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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

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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 [email protected]

Consultant editorDavid Bamford

Technical editorKeith [email protected]

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 [email protected]

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!


Mer

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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


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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


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


Leaders


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.”


8

Leaders


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



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.



11

Exploration


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


12

Exploration


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

[email protected].

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



14

Exploration


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


15

Exploration


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


16

Exploration


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)


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18

Exploration


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


19

Exploration


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


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



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• OpenText Livelink

• Bentley ProjectWise

• PanagonTM

Applications

• PetrelTM

• KingdomTM

• PetrobankTM

• GeoframeTM

• OpenWorksTM

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• OpenSpiritTM enabled data stores

External data sources

• DISKOSTM

• LicenseWebTM

• ArcticWebTM

• Norwegian Petroleum Directorate

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(Offshore247, Energi-pedia, etc.)

...and many more data sources that are

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• KingdomTM

• PetrobankTM

• GeoframeTM

• OpenWorksTM

• FinderTM

• LogDBTM

• SeisDBTM

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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


Production


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


Production


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-


Production


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

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Production


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


Production


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


Production


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


R E D E F I N I N G I N T E R P R E TAT I O N

Interpreting and ImagingPre-Stack and Full Azimuth.

This is your Paradigm.

REDEFINING INTERPRETATION TO MEET YOUR CHALLENGES

Paradigm enriches classical interpretation and characterization workflows with

comprehensive pre-stack interpretation, including anisotropy and full azimuth analysis.

Your team will concurrently characterize and interpret while understanding imaging

and illumination issues. So you can accurately target complex hydrocarbon plays.

Get enriched results. Find out how at pdgm.com

Visit us at Booth 1308 at SEG in Denver

HEDHED

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Date post:	18-Jun-2018
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