to hold
the pressure of the reservoir (up to 680 bar).
A riser which can hold the reservoir
pressure is more easily achieved with this
system, because the riser is only 7 5/8 inch
diameter, compared to a 21 inch standard
deepwater riser.
The system is ideal for reservoirs which
are in deepwater, but at relatively shallow
depths beneath the seabed. However if a se-
ries of expandable liners are used , , Mr
Bamford reckons the system could drill to
6000m below the seabed.
“We’ve got a well architecture and ask-
ing you, have you got the geology that fits
it,” he said.
“We think - if you could drill these
wells for $5m a pop - how many more tar-
gets would you be able to reach?”
On the topic of safety, commenting on
the Gulf of Mexico disaster, Mr Bamford
said on a conventional subsea drilling rig
there was only one point where the hydro-
carbons could be controlled after they got in-
to the well, that was at the the subsea blow
out preventer on the seafloor. “Once gas got
past that and entered the riser, there was
nothing that could be done with them except
divert the gas overboard
With the Geoprober system, there is an
additional blow out preventer just below the
vessel.
“We believe it is safer than existing
technology,” he said.
Seabed apparatusThe equipment on the seabed is much re-
duced – instead of a conventional 300-400
ton subsea blow out preventer tor, there is a
30 ton mini blow out preventer – This has a
much lighter impact on the soft subsea soils.
Geoprober has put most of its design
efforts into the seabed equipment – because
it wanted a system which would provide all
the necessary functionality, but which could
be installed from the vessel in one trip.
All of the equipment on the seabed, in-
cluding the template, conductor and a mini
blow out protector, can be lowered to the
seabed in a single operation, together with
the drillbit.
By drilling a
small hole with a
narrow annular
clearance between
the drilled hole,
drilling through
shallow gas zones
can be less haz-
ardous. This is be-
cause mud circu-
lating rate can be
adjusted to pro-
vide the right back
pressure to limit
the flow from
shallow gas sands.
Geoprober
did a lot of re-
search into a spe-
cial gripper system
with dual seals, to
ensure that nothing can leak out from around
the casing into the ocean.
As part of the development, Geoprober
studied the performance of conventional
blow out preventers.
They analysed the way control systems
are put together in the aerospace industry for
examples of super reliable control systems,
based on triple modular redundancy princi-
ples.
The shear ram of the blow out preven-
ter needs to be able to close in under 45 sec-
onds to meet the API certification require-
ments. This was proven through a practical
demonstration.
The system has 3 separate control pods,
and can communicate signals via acoustics
or through the submarine vehicle (ROV).
The blow out preventer uses lead acid
batteries for a seabed power source. The bat-
teries enable a much lower weight of equip-
ment to be installed on the seabed. With con-
ventional blow out preventers, energy is
stored in liquid under pressure in accumula-
tors.
The charge in the batteries is main-
tained with a steady flow of power from the
vessel.
“The amount of power needed to keep
batteries fully charge is very small indeed,”
he said.
Cost of a well could be$5.73m compared to$13.9m for a typicalGulf of Mexico well -Tony Bamford,Technical Director,GeoProber drilling
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6
Leaders
digital energy journal - September 20106
Leaders
Shell plans to use this technology ex-
clusively for a few years before making it
available commercially to the rest of the in-
dustry.
“Shell only realized recently that the
technology PGS applied offshore could per-
haps be applicable - after some modifica-
tions - to land seismic and that it would
make a significant difference in quality as
well as cost,” Mr Walk says.
“It’s not so farfetched to take the tech-
nology from down the ocean from marine
to land,” says Mr Walk. “The differences
are not that large if you think about it.”
PGS’ role is to develop the technolo-
Shell has announced plans to work together
with seismic technology company PGS to
develop a fibre optic land seismic system,
which has the potential to be left perma-
nently for the life of the field.
The system should be able to carry up
to a million channels.
The system could prove particularly
useful when monitoring what is happening
over large areas of Middle Eastern desert
oilfields. The first tests will be in a desert.
It could also prove useful for monitor-
ing tight gas fields. “To do tight gas eco-
nomically, you need to know very precisely
what the subsurface looks like,” says Wim
Walk, manager geophysics measurement
technologies at Shell.
“Tight gas requires very high resolu-
tion images. That’s the problem with cur-
rent land seismic technologies; they are not
able to provide that level of detail.”
Shell initiated the project because it
“finds the quality of seismic data on land
inadequate for its exploration purposes,”
says Mr Walk. ““We want to make a big
step forward in improving that quality.”
“By using PGS technology – we can
make a step forward in improving the qual-
ity of seismic data on land without it being
cost prohibitive.”
Shell has done permanent reservoir
seismic monitoring before on a small scale,
Mr Walk says.
These kinds of technologies could
prove much more important in future. “It
will be more important to get the last oil
and gas out of these reservoirs,” he says.
“Monitoring systems will become more and
more important.”
To provide some perspective on the
million channel figure, Schlumberger an-
nounced in March 2010 an 80,000 channel
survey it did in Kuwait, saying it was a
“new industry record”.
By increasing the number of channels,
you get a higher resolution seismic image
at the end, which is more likely to accurate-
ly pinpoint locations where there could be
oil and gas.
“Given that most of this technology is
in existence today, we anticipate a relative-
ly low development risk and expect to de-
ploy the first system soon,” says Dirk Smit,
vice president exploration technology at
Shell.
Shell is working together with seismic technology company PGS to develop a fibre optic seismic systemfor land surveys with the potential to be left permanently – which can record with a million channels. Ituses technology originally developed for recording at the bottom of the ocean
Using marine fibre optic seismicacquisition technology on land
VesselThe vessel required on the surface is a sin-
gle hulled vessel, dynamically positioned,
size approx 100m long by 22m across – Mr
Bamford says that such vessels are currently
available on the market for around $50,000
a day.
The vessel has a moonpool in the cen-
tre (a hole through which equipment can be
lowered).
To distribute the weight of the subsea
equipment and riser loads,, Geoprober has
devised a tensioning system, which spreads
these loads around a large area of the deck,
rather than suspending the load from the top
of the drilling derrick.
Even with a slimmed down system, the
total weight of equipment being sent to the
seabed, including the riser can be 300
tonnes, so the vessel needs to be strong
enough to handle it.
The equipment on the vessel has a
“heave compensator” – which means that as
the vessel moves up and down on the waves,
the drillbit and any equipment it is lowering
to the seabed stays in the same place.
Shell wanted to make a big step forward in the quality of seismic data on land - Wim Walk,manager geophysics measurement technologies at Shell
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Leaders
September 2010 - digital energy journal 7
Leaders
7
gy; later another contractor will be invited
to join the collaboration and take on the role
of deploying the technology.
“This will not be PGS as they are not
in the onshore deployment business any
longer,” Mr Walk says. PGS sold its on-
shore seismic business in December 2009
to Geokinetics.
PGS does not plan to be a seismic ac-
quisition service provider on land, but un-
dertakes the research and the development
to put the system together in collaboration
with manufacturing partners.
The company is currently completing
a feasibility study, demonstrating that the
sensor and cable meet the seismic specifi-
cations.
“If this phase is concluded successful-
ly, the next phase will complete the design
and will produce a prototype to test in a re-
al environment, either somewhere in North
America, testing a tight gas environment,
or in the Middle East,” Mr Walk says.
TechnologyIt uses PGS’ OptoSeis technology, original-
ly developed for use on the seabed.
The fibre optic technology is light-
weight, which means that the logistics of
doing a survey is much easier, with less
heavy equipment to transport.
There is no need for a power supply at
the receivers (as there is with a wireless
seismic system), which means that it is pos-
sible to keep the system in place for the life
of the field.
If a system is robust and water resist-
ant enough to be used on the subsea, it
should be reliable enough to be used on
land, apart from elements which are hard to
predict, such as ploughs or vandals cutting
cables, or problems getting the cables
across roads.
The sensors are powered down the fi-
bre optic cable. They are typically attached
to the cable at 50m intervals. (The system
at the seabed typically has stations every
50m.
The sensors consist of a mandrel
wound with an optical fibre, and 3 sensors
are placed in a fluid filled, pressure bal-
anced assembly.
The laser signal going down the cable
excites the sensors. When the seismic sig-
nal is received, the laser beam is subjected
to an induced stress, causing a phase shift
in the light beam.
HPIn parallel, Shell is also developing a new
highly sensitive wireless seismic sensor
technology with HP, and announced this in
March 2010.
The company is keen to develop tech-
nologies which will help it gain a competi-
tive advantage, Mr Walk says.
One disadvantage of the wireless sys-
tem is that each device needs a battery so it
can only run for a limited amount of time
before the battery needs recharging. In con-
trast, the fibre optic system can run perma-
nently, without access to the sensors, be-
cause there is no need for any power at each
sensor location.
Both the HP and PGS systems can
promise a similar number of channels (1
million); the weight of the devices is com-
parable (because the fibre optic cables are
very light); although the HP sensors could
be more sensitive.
The company could end up using both
systems together. “We certainly envisage
that,” Mr Walk says.
“HP and PGS have capabilities that are
very different,” Mr Walk says. “We like to
work with companies with capabilities that
can synergise with our own capabilities.”
DEJ26_28pages:Layout 1 16/08/2010 17:29 Page 7
8
Leaders
digital energy journal - September 20108
Leaders
fairly low oil price at the time.
Looking for different geologyUntil 2005-2006, people were only looking
for a specific number of geology types in the
deepwater, mainly submarine fans and clastic
reservoirs.
But then “there was a big change,” he
said.
“Wherever you take a step back - it’s the
guys that have looked for something quite dif-
ferent which have met success in the past few
years,” he said.
“You could argue the future is strati-
graphic traps and presalt carbonate reservoirs.
The next stage will get a lot more complex
but it does open up a lot of new areas.”
HistoryThe first wave of deepwater exploration was
in the late 1980s, with Shell discoveries in the
deepwater Gulf of Mexico, with submarine
fans.
This was followed by a second wave in
the late 1990s, with discoveries in the Gulf of
Mexico, Angola and Nigeria.
There was actually a drop in the rate of
new discoveries from 2002 to 2004, as the oil
price was sharply climbing. “I think that's be-
cause Integrated Oil Companies stopped ex-
ploring,” he said.
“Beyond 2002 it’s difficult to name dis-
coveries IOCs have actually made - you can
do it pretty much on your hand.”
Then there has been a ‘third wave’ from
2004 to today, which has been driven by
Brazil and the smaller E&P companies, he
said, exploring in the Gulf of Mexico and new
regions of West Africa.
There does also seem to be a trend for
discoveries to get smaller and smaller, and
deeper and deeper.
The flowrates from new discoveries are
also decreasing.
“In fields from the late 1990s to early
2000s, the flowrates could be 55,000 bopd at
Thunderhorse to 15,000 to 20,000 in places
like Angola,” he said.
But for the Gulf of Mexico Lower Terti-
ary (where many of the newer wells are)
“you’re lucky to get 10,000 bopd, or at best
15,000 bopd,” he said.
“I think this is going to be incredibly im-
portant going forward.”
The new wells outside Brazil tend to be
drilled in “very technically challenged geolo-
gy,” he said.
“In Brazil - the flow rates are well above
what we expected 2 years ago and what oil
companies had expected from carbonate
reservoirs,” he said.
Satisfying Wall StreetOil industry investors in Wall Street and the
City are decreasingly rewarding oil majors for
making safe investments, such as in Iraq,
which is dangerous politically but geological-
ly very safe.
“The market is not rewarding them for
going for the non risky stuff,” he said. “A lot
of investors are sitting there saying, what is
your value added for developing this on be-
half of someone else - it really isn't much.”
There are three simple things which in-
vestors are looking for now from oil compa-
nies, he said.
The first is big growth in production,
which is profitable, and which does not in-
clude Iraq (which is considered to have low
profitability, due to the technical service
agreements);
The second is that they “need to be ex-
ploring and have potential for significant
added value from exploration acreage for the
company.”
And the third is that they need to be
leveraged to high oil and gas prices – or in
other words, their production costs should be
high – so an increase in oil and gas prices
Recent exploration success in the deepwater
has been dominated by national oil compa-
nies (NOCs) and smaller exploration and pro-
duction companies (E&Ps), not the oil majors
(integrated oil companies / IOCs), said Neil
McMahon, senior analyst with Bernstein Re-
search, speaking at the May 26 Finding Pe-
troleum London forum.
For example, in 2009, there were 42
deepwater exploration discoveries from IOCs,
111 from the NOCs and 211 from the E&Ps,
he said.
However, “most IOCS have been talk-
ing about returning to exploration recently,”
he said. ”The IOCS are picking up the pace
of exploration or at least talking about this be-
cause they feel they are being left behind.”
“In late 80s and mid 90s - deepwater ex-
ploration was pretty much everything IOCs
were doing. They took on the risk, they didn't
mind doing things seen as quite technical,” he
said.
“Today they're balancing the risk of do-
ing a bit in the deepwater and doing lots and
lots of easy unconventional stuff where the
geological risk is zero.”
“I think they have lost their risk ap-
petite,” he said. “But this could change in a
few years as they are pushed into more and
more exploration areas.”
“I think we could see the next renais-
sance of exploration activity over the next 5
years, where IOCs decide to take on risk
again.”
Looking around the world, some of the
oil majors are in Ghana, some are in Brazil,
and most have gone into Indonesia. There is
also new deepwater activity in the Gulf of
Mexico and offshore Libya.
The country which has seen the most
amount of deepwater discoveries over 2006
to 2009 surprisingly, is Australia.
There is still no clear consensus on what
deepwater actually is, he said. Previously,
anything over 200m was considered deepwa-
ter. But now most people class something
over 1000m as deepwater. “Many people
would say 1000m is far too shallow.”
Mr McMahon believes that the growth
in deepwater exploration is driven more by
the availability of opportunities, rather than a
high oil price, as technology became avail-
able or license blocks were opened.
For example, there were many new dis-
coveries in the period 1996 to 2003, despite a
Deepwater - where the industry goes now Neil McMahon, senior analyst with Bernstein Research, presented an overview of where the oil and gasindustry is with deepwater, at the May 26 Finding Petroleum forum in London
Neil McMahon, senior analyst, BernsteinResearch
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10
Leadersshould make a big increase in overall profit
margin and investor returns.
“Most of the IOCs don't tick any of those
3 boxes,” he said.
West AfricaIn West Africa, the growth in deepwater dis-
coveries has shown “fantastic progression”
until the past 5 years, he said.
Lately, “everything that's been discov-
ered in Angola has been much smaller than
what was discovered in mid 90s,” he said.
Deepwater Nigeria “has seen pretty
much a stalling of any decent exploration ac-
tivity,” he said. “Until we see a clear hydro-
carbon law in Nigeria and people feel a bit
more comfortable about the situation - the tra-
ditional exploration is pretty much dead.”
There are two very important wells in
Sierre Leone and Liberia, being drilled by
Anadarko and Tullow, he said.
“These follow from what Anadarko
would say is a very important test of a hydro-
carbon system in Sierra Leone.”
“In Ghana, Hess will be drilling just
south of the Jubilee field in a 100 per cent
owned block.”
“We will see if the deeper water offshore
Ghana can prove up hydrocarbon plays.”
“So expect a lot more from this area in
terms of industry news in next 12-18
months.”
BrazilBrazil has recently “just taken off,” he said.
The industry is looking at a new type of
deepwater carbonate reservoirs, where the
sediment was originally deposited in shallow
water.
“It’s more of an engineering challenge
than geological challenge,” he said. “It’s not
understanding where the reservoirs are, but
understanding where the fractures are and
how to drill and complete production wells.”
There haven’t been many new explo-
ration rounds in the Santos and Campos
basins recently, so there has been more ap-
praisal drilling (trying to find out more about
known reservoirs) rather than exploration
drilling.
During the next 2 years, there will prob-
ably be a repricing of reserves in the Santos
presalt, now more is known about how pro-
ductive they are. The Brazilian government
has asked independent valuers to work out
how much the reserves are worth, and will sell
them to Petrobras at that price. Bernstein an-
ticipates that the price will be “at least $7 per
barrel,” he said.
This means that companies which al-
ready have reserves in the Santos basin, in-
cluding BG, Galp and Repsol, will be reval-
ued.
“You're going to see a lot of drilling ac-
tivity in the Campos basin as well,” he said.
French Guiana“Probably the most interesting new area in
South America from a deepwater exploration
point of view is probably going to be French
Guiana,” he said. “This is an area that hasn't
seen much activity at all.”
“There's a Tullow/Shell/Total well go-
ing down in the 4th quarter of 2010.”
“It’s targeted historically structural traps
- this time it will be probably more strati-
graphic traps echoing what’s been going on
in West Africa.”
South East Asia“Indonesia is a place a lot of people have writ-
ten off because it has come out of OPEC,” he
said.
“Most people that aren’t involved in the
industry think that pretty much Indonesia is
completely done because it has been worked
on for so long.”
“But there are 2 areas, Pasangkayu and
Bone Bay around Sulawesi where exploration
has never been done.”
“Marathon has got 2 wells going down
here and plans to collect more data in Bone
Bay, as well as in another exciting block in
West Papua.”
“Hess will be drilling in West Papua
too.”
Moving further East, Exxon have had
some success in the Philippines, and in the
South Chinese sea there is a gas condensate
trend. “CNOOC have a major position here
along with Husky and Anadarko are involved
yet again, and BG,” he said. “It will be drilled
extensively in 2010 and 2011.”
LibyaIn Libya, “there have been 2 dry holes drilled
by ExxonMobil in the deep water,” he said.
“The only real discovery we have information
on is Hess' discovery starting to step out into
deepwater.”
“However from a company point of
view Libya is less relevant than other areas in
the world given the fiscal regime that exists,”
he said.
“We tend to discount it from a share
price point movement of view because it can
tend to add limited amount to valuation of a
company because of the tax.”
Gulf of MexicoThe Gulf of Mexico went through “great
wave” in the 1980s. “A lot of exploration
kicked off then,” he said.
“There were great discoveries in late 90s
- Thunderhorse being the best known.”
Then, “it started to drift a bit, he said.
“A lot of the Lower Tertiary discoveries
were made in last few years then it started to
take off again,” he said.
Oil spillThe Macondo oil spill is a “spill of such pro-
portions that it has walked all over the safety
record that was in place in the Gulf of Mexi-
co,” he said.
There have been oil spills in the past, but
the Macondo oil spill is much bigger.
“The total Gulf of Mexico oil spilled in
2005 was surpassed in 3 days by the spill
from Macondo.”
The Gulf of Mexico has a far from per-
fect safety record. According to data from the
US Minerals Management Service (MMS),
there have been plenty of fires and explosions
offshore since 1996, he said, (see graph).
“We haven't heard about them because
in many cases the blow out preventors worked
- we didn't have a situation like we have to-
day,” he said.
“[The Macondo disaster] is regarded as
a unique event which a lot of attention should
be spent on,” he said.
“You could argue that a lot of attention
should have been spent on this since 1996 -
it’s not as though the industry has been
squeaky clean.”
Reduced drilling?As a result of the Macondo disaster, many
people around the world are looking at deep-
water drilling much more closely, which will
have an impact on the amount of drilling that
is allowed.
Already, the consultations which had
been planned on oil drilling offshore Virginia
for the weeks following the spill have been
postponed. “So it looks like that's not going
on,” he said.
“It looks very unlikely that East Gulf of
Mexico lease sale is going ahead,” he said.
There are also areas Shell is trying to
drill in the Arctic this year, where there are
uncertainties, he said. “We think this whole
Arctic area isn't going to see any activity un-
til 2012 and beyond.”
If all oil and gas deepwater production
projects around the world which are planned,
but have not yet been started were delayed by
a year, there would be a shortage of oil of be-
tween half a million and a million barrels of
oil per day, versus previous oil supply and de-
mand forecastshe said.
“That gap could be closed by OPEC.”
But “any delays, any regulation, will just
drive up the oil price.”
However, “a high oil price could then
generate more exploration opportunities go-
ing forward,” he said.
digital energy journal - September 2010
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Many oil and gas companies run a number
of different geophysical packages – includ-
ing Halliburton’s OpenWorks, and Schlum-
berger’s GeoFrame, and they want to view
their data in all of the packages. This usual-
ly means a lot of converting needs to be
done.
Often, the larger the oil company, the
more likely it is to have a range of different
geosciences software applications it uses
regularly.
If staff need to manually convert data
from one application to another, this takes
a lot of time – and can also cause problems
from having different employees working
on different versions of the data. If one ver-
sion of the data is updated and another ver-
sion isn’t, there will be problems.
Oil and gas geosciences software com-
pany SMT is aiming to achieve a scenario
where geosciences data can easily be used
in a range of different applications without
users even noticing that it is being convert-
ed into different formats – so users only
need to keep one version of the data.
The idea is that data can be easily
copied from one project to another, to avoid
companies permanently storing versions of
each project data configured for different
software applications.
OpenSpirit provides the interoperabil-
ity framework that allows multiple applica-
tions to connect to OpenSpirit and access
data from data stores, as well as share user
interaction events with other OpenSpirit-
enabled applications.
When this is done, “customers can
easily see where projects overlap, select the
delta, move only that data over, consolidate
projects and clean up their environments,”
says Kay Sutter, Product Manager for SMT
Data Management & Connectivity.
“Many of our customers work in data
rooms and bring several consultants in.
With better tools, they can subset their da-
ta, and streamline those data management
workflows. We’re hearing a lot of happy
feedback as a result.”
“G&G companies are big users of GIS
software like ArcGIS Desktop and ArcGIS
Explorer,” she says. “Connectivity with
GIS environments has been a big request
from our customer base. That turns out to
be a pleasant additional benefit of interop-
erability through OpenSpirit.”
Users can share GIS events between
applications, and gain read access to their
enterprise geodatabase with OpenSpirit’s
SDE Data Connector.
Multivendor connectivity is now part
of the end user’s workflow, not just a data
transfer process, no matter how efficient,
Ms Sutter says.
Interpreters working in KINGDOM
can share data dynamically with other ap-
plications using the OpenSpirit framework
under the hood.
“They don’t have to break their train
of thought, get out of their software, and
use a different tool to import and export da-
ta,” Ms Sutter says. “It is a seamless, user-
driven workflow, instead of a separate data
management function.”
“When customers are forced to move
data back and forth between this many so-
lutions, valuable time is lost.”
“A lot of companies are looking at
how to use KINGDOM for seismic and ge-
ological interpretation in a workflow with
(Schlumberger’s) Petrel modelling, and up-
scaling to (Schlumberger’s) Eclipse for
simulation,” she says.
“With application interoperability,
they can interpret in KINGDOM, select a
grid, rightclick and broadcast it directly to
Petrel, just like that.”
OpenSpirit’s application adapters are
“spreading like wildfire,” Ms Sutter says.
“We get broader coverage as more
vendors integrate their products and servic-
es with OpenSpirit.”
“Our new OpenSpirit connectors allow
customers to maintain those investments, to
keep managing information right where
they have it today, easily pulling data into
KINGDOM whenever they need it, and
moving it back. OpenSpirit does all the
heavy lifting in the background,” Ms Sutter
says.
“Ultimately, with OpenSpirit connec-
tivity, our value proposition goes way up,”
Ms Sutter says. “We fit more easily into
more organizations’ workflows than ever
before.
Step by stepBefore the days of OpenSpirit, the only way
to convert data from one application’s for-
mat to another was to manually hand code
an integration.
SMT would build data links to other
company’s software using new integrations
every time they were asked for one, and
these proved expensive and difficult to sus-
tain.
“Usually it was a one-off solution you
do for a big client who demands connectivi-
ty,” says Ms Sutter. “It was a painful and ex-
pensive development process and we could-
n’t market [the connection] to anyone else.”
“It was costly not only to build the link,
but also to retool it every time the other ven-
dor’s platform, architecture, or implementa-
tion changes.”
The first stage of integrating OpenSpir-
it with SMT was to build an import export
data connector called “Tunnel O,” which en-
abled users of SMT’s KINGDOM software
to move data from OpenSpirit-enabled com-
mercial repositories into and out of KING-
DOM projects.
But it was clear that a deeper method
of interoperability would be needed.
So in early 2009, SMT decided to ex-
pand its existing relationship with OpenSpir-
it.
During 2009, SMT has been broaden-
ing Tunnel O from an import/export tool to
a full multivendor workflow tool with cur-
sor tracking between applications, broadcast
and reception of data events, and integration
with industry- standard GIS systems.
In mid-2009, OpenSpirit and SMT re-
leased an enhanced KINGDOM data con-
nector, with improved performance and scal-
ability, particularly for large, regional proj-
ects.
In January 2010, SMT introduced a
next-generation KINGDOM Data Manage-
ment system, which can be used to search
and copy large scale project data between
applications. It uses OpenSpirit’s Copy Man-
ager tool as an embedded component.
A new OpenSpirit KINGDOM Appli-
cation Adapter, called KINGDOM Connect,
is due for release by late 2010. It will enable
SMT customers to interoperate seamlessly
SMT deepens its relationship withOpenSpiritGeosciences software company SMT wants to make it easier for customers to work on their projects usinga range of different software tools. SMT is working together with OpenSpirit to make this easier to do
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Exploration
digital energy journal - September 2010
with other vendors’ applications—from di-
rectly within KINGDOM’s user interface.
“We’re taking cross-vendor connectivi-
ty to a completely new level with OpenSpir-
it’s Application Adapter Toolkit,” says Ms
Sutter.
“OpenSpirit has provided tools and a
whole lot of guidance into our development
process. We’re one of the first software ven-
dors to build on their new toolkit, which
nicely wraps up a set of common functions
from OpenSpirit’s Software Developer Kit.”
About SMT SMT claims to have 2700 customers in more
than 95 countries for its KINGDOM soft-
ware.
Texas, began operations in July 2000 as an
independent software company focused on
providing integration solutions for upstream
applications and data. The OpenSpirit appli-
cation integration framework is installed
worldwide in more than 450 sites and 300
companies. With a growing partner network
of more than 55 partners with more than 40
OpenSpirit-enabled applications, OpenSpirit
allows interoperability between multiple
vendors' applications and data, enabling oil
company end users in 65 countries to speed
up critical workflows and enhance analysis
in the geotechnical space.
www.openspirit.com or
info@openspirit.com.
In the latest Welling Report, SMT came
out No. 1 in “Most Likely to Recommend,”
as well as No. 1 in 11 of 13 seismic interpre-
tation categories, including reliability, price,
ease of use, speed, functionality, support,
training, reputation, and dependability.
SMT has been strategically expanding
its KINGDOM suite to cover everything
from advanced geophysics and geology to
full-blown subsurface modelling on the Win-
dows platform.
KINGDOM covers the steps from seis-
mic interpretation to geologic modelling.
www.seismicmicro.com
About OpenSpiritThe OpenSpirit Corporation, in Houston,
Neuralog - log files data management Neuralog of Houston has developed a system to help people manage their well log data and well files
Neuralog, a company based in Houston,
Texas, has developed a system which oil
companies can use to manage their well log
data.
The database can serve as the compa-
ny's Well Data Master, Well Log Repository,
and Well File Management System, and for
managing documents associated with wells,
fields, stratigraphy and seismic data.
As well as standard well log files, it can
support unstructured data such as raster well
logs, maps, reports, and cross sections to
name a few.
The data architecture is based on the
PPDM [Public Petroleum Data Model], us-
ing Oracle or SQL Server for its database en-
gine.
All data can be viewed geographically,
using ESRi's ArcMAP system using the Ar-
cGIS extension. Or, data can be browsed
through and explorer-like interface.
To help people use the system, "we
have unique routines for finding the data,
capturing it in the system, organising it,
managing it, making it available for admin-
istrators and users," says Javan Meinwald,
VP business development with Neuralog.
"When a log comes in it has to be
processed in a particular way - so we have a
system to implement those kinds of business
rules - so the log data is captured properly,
quality controlled properly and accessible
properly."
"It's about providing the tools that the
geologist, IT managers and technicians need
to solve their own problems - rather than be-
come dependent on others to provide it for
them," he says.
"Certain people are entitled to look at
certain types of data and not other types. The
geologist that's working in the North Sea has
access to North Sea data - but maybe not da-
ta from the former Soviet Union," he says.
There is a dashboard application and
messaging system to inform those involved
with the data of its current status.
The company's core products were a
portable scanning device and automated dig-
itizing software which would convert paper
log files to data, with special computer algo-
rithms designed to help the computer under-
stand what was happening.
The scanner and software can capture
logs for a database and the software can un-
derstand the sometimes complex systems
used on log, when scales are changed, the
graph moves off a chart, and converts a
dashed, dotted or other line types into digital
data.
Finding Petroleum London Forums 2010For latest developments, registration and to subscribe to our newslettersee www.findingpetroleum.comLimited free tickets available for each forum - exhibition andsponsorship opportunities
• The 'capability crunch' November 23• Collaboration and the digital oilfield -
December 9
• Carbon capture and storage - September 15• Exploration, Technology and Business - Oct 7
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Electromagnetics - how good is it really? Electromagnetic survey company EMGS tried to quantify exactly how useful electromagnetic surveys canbe in helping derisk exploration - by comparing what the electromagnetic analysis suggested to whatwas actually found
Svein Ellingsrud, founder and vice president
of Norwegian electromagnetic survey com-
pany EMGS, spoke at the Finding Petrole-
um May 26 forum about developments with
using electromagnetic survey technology in
the deepwater.
Mr Ellingsrud presented the results of
86 wells drilled so far in regions where elec-
tromagnetic surveys had been done, which
can be used to demonstrate how well elec-
tromagnetics can and can't accurately predict
hydrocarbons.
Of the 86 wells drilled so far, the com-
pany classified 36 of them as "calibration
wells" and 50 as "exploration wells".
Of the 36 "calibration wells", 22 of
them were reported as oil discoveries - the
other 14 were dry holes.
13 of the dry holes showed an electro-
magnetic response which was the same as
the rock around it (or in other words, the
electromagnetic survey did not indicate any-
thing which would suggest there was a reser-
voir there).
19 of the 22 discovery wells showed
more than 15 per cent difference in electro-
magnetic response from the rock around
them - or in other words, the electromagnet-
ic survey would have indicated a body of
higher than usual resistivity at that point (hy-
drocarbons are high resistivity).
The other 3 of the discovery wells
showed between 1 and 15 per cent difference
in response to the rock around it - so there
was some indication of possible hydrocar-
bons but not a strong one.
But meanwhile one of the dry wells had
an anomaly above 15 per cent, (so the elec-
tromagnetics would have predicted that there
could have been a reservoir there).
The other dry wells had an anomaly of
1-15 per cent or a negative anomaly.
In a separate study of 50 "exploration
wells" which were ultimately drilled, with a
56 per cent success rate (28 discovery wells),
21 of the 28 discovery wells showed 'signif-
icant anomalies' (i.e. over a 15 per cent
anomaly response for the reservoir). All in
all, for the wells drilled on a significant
anomaly, the discovery rate increases to 70
per cent, while the discovery rate on wells
drilled with no significant anomaly is down
to 35 per cent from the 56 percent discovery
rate for the entire well database.
However 9 of the 22 dry wells also had
significant anomalies, while 8 of the 28 dis-
covery wells did not show significant anom-
alies. These are the cases, where the meas-
urement seemingly does not correspond with
the well result. It should be noted that the
well study uses the most simplistic analysis
method to reduce bias in the interpretation.
A modern analysis of electromagnetic data
uses complex depth conversion algorithms
and requires considerable cluster power.
This analysis was published in detail in
First Break magazine May 2010 (Fanavoll
et al).
Of course, if a decision is taken not to
drill as a result of electromagnetic data or for
any other reason, then nobody knows if good
reservoirs were missed because of that.
There have been cases of oil companies
making decisions not to drill as a result of
electromagnetics, including a study present-
ed by Shell at EAGE 2004 in Paris. "That's
also happened with other companies but I
can't talk about who or where," he said.
Reasons for "errors"In essence, the CSEM measurement is al-
ways correct, as any other well-performed
measurement. However, the interpretation of
the measurement is error-prone. There are
many possible reasons why electromagnet-
ics can be interpreted for a wrong result -
for example hydrates can have a high resis-
tivity, but cannot be produced in a conven-
tional way, Mr Ellingsrud said.
Carbonate rocks can have a high resis-
tivity. However a good seismic analysis
might spot this. "If you do correct interpre-
tation together with seismic you can maybe
tell that it is carbonates," he said.
One well had a reservoir which was
close to basement rock, and basement rock
has a different type of electromagnetic re-
sponse.
The more interpreters are exposed to
electromagnetic data, the more they learn
about other causes of electromagnetic re-
sponses in a given area.
Volcanic rock can also cause anom-
alies.
Surveys to dateTo date, EMGS has performed surveys off-
shore Greenland, Newfoundland, in the
Caribbean , French Guiana, Brazil, Nigeria,
Angola, Ghana, Egypt, Libya, Norway, East
Schematic view of a controlled source electromagnetic (CSEM) survey. A horizontal electricdipole (HED) is towed above receivers that are deployed on the seafloor. The HED emits acontinuous EM signal which is recorded by the receivers
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September 2010 - digital energy journal
India, Malaysia, Indonesia, Australia, , in the
Gulf of Mexico, etc.
The company has carried out more than
450 surveys so far, of which around 200
have been at water depths of between 2000
and 3500m.
Surveys at over 1000m depth have been
carried out in the Gulf of Mexico, and off-
shore Brazil, West Africa, Newfoundland,
Greenland and East of India among others.
Electromagnetics - basicsElectromagnetic surveys work like this.
The technology can measure the elec-
trical resistivity of rock and how it varies lat-
erally in depth.
In CSEM electromagnetic energy is
transmitted into the subsurface, which either
continues further or comes back up to the
surface as it meets formation or petrophysi-
cal changes, depending on the resistivity
contrast.
Normally the pores in subsurface are
filled with brine (saline water) which is rela-
tively conductive A higher electromagnetic
response occurs when the field propagates
into an electrical resistive formation, e.g.
volcanic, salt, carbonates, other tight rocks
or hydrocarbon reservoirs.
The technology works well together
with seismic because both methods can be
used to find possible reservoirs, but in com-
pletely different ways - so if a prospect looks
hopeful using both techniques, that gives
you additional reassurance.
Seismic technology reports how a
sound wave passes through different rock
layers, which provides a picture of the geom-
etry of the rock layers, because at any point
where the rock density or acoustic parame-
ters changes, some of the energy is reflected
and some of it continues.
Seismic surveys are normally not very
good at actually identifying which fluid
types that are in the subsurface, just show-
ing the shape of the rock structures; but elec-
tromagnetics can't tell you much about the
precise shape of the rock, but can tell you
about the resistivity of the structures. , which
in its turn is linked to pore fluid
CSEM aims to look for areas where the
electromagnetic response s are higher than
the area around it.
To do the survey, you need to place re-
ceivers directly over the zone of interest and
also around it.
Electromagnetic surveys can actually
work better in deepwater than shallow wa-
ter, because very little of the electromagnet-
ic energy (moving upwards) gets out of the
water into the air, and back again to the re-
ceivers. Additionally, the level of electro-
magnetic background noise is lower at deep-
er waters.
At depths of 2000m, you don't see any
energy which has been through the air/water
interface - and at 1000m water depths, you
"don't see it a lot", he said.
It used to be a problem doing electro-
magnetic surveys in shallow water, but with-
in the last couple of years, we have obtained
high accuracy on data acquisition and pro-
cessing so that the water depth limitation is
strictly and operational HSE issue , he says.
We need water under of the keel of the boat,
so to speak.
Data acquisitionIn deep water, surveys are typically done
with an electromagnetic source as close to
the seabed as possible, hung from a vessel,
and electromagnetic receivers on the seabed.
EMGS operates two vessels, each with
capacity to carry and deploy 200 receivers.
Receivers are placed on the seabed with
a distance of between 500m and 5km be-
tween them. The receivers can be positioned
either in a line or a grid, depending on the
type of survey being done.
The necessary distance between re-
ceivers depends on the wavelength being
used. Typical frequencies is ranging from
0.25 Hz to a couple of Hz (wavelength de-
crease with increased frequency) which
means that it is possible to operate with a
wide spacing between receivers.
A 1000km 2 survey can deliver data
within a month of starting it, he said, de-
pending on the complexity of the processing
(2,5D or 3D).
The equipment is designed to operate
at depths of up to 3500m, which means that
it can be used on approximately 90 per cent
of the continental shelf around the world, he
said.
Murphy Oil case studyMurphy Oil used the technology prior to
drilling a gas prospect off Malaysia.
Its seismic surveys had shown a
"flatspot", indicating that there is gas, but it
doesn't provide any indication about how
much there is - anything from 2 per cent to
100 per cent saturation can give nearly the
same seismic response.
But with electromagnetics, if there is
considerable, say 40-50 per cent or higher,
gas saturation, you get an increase in resis-
tivity.
So Murphy Oil wanted to use electro-
magnetics to find out which it could poten-
tially be.
It asked EMGS to put in a line of re-
ceivers and tow an electromagnetic source
over them.
The results showed an electromagnetic
anomaly in the same position as the seismic
flatspot, giving an indication that there could
be hydrocarbons there.
Subsequently a well was drilled which
"encountered a good reservoir," he said.
Barents SeaOn the Barents Sea (North of Norway),
EMGS ran a multi client survey in 2008 and
is aiming to run a MC survey the spring and
summer 2010 - where a survey is pre funded
by different clients.
To cover the large area, the company
will lay receivers with a 3km distance be-
tween them, and run surveys both North-
South and East-West. It will lay out 100-140
receivers.
So with a grid of 10 x 10 receivers
spaced 3km apart it could survey a region of
30km x 30km (900km2) in one survey).
SubsaltDoing electromagnetic surveys for subsalt
reservoir detection is difficult because the
salt often has very high resistivity, which
means that some components of the electro-
magnetic field are blocked, and these
blocked components are the most sensitive
to a hydrocarbon reservoir. The remaning
parts of the electromagnetic field, which
pass through the salt, cannot resolve a hy-
drocarbon reservoir.
In salt areas, Mr Ellingsrud recom-
mends combining it with Magnetotellurics,
a method of imaging the subsurface using
natural source electromagnetics (electro-
magnetic energy which comes from the so-
lar wind interacting with Earth’s magnetic
field). This method complements with low,
deep-penetrating frequencies. Together with
CSEM, this can give important information
about the thickness and shape of a salt layer
or a salt dome.
In certain cases, you can also use elec-
tromagnetics at a higher frequency, so they
might give better resolution of the salt, and
use gravity.
BOA Galatea, EMGS's purpose-built 3D EMvessel
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 15
16
Exploration
digital energy journal - September 2010
Arctic seismic surveys without damagingthe environment
In the Arctic, offshore exploration has to be
carried out in the short summer, when there
is sufficient open water for towed-streamer
deployment.
Onshore exploration is only permitted
in the winter, when snow-cover reaches 15
centimeters and the ground is sufficiently
frozen for vehicles to be taken over snow
without damaging the tundra.
Both require careful planning for their
successful execution, covering not only the
usual subjects such as spread configuration,
geodesy, and resupply, but also contingen-
cies, HSE-preparedness, and environmental
and cultural sensitivity.
Close collaboration with local authori-
ties and communities is essential to prevent
impact on the environment and local subsis-
tence lifestyles.
To protect the Arctic’s wildlife, Marine
Mammal Observers, mainly from the local
community, are employed to monitor exclu-
sion zones and to record wildlife observa-
tions. CGGVeritas vessels deploy Passive
Acoustic Monitoring systems to listen for
marine mammal vocalizations.
Source ‘soft start’ techniques are used
to prevent startling mammals in the survey
area.
The onshore crews use integrated GPS
tracking units to map hazard areas, includ-
ing government-supplied wildlife locations.
Getting closer than one mile to a polar
bear den triggers alarms in the recorder truck
and in the offices of the client and recording
crew manager.
For CGGVeritas crews operating in the
Arctic, ensuring minimal impact on the frag-
ile environment is fundamental.
Seismic crews use low ground pressure
vehicles, equipped with wide tires or tracks
to ensure minimal impact.
Long-term camp areas are completely
iced-over manually or set up on frozen pools
to minimize effects on the ground.
Most camp strings are on skis and
move every three to five days with the ac-
quisition spread.
CGGVeritas has a strict “no spills” pol-
icy; no garbage or contaminants of any kind
may remain on site after the crews leave, so
that there is zero impact on the environment.
Over 14,000km of data was recorded,
reaching latitude 740 North, for which the
crew were awarded an industry HSE
(Health, Safety and Environment) award.
CGGVeritas has a history of working
offshore Greenland, the Princess and Bergen
Surveyor having acquired over 20,000km of
data there since 2008.
CGGVeritas has a number of DNV-cer-
tified Ice Class vessels, which will shortly
be joined by the the Oceanic Vega, with its
distinctive X-BowTM hull.
All are equipped with Sercel Sentinel
solid streamers, which are preferred in the
Arctic due to their resilience to in-sea dam-
age.
Solid streamers also have increased
depth stability in variable water temperatures
and salinity and are quieter at all frequencies
and depths, particularly in marginal weather
conditions.
Seismic exploration in the Arctic poses
considerable operational and geophysical
challenges. The highest possible standards
of specialized equipment, crew training, and
zero impact methods to preserve the envi-
ronment and delicate ecosystem must be em-
ployed.
Once the data is recorded, the challenge
is extended to processing, where the expert-
ise CGGVeritas has gained in handling the
unique problems of ice noise, data recorded
over permafrost and a highly variable near-
surface provides reliable seismic images of
the subsurface.
The mantra of field staff is
“Take only data, leave only
footprints”, and when the snow
melts, even the footprints are
gone.
In 2009, CGGVeritas suc-
cessfully completed a program
within an existing, active oil-
field on the North Slope of Alas-
ka.
The crew took special pre-
cautions to meet the safety and
logistical challenges of working
in and around “hot” pipelines,
running cable across busy ac-
cess roads, and dealing with the
operations of an active field.
During the summer of 2008, CGGVeri-
tas acquired transition zone 3D seismic in a
rugged and environmentally sensitive area
of the Beaufort Sea shoreline with a very
narrow data acquisition window.
CGGVeritas successfully put together a
shallow water transition zone team and ves-
sels to complete this in the limited available
time.
The principal hazard faced by CG-
GVeritas marine crews is ice.
Support vessels are equipped with ice
radar and assisted by regular ice reconnais-
sance flights. Ice pilots assimilate the obser-
vations, satellite imagery, and meteorologi-
cal information, to provide on-the-spot fore-
casts of ice conditions.
In the summer of 2009 the CGGVeritas
Viking Vision vessel was able to record the
furthest-north 3D survey in the western
hemisphere, in the Beaufort Sea.
The vessel operated with the largest
areal spread (8 x 150m x 7.2km) ever de-
ployed in the Arctic, only having to leave the
work area twice due to movement of pack
ice.
Total technical downtime for the entire
55-day campaign was only 42 minutes, or
0.05%, allowing almost 1600 square kilome-
tres of high-quality 3D data to be acquired,
surpassing the most optimistic expectations,
CGGVeritas says.
At the same time another CGGVeritas
vessel, the Bergen Surveyor, was recording a
2D survey in Baffin Bay, offshore Greenland.
CGG Veritas explains how it minimises disturbance to wildlife, environmental damage and risk of marineaccidents, when conducting its Arctic seismic surveys
CGGVeritas' ice class vessel Oceanic Vega sailing inNorwegian waters after her christening ceremony on July2nd 2010 (Image courtesy of CGGVeritas)
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 16
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18
Exploration
digital energy journal - September 2010
Kongsberg Oil and Gas Technologies has de-
veloped a tool for running reservoir simula-
tion data and doing all kinds of analysis with
it – which can work on 100 thousand cells
up to a billion cells.
The reservoir simulation post process-
ing software was originally developed for
Saudi Aramco in 2006, following a request
for tender where Saudi Aramco asked 19
different companies if they could develop a
computer system which could work on huge
reservoir models with 50-100m cells. The
company has also worked with Cono-
coPhillips, on models of 1-2m cells.
Kevin Hermansen, department manag-
er, software products, at Kongsberg Oil and
Gas Technologies in Norway, believes that
the software fills a big gap in the market –
because the industry does not have tools to
work with reservoir simulations which make
full use of the recent advances in 3D data
processing.
Many people are still working with
software tools which show results as 2D
graphs, or show 3D models but visualizes
them as layers and cross sections which in
reality is only 2D displayed within a 3D
space, he says.
Most oil and gas companies are work-
ing with reservoir simulations using post-
processing software which is based on 15-
20 years old, he claims. Or they are trying to
develop software tools in house, asking
reservoir engineers to turn into 3D visualisa-
tion programmers.
There have been many big advances in
3D computer processing technology over the
past few years, as any computer game play-
er will be well aware – and it is time the oil
and gas industry started using this kind of
technology.
With the Kongsberg software, you can
manipulate the 3D model as you view it –
and the processing and analysis is done on
the fly and within seconds.
This means that it can be a much more
time efficient way of working with reservoir
simulations than other systems on the mar-
ket.
The software can be particularly useful
for large or complex reservoirs, or where
there are say over 100 wells, where it is very
difficult to visualise or understand in depth
what is happening.
The company offers to sell the software
either by a licence fee for lifetime use, or
rental which can be for anything to an hour
duration upwards.
The parent company of Kongsberg Oil
and Gas, Kongsberg Gruppen, is the biggest
defence contractor in Norway, and also owns
Kongsberg Maritime, a manufacturer of mar-
itime automation systems. It employs over
5,000 people.
It is important to stress that the soft-
ware is not used for creating reservoir mod-
els or simulation - it is used for working on
the simulations which have been created
from other software packages. It is a generic
post-processing tool which supports all ma-
jor simulators.
BenefitsThrough 3D analysis and specialist tools,
you can identify interesting dynamics within
the reservoir and particularly in between
wells.
Working with volumes instead of limit-
ing the analysis to 2D layers and cross sec-
tions allows for a better understanding. Take
dynamic filtering for example – visualize the
volume of increasing pressure around inject-
ing wells as new injectors come online in
your simulation.
You can draw isosurfaces (surfaces
where a certain value is constant, such as
pressure). Many software tools can do this
but the Kongsberg software can "create them
on the fly", he says.
You can calculate the current oil in
place, and see where in the reservoir this is
decreasing and even more interesting where
the oil in place is increasing (oil banking).
By comparing the reservoir simulation
with actual well data in 3 dimensions, you
can quickly distinguish between times when
the simulation is showing a big difference
between actual recorded data (indicating a
problem with the simulation), or an erro-
neous sensor reading from the well.
If the data from one individual well is
different to the simulation for that part of the
reservoir, that probably indicates an error
with that well’s data. But if the data from the
wells differs from the simulation over a
range of different wells, that probably indi-
cates a problem with the simulation.
Trying to match the observed reservoir
performance to the simulated one is a very
time consuming but important task. History
matching is in simple words a calibration of
the model so that the simulation matches the
historical data. A good match increases reli-
ability of the model and the predictive capa-
bility of the model. Traditionally this history
matching has been done using 2D plots
where observed and simulated values are
plotted together.
The SIM reservoir system allows the
Kongsberg´s new 3D reservoir softwareKongsberg of Norway was asked to develop 3D reservoir simulation software for Saudi Aramco which canhandle up to a billion cells. It is now making it available to everyone
The Kongsberg 3D reservoir simulation software which can handle up to a billion cells -originally developed for Saudi Aramco
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 18
19
Exploration
September 2010 - digital energy journal
Understanding formation pore pressure Having a better understanding of formation pore pressure can help you predict problems you mightincur when drilling. Gary Yu, chief technology officer of Geotrace, explains what you can do
Understanding formation pore pressure distri-
bution is critical for evaluating seal integrity
and hydrocarbon accumulation column height
evaluation of a prospect.
You can also work out pressure attrib-
utes such as fracture gradient (amount of pres-
sure you need to induce fractures in the rock
at different depths), correct mud weight re-
quired in drilling, effective stress, and over-
burden pressure.
With this information, drillers and engi-
neers can better carry out well planning for
mud program, casing shoe position, and cas-
ing string purchase as well as assess drilling
risk for wellbore stability, hazard prevention,
and reservoir formation protection.
Pore pressure also offers tremendous
value in the early phase of exploration.
It allows us to assess trap seal integrity
and hydrocarbon accumulation column height
for prospect evaluation, as well as to identify
bypass zones and pressure changes when 4D
data are available.
It has been shown that, using seal in-
tegrity concept, you can differentiate low sat-
urated gas sands, i.e., a seal breach problem,
from saturated sands.
This seal breaching analysis using pres-
sure data can complement the AVO analysis
in differentiating false anomalies caused by
low saturation from valid bright spots.
Pennebaker showed in 1970 that pore
pressure can be predicted from seismic veloc-
ities, and since then many formulations have
been introduced with varying success.
Prestack seismic data quality in terms of
signal-to-noise ratio (SNR) and resolution can
significantly affect velocity analysis and the
quality of pore pressure estimation.
StepsGeotrace developed a systematic methodolo-
gy together with a calibrated pressure model
that transforms seismic interval velocities in-
to high density high resolution (HDHR) for-
mation pore pressure and subsequently other
pressure related attributes.
This calibrated pressure model attempt-
ed to go beyond conventional compaction
trend consideration and take into account the
effect of burial depth, porosity, temperature,
and shale diagenesis.
First, PSTM (pre-stack time migrated)
seismic data was carefully optimized to en-
hance its sig-
nal to noise
ratio and fre-
quency band-
width.
Then,
HDHR
anisotropic
velocity
analysis with
6th-order
curved ray
formulation
was em-
ployed to ac-
curately ex-
tract a de-
tailed 3D seismic velocity field for every time
sample at every common-mid-point (CMP)
location.
Land and marine seismic data were used
to evaluate the progressive impact of data
quality on the accuracy and vertical resolu-
tion of the seismic interval velocity field at
important milestone steps in the prestack data
enhancement workflow.
A calibrated pressure model was built af-
Gary Yu, chief technologyofficer, Geotrace
analysis to be done in 3D and each measure
point will be illustrated as cell with a colour
gradient that is white where the match is
good, blue where the output is overestimat-
ed and red where it is underestimated. So in-
stead of being bound by a 2D plot that has
no geographic reference "You can look at
your whole reservoir and immediately spot
sectors, geological layers or individual wells
that are completely wrong" he said.
The standard input for these 3D history
match analysis is "repeat formation tester"
(RFT) logs to pressure test zones of interest
in the well, and see if it matches the reser-
voir simulator's output.
The tool is also useful when many peo-
ple are working together on a model so they
all see the same thing.
TrainingWhen it comes to training people to use the
system, there is a big difference between
people who are used to working in 3D on
computer games, and people who are more
used to working with 2D scientific plotters,
Mr Hermansen says.
"You have the grandfathers who cannot
operate this -
they have diffi-
culties navigat-
ing in 3D with
the mouse -
they're not used
to working in
3D at all," he
said. "They are
used to working
with layers –
and they will
only work with
the 2D views,
maps and
plots." Luckily,
SIM Reservoir
also provides
the users with
this capability.
"Then you have probably some very
knowledgeable guys who just jump on
everything and try every single feature and
really get a lot of stuff out of it. Students are
typical users that would touch and combine
everything because they’re not scared of
touching all buttons."
"But then you have a great deal of real-
ly experienced people who have been think-
ing about this for many years. They want to
have the tools that you have in this post pro-
cessing package and the possibilities will on-
ly grow as new experienced users are com-
ing on board."
Volumes of delta pressures
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 19
20
Explorationter it was correlated with available wells, logs,
and drilling data and tested to evaluate its re-
liability and uncertainty of pore pressure esti-
mation.
With blind well testing and real case
studies, it was demonstrated that this method-
ology is practical and effective and can pro-
vide valuable information for prospect evalu-
ation, well planning, and drilling risk man-
agement ahead of the drill bit.
Calibrated pressure modelA calibrated pressure model was developed
to transform seismic interval velocities to
pore pressure.
It takes into consideration various fac-
tors including under compaction of the rock,
burial depth, temperature, shale diagenesis
and inelasticity, that affect subsurface pore
pressure.
Available logs, drilling data, and engi-
neering information such as mud weights,
LOT (leak-off test), RFT (retrievable forma-
tion tester), and MDT (Modular Formation
Dynamics Tester) from nearby wells were in-
corporated into the calibrated pressure mode
generation.
Figure 2 displays the estimated mud
weights using a calibrated pressure model at
a known well location and at a blind well test
location from a project in the deepwater Gulf
of Mexico.
The distance between the two wells is in
tens of miles, and the target is around 16,000
feet. The real mud weights applied are denot-
ed as blue triangles and the estimated mud
weights are shown as solid red trend.
The mud weights vs. depth chart at the
calibration well (to the left of Figure 2) illus-
trates that the calibrated pressure model pre-
dicts quite well the pore pressure in terms of
mud weights and thus demonstrates its appli-
cability and reliability.
When this model was applied to the
blind well test using derived high resolution
interval velocity field, the estimated mud
weights were very close to the drilling mud
weights and RFT (retrievable formation
tester) measurements as shown in the chart to
the right in Figure 2.
In addition, the
calibrated pressure
model also provides
an uncertainty assess-
ment displayed as a
fairway between the
green and light blue
solid trends around
the estimated mud
weigh trend.
The relative
tight and consistent
fairway displayed in
Figure 2 implies a
good pressure model
was generated and the
estimated pressure re-
sult was reliable.
Case studyThe following study was conducted using the
above workflow and calibrated pressure mod-
el to estimate the reservoir and surrounding
formation pore pressure and appraise the
prospect seal integrity for an onshore pres-
sure-charged gas play in the Gulf Coast re-
gion of the United States.
In Figure 3, a 2D pre stack time migrat-
ed section (seismic in black wiggle with vari-
able area) overlaid with estimated pore pres-
sure in color (blue to orange for high to low
pressure variation) demonstrates that the
prospect has excellent fault and top seals be-
cause there are no pressure leaks on either
sides of the two bounding faults (in white)
and no leakage into the overlaying formation.
The drill bit found gas and confirmed the
pore pressure estimation and seal capacity in-
terpretation.
A detailed two dimensional display in
Figure 3 can assist the evaluation of subtle
pressure changes across lithological, strati-
graphic, and structural boundaries, but does
not give a good idea of spatial pressure varia-
tion and 3D pressure cell distribution.
On the other hand, a 3D visualization of-
fers a better view of regional pressure distri-
bution.
Figure 4 is a snapshot of a 3D visualiza-
tion exercise of pore pressure distribution for
the same prospect in Figure 3.
Now, explorationists can quickly visual-
ize and interpret 3D pressure cell distribution,
pressure plume, and pressure sink as well as
quickly assess any potential seal breaching
problems and drilling problems in a region or
a basin.
Another powerful 3D visualization is to
simultaneously co-render multiple 3D attrib-
ute volumes for integrated interpretation.
Figure 5 depicts a 3D visualization of a
PSTM seismic cube embedded in various
pressure attribute cubes, since PSTM stack
volume shows structure and stratigraphy bet-
ter, and pore pressure volumes show fluid dy-
namics better.
It allows explorationists from different
disciplines to work together and perform true
3D interpretation by moving, stripping, or in-
tercepting various sub-cubes to evaluate ge-
ology, structure, reservoir, pressure, and their
interaction – a full integration allows conduct-
ing geological and geophysical evaluation by
geologists and geophysicists and planning
well design and drilling hazard prevention by
drillers and engineers.
Figure 2: The left chart is the estimated mud weights at the knownwell and the right chart is the estimated mud weights at the blind welltest location. The estimated mud weights are very close to the knownmud weights and RFT values
Figure 3: Estimated pore pressure (blue toorange for high to low pressure) overlaid withPSTM stack (black wiggle with variable area).The prospect is well-sealed by faults and topformation
Figure 4: Estimated pore pressure in 3Dvisualization shows 3D pressure celldistribution and regional pressure variation
Figure 5: A series of snapshots of a 3Dvisualization and interpretation session usinga combination of multiple 3D PSTM andHDHR 3D pressure attribute volumes
digital energy journal - September 2010
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 20
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• PetrelTM
• KingdomTM
• PetrobankTM
• GeoframeTM
• OpenWorksTM
• FinderTM
• LogDBTM
• SeisDBTM
• AssetDBTM
• GeologTM
• OpenSpiritTM enabled data stores
External data sources
• DISKOSTM
• LicenseWebTM
• ArcticWebTM
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Production
22 digital energy journal - September 2010
UK energy company is so pleased with
its experience with 4Projects’ web hosted
document storage system, that it has signed
an enterprise wide deal for its entire up-
stream business.
Centrica uses the service to share doc-
uments with people working on the project,
including their own staff, front end engi-
neering and design (FEED) contractors and
risk consultants.
4Projects started working with Centri-
ca handling documents for the Grove Field
and Seven Seas Development, in the North
Sea in 2007. This was followed by 2 proj-
ects in 2009 to handle documents for a gas
storage project, and finally a company-wide
or “enterprise” deal.
“They’re adding new projects to it
every time,” says Martin Robertson, key ac-
count manager for the Centrica account at
4Projects.
“As we increase our upstream activi-
ties we need a reliable and secure system
for documentation handling and storage,”
says Sharon Nott, senior project adminis-
trator for Centrica.
“The business has been impressed
with the 4Projects solution and the level of
customer support offered by the company.”
Documents on the webCompanies already have systems to man-
age documents internally, but it is usually
very hard to find a way to bring in other
companies to this system, because of secu-
rity reasons. The 4Projects tool does it for
them. Allowing another company to view
the documents can be done by ticking a
check box.
One of the biggest benefits of the sys-
tem is providing people with a better way
of sharing electronic documents than by e-
mail. Sending large attachments by e-mail
can be very slow, has a big drain on server
resources, and means you end up with mul-
tiple versions of a document in circulation.
The 4Projects system is designed so
that people should be able to find the docu-
ments they need without using folders.
They can use folders if they want, but as
most of us know, folder systems on shared
document systems easily get very compli-
cated and hard to navigate.
Documents can be searched using a
range of different criteria, such as date
modified, who uploaded it, document sta-
tus. The system can be used to handle any
type of documents, including drawings, e-
mails, tasks, discussions, “request for infor-
mation”, technical queries.
There are also document viewing
tools, which enable you to view software
which normally needs special software,
such as CAD drawings. The software to
view the data can be hosted by 4Projects,
so you can view the drawings on a web
browser. You can also leave comments on
them.
The tool does not have functionality to
edit documents online – the editing is done
using the core software.
The software has a full audit trail so
you can see who did what when.
It can be easier if people retrieve the
documents they want by searching by key-
word or by meta data, rather than looking
for documents in folders.
“The temptation people have is to
replicate their internal network folder struc-
ture – but that’s what’s giving them the
headache in the first place,” says Mr
Robertson. “You don’t need to have a filing
structure at all if you use it in the right
way.”
The system can be configured so peo-
ple add the meta data every time a new doc-
ument is uploaded.
“It’s all about using the Meta data that
exists – and allowing people to assign Meta
data that they want with custom fields and
key words,” he says.
WorkflowUsers can construct their own workflows or
designs for how the system should be used
– so for example, you can say that certain
individuals should be notified when a cer-
tain type of document is uploaded.
4Projects leaves it to clients to build
the workflow – eg stating that certain draw-
ings need to be approved by somebody.
“That workflow can be as complex or as
Centrica uses cloud document hostingserviceUK energy company Centrica has signed an Enterprise deal with 4Projects to use its document webhosting service across its whole upstream oil and gas business - which means the documents will behosted on a cloud type service
simple as you want it to be,” he says.
You can have steps where people from
different departments, such as the technical
team and project management team, review
something before it goes live.
About 4Projects4Projects has been providing online docu-
ment management services for 10 years.
Other energy companies using it include
Mott McDonald, EON, Poyry and Conoco
Phillips.
10 years ago, the company was main-
ly displacing the cost of posting or courier-
ing paper documents to people – now it is
mainly providing IT infrastructure.
It was originally working in the UK
construction industry, with a number of ma-
jor UK construction companies using the
service.
It is also used in other energy sectors
– the company estimates that 75 per cent of
the UK’s offshore wind installations in
2009 were using 4Projects.
Some companies migrate to using the
system when they reach the point in a proj-
ect where data needs to be shared outside
the company; other companies start using it
from the beginning.
Martin Robertson, key account manager forthe Centrica account at 4Projects
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 22
Production
September 2010 - digital energy journal 23
Imagine if it was possible to buy a manual
which would tell you how to put together
information technology systems for the up-
stream, so you could be sure that it works.
This is roughly what Microsoft is put-
ting together, calling it its “Microsoft Up-
stream Reference Architecture Initiative.”
To date it involves 20 of its partners,
including Accenture, EMC, Energistics,
ESRI, Honeywell, IHS, Infosys, ISSGroup,
Landmark Graphics, Logica, Merrick Sys-
tems, Open Spirit, OSIsoft, Petris, Point-
Cross, Schlumberger Information Solu-
tions (SIS), Siemens Energy, VRcontext,
WellPoint Systems and Wipro Technolo-
gies.
The reference architecture created by
Microsoft and further developed by initia-
tive partners won’t tell you exactly how to
do it but gives you broad principles which
you can follow which are tried and tested.
It is a bit like someone writing a stan-
dard manual for a house (after a few hous-
es had been built and some things had been
tried), which might say things like, ‘it’s a
good idea to have the dining room near the
kitchen so you don’t have to carry food so
far,” says Accenture’s Martin Leach, Chief
Architect – Integrated Oilfield Solutions,
who is involved in the project.
Such a manual still leaves plenty of
diversity in how houses are built to meet
people’s different needs, and provides
room for innovation and competition, when
people develop new ways of doing it, and
the reference architecture is the same.
The reference architecture is not lim-
ited to just Microsoft products, and does
not exclude companies which are in com-
petition with Microsoft – in fact, virtually
every information technology service
provider, whether they are providing data-
bases, visualisation tools, storage, models
or information management could fit into
it.
There are no restrictions to what can
be added to it. “If we have vendors that
would like to implement this architecture
and they happen to be on a different plat-
form, there’s nothing to stop them,” says
Microsoft’s Technology Strategist, World-
wide Oil & Gas Industries, Paul Nguyen.
Microsoft is currently developing
processes for how the system will be gov-
erned and evolved. The leaders of the proj-
ect are Microsoft’s Paul Nguyen and Ali
Ferling, Managing Director, Worldwide Oil
& Gas Industries. “More detail will be re-
vealed on the next few months,” Mr
Nguyen says.
There are plenty of clear advantages
to having a system like this.
It is very useful for the whole indus-
try to develop standard ways of doing their
IT, rather than developing new systems
from scratch in every company – just like
we all have fairly standard ways of plumb-
ing our houses. This makes it much easier
for employees and service providers to
work for different companies, because they
can understand much more quickly how it
all works.
Companies will be able to implement
new technology with a higher degree of
confidence that it will work, knowing that
they are implementing systems which have
all been fully tested and should work with
the set-up they already have. This means
that people can spend their time on the
more value-adding work, such as actually
optimising their production and safety.
It should make it easier for innovators
to develop new tools, such as for analytics,
collaboration, complex event processing,
data integration, connecting devices, data
storage – even entire business processes –
because they know there is already a big
market of companies who are ready to in-
stall the system.
Companies could compete to design
and sell “processes” which run on it. For
example, a company could design a process
for people to work together in exploration,
so the software supports robust discussion
between geologists and lets them all sug-
gest alternative views of what the seismic
data might mean so they can choose the
best between them, with the possibility of
inviting anyone else into the discussion.
Microsoft’s Ali Ferling sees this a bit
like the way automotive companies design
their cars on ‘platforms’ – which a variety
of different manufacturers can compete to
make the best and highly standardised
components
for. Then dif-
ferent car
models are
created on
top of this
platform, ful-
filling differ-
ent special
require-
ments. Mi-
crosoft sees
its role in a
similar way:
providing the
best platform
for IT with
Microsoft´s
Industry
partners then
creating
highly spe-
cialised Oil
& Gas applications on top of this platform.
The system is planned to cover all up-
stream operations and perhaps extend later
into downstream, although it is unlikely
that many companies will want to imple-
ment it all at once.
Production operations is seen as the
most critical area where a system like this
could help – when there are complex daily
decisions to be made which rely on a large
amount of information.
Although all oil companies are differ-
ent and do things in different ways, there
are some things they all do – such as own-
ing and managing subsurface assets, and
monitoring what is coming through the
wells. So systems can be developed to do
these standard tasks, such as automate how
a well test works.
“Every oil and gas producer has a
common core set of workflows such as
well test validation and production opti-
mization,” says Michael Szatny, Landmark
key product manager for DecisionSpace®
for Production™. “The Microsoft upstream
reference architecture recognizes similar
principles as those in Landmark’s commer-
cially-available IPO solution which en-
ables companies to use their disparate data
Microsoft initiative for standard ITinfrastructureMicrosoft has launched what it calls the “Microsoft Upstream Reference Architecture Initiative” togetherwith 20 partners to date – a kind of manual for how to do IT for the upstream
Putting together a standardplatform for oil and gas IT -Ali Ferling, Microsoft’sManaging Director,Worldwide Oil & GasIndustries
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 23
Production
24 digital energy journal - September 2010
and preferred software applications in pro-
duction workflows.”
What it coversVertically, the Microsoft Upstream Refer-
ence Architecture has 5 layers – (i) data
sources, (i) software for specific disci-
plines (g+g, drilling+completions, produc-
tion operations, data integration, back of-
fice ERP/CRM); (iii) data integration lay-
er; (iv) business process management /
workflow layer; and (v) visualisation /
presentation layer.
Any data source could be used for the
system – SQL databases, Oracle databases,
PPDM data stores.
A data model, such as the PPDM data
model, is only a component of the refer-
ence architecture – it is a plan for how da-
ta can be managed and integrated.
The data integration layer (ii) gathers
all data sources into a single system, so it
can all be worked on together.
It can cover both structured data (such
as data held in specific software packages,
such as reservoir modelling and surveying)
and unstructured data (such as emails, doc-
uments and spreadsheets).
The role of the business process man-
agement / workflow layer (iv) (which Mi-
crosoft also calls the ‘orchestration’ layer)
is partly to manage the data itself.
This layer can ensure that the data is
all co-ordinated and accurate - addressing
a common problem for upstream software
systems, when there is large amounts of da-
ta but too unstructured or inaccurate to be
much use.
It also co-ordinates the various mod-
els the company is running. For example,
if an economic model is built on the results
of a reservoir model, and the reservoir
model is changed, the economic model can
automatically update.
The visualisation layer (v) is how peo-
ple actually work with the data – whether
in their offices, working remotely via smart
phones, or working at home. Also some
people who work with the system might
not be direct employees of the company.
As part of the visualisation layer,
there is a core "integrated portal" where
everybody can find all kinds of informa-
tion, for geoscientists, engineers and man-
agers. Once people have logged on they
can see whatever they want.
Going across the company, it covers
everything upstream – exploration,
drilling, production and financial manage-
ment.
It can incorporate high performance
computing systems, via a cluster server.
The architecture can use XML standards,
plement whichever bits of it they want.
To build it, Microsoft suggests start-
ing with one domain process, such as do-
ing a well review, and putting in the infra-
structure, connectivity and processes to do
that.
You can make it your general plan to
move towards it over a number of years, or
decide you are going to revamp a portion
of your IT systems according to the refer-
ence architecture.
LandmarkLandmark markets its own software plat-
form, “DecisionSpace for Production,”
which integrates Landmark and third party
data and products, following the Microsoft
reference architecture.
Landmark has been putting together
workflow “solutions” for a number of
years, helping companies get the data they
want from different systems and making
that data available.
“By having a standard system it is ul-
timately much cheaper and quicker for the
customer to install an asset management
solution,” says Landmarks’ Mr
Szatny.“This means that Landmark and its
oil and gas customers can focus less on
how information flows and more on how
information is used and consumed within
an oil and gas domain context.”
AccentureInternational technology and consulting
company Accenture is going to use the Mi-
crosoft Upstream Reference Architecture
as part of its service offering to oil and gas
companies, when it offers to install what it
calls an “integrated oilfield solution” for
them.
Accenture focuses in particular on so-
lutions to help companies optimise reser-
voir performance, well performance, facil-
ity performance, asset performance and al-
so managing HSE (health, safety and envi-
ronment).
About 18 month ago, Accenture re-
built its solutions to work on the Microsoft
stack of products, including databases, in-
tegration capabilities and visualisation
technology.
Accenture says to companies first of
all “we’d rather you had any architecture
than had no architecture,” and secondly
“we’d rather you had our architecture,”
says Accenture’s Martin Leach.
such as WITSML and PRODML. It can in-
clude service orientated architecture and
cloud computing, and social media.
WorkflowsWith an IT architecture like this, it should
be much easier to put together workflows
to help answer complex questions, like
how to develop a field, which involve peo-
ple with different areas of expertise, and
different data sources, all coming together
to achieve the best answer.
For example this task might draw on
information about the reservoir, informa-
tion about production from different wells,
information about the costs of drilling new
wells and possible targets.
When staff are scheduling how to use
their rigs, they can see all current drilling
opportunities on one half of the screen, and
information about rig availability on the
other half of the screen, so they can match
them together.
What we have todayToday, it is common for oil companies to
have fairly evolved data management sys-
tems within individual departments, such
as managing facilities, reservoir, wells and
overall operations, but they do not work to-
gether well.
Different departments have their own
analytic models, but the models are not
connected together.
There have been many efforts to con-
nect together systems from different de-
partments, but normally it is on a one to
one basis (a lot of effort is put into connect-
ing one system to another system), known
as a “point to point” integration.
Collaboration is also difficult because
it is hard to enable people working inside
and outside the company to see all the nec-
essary data at once. For example, a seismic
service company working for different
companies needs a separate login for each
of the different systems.
People are agreed on the need for key
performance indicators to assess how well
things are going, but the data to calculate
them is often not readily available, and
when data is available it is hard to deter-
mine the timeliness of it.
How to do itOf course every company already has an IT
architecture of some sort (so they’re not
building one from scratch), but they can
use this as a blueprint as they develop what
they are doing, and compare this system to
what they have already.
The system can be implemented in
different modules, so companies can im-
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 24
Production
September 2010 - digital energy journal 25
experts - hopefully they will be able to im-
prove the quality of operations.”
“If you're in a difficult piece of drilling
- if you've got anything going into an abnor-
mal situation, for example - you can call up-
on remote expertise,” he says. “It’s great to
have an extra pair of eyes to help.”
“I don't think it’s about people interfer-
ing - or making data available for the sake
of it. It’s about getting the data to the right
people.”
“If you can do that from a number of
different sources -it makes sense to use stan-
dards like WITMSL.”
rence, September); SPE Russian Oil and Gas
exhibition (Moscow, October) and Petex ex-
hibition(London, November).
He plans to provide Energistics with
global support, and his company will take an
active role in promoting the use of the
WITSML and PRODML standards.
Dr Pickering is currently co-writing a
paper with other members of the WITSML
steering committee about how WITSML
could help with drilling automation.
Interest areasDr Pickering is particularly interested in
looking for ways drilling can be further au-
tomated – which can mean less people re-
quired on the rig. “We're going to see au-
tomation becoming progressively more im-
portant on rig operations,” he says.
As the industry moves forward it is
very probably that much more data will be
transferred from platforms and rigs to shore-
based offices and collaboration centres.
Another possible change might be that
oil companies get far more involved in mon-
itoring drilling activities remotely. Until
now, they have mainly entrusted the respon-
sibility for monitoring drilling to their
drilling contractors, he says.
More information from the drilling rigs
in general is probably a good thing, he says.
“The more information you have about
what you're doing on a drilling operation, the
better it’s likely to be and the safer it’s likely
to be,” he says. “Real time information al-
lows you to predict problems.”
“If you can relay that information to
www.digitaloilfieldsolutions.comDr Pickering is a past head of IT for drilling
and completions at BP, and later, until March
2010, he worked for BP’s Field of the Future
Programme Office. He is also a past chair of
the Energistics WITSML Executive Team
and remains a member.
A partner in Digital Oilfield Solutions
is Jesse Roye, a former BP IT drilling con-
sultant, based in the US.
Mr Roye was co-chairman of a May
2009 SPE conference in Colorado entitled
“Artificial Intelligence in the E&P Industry
— Future Opportunities for Better Decision
Making.” He initiated, implemented and
managed BP’s Gulf of Mexico Drilling and
Completions Real Time Operating Centres
from 2005 through to February 2010.
A third partner, Bruce Guthridge, is
consulting with BP in Houston and has been
part of the Real Time Operating Centre team
from 2006 to 2010 and is currently manag-
ing the Real Time Operating Centres. He
worked previously with Gemini Consulting
and Oracle.
Dr Pickering, Mr Roye and Mr
Guthridge all have in excess of 30 years ex-
perience working in the oil & gas industry.
Digital Oilfield Solutions anticipate
working with oil and gas operators, drilling
companies and oil and gas software compa-
nies. They are engaged currently with a ma-
jor international E&P company.
Dr Pickering will also continue on the
board of the Energistics WITSML special in-
terest group, and will represent Energistics
this Autumn at the ATCE exhibition (Flo-
Julian Pickering establishes DigitalOilfield SolutionsJulian Pickering has set up a new oil and gas IT consultancy “Digital Oilfield Solutions Ltd”, which will focuspartly on helping companies with real time drilling data, and working out strategies to implement theEnergistics’ WITSML and PRODML standards
Sign up to our free e-mail newsletter atwww.digitalenergyjournal.com
Receive the latest news and feature articles in your inbo x every Friday
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 25
Production
26 digital energy journal - September 2010
Zedi´s flowmeter for sandy gas wellsZedi of Alberta has developed a gas flowmeter with a very smooth throat – which means it suffers muchless damage if there is sand in the flowline, compared to conventional flowmeters
www.zedi.caAn unconventional gas producer in the
Montney formation (British Columbia and
Alberta, Canada) had problems with large
amounts of sand entering the flow line.
The sand was messing up the orifice
plates in the flowmeter – which meant that
staff had to inspect and replace orifice plates
daily. There were concerns that the flow da-
ta being gathered was not accurate enough.
The company approached Zedi Inc, a
production operations company based in Al-
berta, Canada, to see if they had a better sys-
tem which would be more resilient.
Zedi suggested its “eTube,” which has
a smooth shaped throat, rather than an ori-
fice plate.
Flowmeters work by constricting the
flow and taking a pressure reading before
and after the constriction. The flowrate can
be calculated from the change in pressure.
The Zedi eTube has a much smoother
constriction (called a throat) and can work
across a wide range of flow rates.
The throat is shaped like an ellipse, so
that it allows sand and debris to pass through
without excessive wear and or damage.
Unlike orifice plates, where sharp
edges can be easily damaged or act as a trap
for sand or liquids, the eTube has no edges.
In many cases, with its wide turndown
ratio, an eTube should only need to be sized
once throughout the entire life cycle of a
well.
The eTube can be used together with
electronic flow measurement field devices
produced by Zedi, such as the Smart-Alek,
Zedi Connect or Zedi EFM Walk-up, with
the measurement data sent automatically to
Zedi’s secure web portal Zedi Access.
In this project, the subject well was
brought on production with a 2-inch, 600
ANSI-rated flanged eTube with a 0.7 beta
ratio and a Smart-Alek EFM device.
After three days on production, other
pieces of equipment began to fail under the
severe erosive conditions.
The dump valve on the separator and a
flow joint failed due to the sand flowing
back, also causing significant erosion to the
piping.
The well was shut down for three days
to do repairs. After coming back online, the
well flowed for a mere 16.5 hours before the
flow joint had again eroded.
At this point, the producer became con-
cerned about measurement accuracy, and re-
moved the eTube for inspection, expecting
significant wear given the damage to the oth-
er pieces of equipment.
The producer was shocked to discover
that the eTube looked as though it could have
remained in service with no visible wear or
erosion detected, Zedi says.
To be certain of the eTube’s accuracy,
the producer sent the device to Zedi’s Ed-
monton Research Facility for a more detailed
inspection to confirm their assumption that
the eTube had incurred no significant dam-
age.
The subsequent tests confirmed the
producer’s initial observation - that despite
enduring the same harsh conditions that led
to the failure of two extra heavy flow joints
and a dump valve, this particular eTube was
approved to be put back in service.
Now the company uses Zedi flowme-
ters all the time.
The two workers that were being used
to change or inspect orifice plates 1.5 hours
a day could be deployed in more useful
ways. The savings on labour time and re-
placement costs, by using an eTube instead
of orifice plates, were estimated at $3900 per
month.
A further problem with the previous
system was that if a new orifice plate was in-
serted of a slightly different size, the soft-
ware needed to be updated and there was
room for human error. This problem no
longer applies with the eTube.
“By tapping into more unconventional
gas sources such as shale gas, we’ve discov-
ered that we may also need to move away
from conventional methods of gas meter-
ing,” the operator said.
“The eTube helped us reduce costs and
eliminate constant interruption and unneces-
sary labour to redefine the efficiency of our
field staff. But most importantly, we know
that critical decisions are being made based
on trustworthy metering accuracy.”
Zedi's "eTube" flow meter with a smooththroat so it does not get clogged up by sand
Finding Petroleum London Forums 2010For latest developments, registration and to subscribe to ournewsletter see www.findingpetroleum.comLimited free tickets available for each forum - exhibition andsponsorship opportunities
• The 'capability crunch'November 23
• Collaboration and the digitaloilfield - December 9
• Carbon capture and storage -September 15
• Exploration, Technology and Business -Oct 7
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 26
Production
September 2010 - digital energy journal 27
The purpose of this discussion is to en-
courage the leader to say those thoughts out
loud…to make effective change happen for
the organization.
The messages are naturally designed to
destabilize the current situation, serve as a
warning, a kick in the rear end, a jolt and a
jar.
The messages are designed to remove
obstacles that have so far been unscathed by
conventional change leadership approaches.
In addition, delivering these weapons will
just feel good. No more Mr/Ms. Indirect; say
what needs to be said.
Get over itTwo energy service organizations had been
merged for almost a year. All the legal pa-
perwork was behind them; all the signs, sta-
tionery, product catalogs and Web sites had
been adjusted to the one new company name.
Customers were starting to react positively,
things were moving forward … except for
one senior manager. He continued to whine
about the fact that now he was required to
work with another senior manager who had
been his most fierce competitor before the
merger. What’s more, he was being asked to
use a business software application which
came with the other company. Whine, com-
plain, delay, mumble, grumble, ad nausea.
Sound familiar?
Finally, ater hearing both second and
third hand about another whining tirade, the
CEO had enough. He had already had more
than a half dozen motivational and inspira-
tional sessions with Mr. Whine to catalog the
positive reasons for the merger, the necessi-
ty to use the software and to sing “There’s
going to be a morning after.”
Enough was enough. The CEO made a
surprise visit to Mr. Whine and after taking
a chair said, “I gather you are still not com-
fortable with this merger.” The surprised Mr.
Whine said that, in fact, was true.
“Well then, get over it,” said the CEO
as he stood to walk out of the office without
another word or a glance over his shoulder.
And you know what? Mr. Whine got over it,
that very day. Sooner or later everybody has
to just get over some things and get on with
business and life.
Sometimes all the great methods and tools
for change engineering, change manage-
ment, organizational re-alignment and oper-
ational integration just don’t work. Despite
trying as hard as possible, successful imple-
mentation just does not happen.
At its core, an organizational change
such as a DOF implementation is a “contact
sport.”
Or, as another veteran of technology in-
sertions said, “You just have to face the fact
that there will be trench warfare with some
of these clowns.” (He was, by the way,
speaking of experienced professionals with
all sorts of educational initials after their
names.)
Let’s say that Bill Smith has been
charged to lead a DOF implementation in his
part of the business and welcomes the chal-
lenge.
However, with some of the managers
and employees, it feels as though he has hit
a brick wall. Why?
Communications about the new way of
doing business have been repeated and re-
peated. Work processes have been altered to
fit with the new software application. Every-
body has been trained in the new software as
well as how to use it in the altered work
processes. Their job descriptions have even
been altered to reflect the new way of doing
business.
Still, a handful of scattered people have
problems.
Before giving up, Smith might want to
try the “heretofore unpublished Secret
Weapons of the effective change leader.”
The Secret Weapons are actually direct
messages, carefully designed for one-on-
one, eyeball-to-eyeball delivery to one or
more individuals who have distinguished
themselves in the DOF implementation proj-
ect by their total blindness and/or disregard
for what is going on around them.
There are no real surprises in the three
weapons which follow. All come to mind au-
tomatically to the dedicated change leader in
the thick of any technology insertion.
Normally the change leader keeps them
unspoken; he thinks the thoughts, then bites
his tongue and puts on his smiling game
face.
DOF - when to tell colleagues to ´Getover it´It may be surprising to see how much better the organization will work with a leader having the guts tosay it like it is, says Dutch HollandBy Dr. Dutch Holland, PhD, Holland & Davis LLC, a service line of Endeavor Management
The
message to
the imple-
menting or-
ganization is
that “We (our
company)
have made a
considered
decision, after
tons of input
from multiple
levels, to im-
plement sys-
tems that will
give us real-
time data on a
24/7 basis.
We’re going
to use that da-
ta to make
better production decisions, starting now. If
you have lingering hard feelings, Get Over
It.”
“Oh, Balderdash.”The world-renowned geoscientist was well
into his third page of reading aloud the rea-
sons why not one iota of his operating meth-
ods could be changed to incorporate a five-
second entry in a new information system.
Supposedly, his personal quest to solve the
mysteries of the known and unknown uni-
verses would be hopelessly and forever de-
railed. His guest could feel internal pressure
building after hearing yet another detailed,
but stupid, rationalization. This imminent
professional just plain didn’t want to be
bothered with any duties associated with
supporting the very company that housed,
fed, funded and coddled him.
The guest set his feet firmly, looked
deep into the geoscientist’s eyes to signal his
turn to talk, waited a second or two longer
then expected, smiled, and then said, “Oh,
Balderdash.” (To be fair, other words may
work better than Balderdash in the oil patch.)
Imagine how good that felt and picture
the look on the geoscientist’s face as he
processed that unthinkable comment from
hell. “Everybody knows that the five-second
data entry requirement will not affect a darn
There are times when youshould say "oh Balderdash"- or something stronger - toyour colleagues - Dr DutchHolland, Holland & DavisLLC
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 27
Production
28 digital energy journal - September 2010
thing.” His guest just turned and walked
away, leaving him to examine exactly where
he stood in light of that surprising, direct
evaluation.
“Your move.”Jane was bending her visitor’s ear for the
third time in a week, going on and on about
how the latest change in work processes was
not ideal from where she stood.
It just wasn’t the optimum way she had
been taught to handle gas lift calculations.
Yes, she understood that the work re-design
and the new software were initiated to meet
specific business needs, and she understood
that everybody’s opinions in the department
had been heard and evaluated as well as used
in the new design. She finally ended her lat-
est latest harangue with a look that said, “So,
what do you think of that?”
Looking at her and smiling, the visitor
said “Your move.”
“Your move?,” she said, “What kind of
answer is that? What do you mean, my
move?” He responded, “It means, your
move. The company and I have done all we
can do to describe the change that we will be
making next week. Now it’s your move. Join
us, please or leave us, please. But, no more
harangues. It’s your move. The ball is in your
court.”
Helping peopleSometimes it’s necessary to help people see
the need to make a choice from among lim-
ited alternatives. They must either sign up to
go forward with the organization or make
another choice that suits them best. Staying
in their current job and complaining about it
is just not an option in today’s world of fast-
paced change. “But she is just too important
to lose,” readers may say. “Oh Balderdash.”
Now, candidly, who hasn’t said all of
these messages to themselves? Most have,
and now may be the time to bring those mes-
sages out in the open and use them as the se-
cret weapons they can be.
Don’t bring them out like the exasper-
ated parent -- with stone-cold eyes, a rock-
hard face, an aggressive body stance or a
“you are about to die” look. Instead use
warm eyes, your smiling face, an informal
stance, open hands; deliver with care for the
individual, the organization and oneself.
Now just in case this discussion ap-
pears to have been written tongue in cheek,
let’s close out with a hard-nosed fact about
change leadership. Most people will proba-
bly never lead a successful change in orga-
nizational behavior until they personally ac-
knowledge that their behavior may play a big
role in the change equation. That’s a truth.
So, as a final shot, please consider the
times when it may be necessary to direct the
Secret Weapons inward. Yep, standing up,
looking into the mirror and letting fly the
message(s) that everyone needs to hear to get
on with their part of the implementation.
Unfortunately, these secret weapons
won’t always work. Not everybody resisting
change can be recovered. Yet it may be sur-
prising to see how much better the organiza-
tion will work with a leader having the guts
to say it like it is. Try it and feel much bet-
ter. Good luck.
Getting more out of your fibre UK Telecoms Equipment Manufacturer Metrodata Ltd. has helped a UK North Sea rig operator get morecapacity out of their existing fibre optic communications - by combining multiple traffic payloads overindividual fibre links between three offshore rigs
It installed converters on the platforms to in-
terface each of telephony, serial and (Gigabit)
Ethernet data signals to Fibre , and then de-
ployed optical multiplexing using CWDM
(Coarse Wavelength Division Multiplexing)
technology to carry the combined data down a
fibre optic network much more efficiently.
An alternative way of doing this could
be to convert the phone and serial data to Eth-
ernet / IP first and then run pure Ethernet/IP
over the fibre. "This would have potentially
been technically possible, but certainly more
costly, more complex to configure, and more
difficult to install (requiring greater technical
skills) " says Metrodata's Managing Director
Richard Kirby.
The optical multiplexer devices them-
selves are "passive", i.e. they require no pow-
er connection, which means that there is no
optical re-transmission or amplification on the
way, with sufficient Transmit power coming
from the fibre conversion devices to pass data
directly between rigs within the network. This
set-up can work readily over distances of up
to around 100km and is inherently extremely
reliable.
You might be surprised to learn that com-
panies are running out of data communications
capacity in a fibre optic network.
Fibre optic installations typically consist
of a limited number of transmit / receive pairs,
each designed to carry between 100 mpbs to
10 gbps, inside an armoured pipe along the
seabed.
The problem the client faced in this in-
stance was that nearly all of its fibre optic
transmit / receive (Tx/Rx) pairs were already
being used on other services.
It wanted to use the system for conven-
tional voice lines (trunk circuits between tra-
ditional PBX devices), data (gigabit Ethernet)
and alarm signalling from a power manage-
ment system (serial data), all through a single
fibre Tx/Rx pair.
For resilience, the company deployed a
'ring' topology between the rigs, ensuring that
traffic could pass either 'east' (or 'clockwise)
or 'west' (counter clockwise) around the ring
to protect against
the possibility of a
link failure, i.e. if
the route from rig
A to rig B failed,
the data could be
routed via rig C.
In reality, in
order to provide
maximum re-
silience for this
critical network, a
second separate
ring was construct-
ed using a single
additional Tx/Rx
fibre pair. In this
way, the network offered resilience to multi-
ple link or component failures.
Mr Kirby suggests that the same technol-
ogy could be use for anyone running out of fi-
bre space. The installation proved to be sim-
ple, needing less skills offshore and with min-
imal impact on operations, he says.
Metrodata Ltd. is a specialist manufac-
turer and integrator of fibre interface conver-
sion and multiplexing equipment and can be
reached at www.metrodata.co.uk
Helping North Sea rigoperators get moredata through their fibre- Metrodata'smanaging directorRichard Kirby
A fibre interface converter device, in this casefor serial to fibre connection, illustrating thedual (redundant) fibre connectors forresilience
DEJ26_28pages:Layout 1 16/08/2010 17:31 Page 28
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