dej20:layout 1 14/08/2009 10:23 page 1 bp: value from...

September 2009 Issue 20

BP: value fromconnectivity

Can seismic beimproved?

Robots in the well

™

Associate Member

DEJ20:Layout 1 14/08/2009 10:23

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DEJ20:Layout 1 14/08/2009 10:23

September 2009 Issue 20

September 2009 - digital energy journal

Digital Energy Journal is a magazine for oil and

gas company professionals, geoscientists, engi-

neers, procurement managers, IT professionals,

commercial managers and regulators, to help

you keep up to date with developments with

digital technology in the oil and gas industry.

Subscriptions: Apply for your free print or elec-

tronic subscription to Digital Energy Journal on

our website www.d-e-j.com

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 ForumsOctober 20th - Russia, the Arctic / subsalt, ridgesNovember 17th - Kurdistan / Iraqwww.findingpetroleum.com

Social networknetwork.findingpetroleum.com

Advertising and sponsorshipAlec EganTel +44 (0)203 051 [email protected]

1

Cover photo - Modelling salt: a model of a saltdome made using Paradigm SeisEarth, a toolwhich can analyse seismic data from a prospectscale to a basin scale in 2D or 3D. Being able toview data in a basin scale changes the nature ofan interpreters’ questions, Paradigm says – eginstead of asking “where are the hydrocarbons inthis prospect?” the question can be elevated to“Where are the prospects in this basin?” Or, “Whyisn’t there a producing field here?”

David BamfordConsultant Editor, Digital Energy Journal

Gravity and cheaper 3D -transformational technologies?

Much is made of the fact that the oil & gas resources of our planet will last many decades

yet: this is evident if one digs into the most recent BP annual Statistical Review of World

Energy (www.bp.com/productlanding.do?categoryId=6929&contentId=7044622). It is also

true that much of this petroleum still needs to be found, whether in new discoveries or up-

grades of existing discoveries or increases in the recovery factor of currently producing

fields or even in the resurrection of currently abandoned fields.

Finding Petroleum in the future will take us to tougher areas, more complex geology,

more difficult reservoirs and, unless we are very smart, much higher Finding Costs. It would

be wrong, ironic and a great shame if, as companies increased expenditures coming out of

the current downturn, they find less barrels and molecules due to tough problems and ram-

pant oil field service prices!

“Know How”, including the smart application of technology, is the key. Although the

oil & gas industry is perceived as deeply conservative, nonetheless it has given birth to, and

matured, some truly transformational ideas and technologies. As a geophysicist, I’d think for

example of the shift from analogue to digital technologies, from explosives to air-guns and

vibrators, from 2D to 3D seismic. I guess I started working in the industry a few years be-

fore the first “postage stamp” 3D surveys were shot over producing fields in the North Sea:

when I moved to Aberdeen in 1986, I was stunned to learn that it took up to two years to

move from planning a 3D to having a 1st Pass interpretation.

Subsequently Finding Petroleum was revolutionized during the 1990’s by the availabil-

ity of ‘exploration 3D’ covering huge offshore areas at low unit cost and, eventually, with

much shortened plan-through-to-complete interpretation cycle-times. Of course there was

huge customer ‘pull’ – led by the Majors – but if I had to single out one decisive contributor

it would be PGS who introduced their RamForm vessels, towing multiple streamers, and

transformed 3D marine acquisition technology ‘overnight’.

If I had to choose one potentially ‘transformational’ technology of today, unusually for

me I would look away from the seismic world to gravity gradiometry, especially airborne,

systems. Such systems measure changes to the gravity vector components, the gradients or

spatial rates of change, in the gravity field. Unlike a conventional gravimeter, which meas-

ures only the magnitude of the gravity field, these systems acquire data from all directions.

Gravity gradiometry may well prove invaluable onshore as a relatively inexpensive – though

not ‘cheap’ - reconnaissance tool that allows subsequent, more expensive, seismic to be well

focused and seems (to me) to be a world away from the vague and ambiguous offerings of

conventional gravity and magnetics. ArkEx and Bell Geospace are leading the charge.

Linked with both of the above, my ‘desired technology of the future’ is easy to articu-

late – onshore and transition zone 3D seismic that has similar unit costs and cycle-times to

marine 3D. As the unit costs for a ‘difficult’ onshore 3D can be an order of magnitude more

than those for a straightforward marine survey, I have to admit that these words are easier to

articulate than to deliver! But in a UK Government-like surge of optimism, I can see ‘green

shoots’! My impression is that such a technology transformation is most likely to be led by a

relatively new player (as PGS were, and ArkEx and Bell Geospace are) rather than one of

the ‘big boys’.

Perhaps that’s inevitably true of any technology, in any industry? Perhaps the big, es-

tablished players have so much invested in their current offerings, including emotional and

intellectual investment if they developed their current technology themselves, that they find

it difficult to think ‘outside the box’ and/or spend more of their energies trying to keep new

players out of their market?

Nevertheless, if we could have gravity gradiometry and cheap, rapid 3D everywhere,

that would really help Finding Petroleum.

David Bamford is a non executive director of Tullow Oil and a past head of exploration with BP

DEJ20:Layout 1 14/08/2009 10:23 Page 1

The 5th INTERNATIONAL CONFERENCE ON INTEGRATED OPERATIONS IN THE PETROLEUM INDUSTRY, TRONDHEIM, NORWAY 29–30 SEPTEMBER 2009

Established by the Research Council of Norway

Kyoto University

Partners in the Center for Integrated Operations in the Petroleum Industry:

Cooperating academic partners:

Intelligent petroleum fi elds and integrated operations for better productivity and safety

eFieldsSmart FieldsDigital Oil FieldsFields for the Future

SessionsIO 09 will highlight aspects of the technologies and work processes for better productivity and safety. 1. Intelligent petroleum fi elds and IO in a low price scenario 2. IO solutions for improved safety and environment 3. Smarter oil and gas world – experiences and solutions 4. Roadmap for green fi elds and brown fi elds – IO solutions and IO compliance 5. Pushing the boundary of integrated modeling 6. New work processes and collaboration environment 7. Industrial gaming applications for IO in the oil and gas industry 8. Pushing wired pipe – smarter well solutions and reservoir optimization 9. Operation management through integrated planning and optimized maintenance10. Digital platform for the next generation IO – a prerequisite for the high north

Sponsoring organization: The conference is organized by the Center for Integrated Operations hosted by the Norwegian University of Science and Technology (NTNU) in cooperation with SINTEF and the Institute for Energy Technology (IFE). The IO Center was established in 2006, by leading international oil companies, system suppliers, academic institutions and the Research Council of Norway, with the objective to undertake research, innovation and education on integrated operations. www.ntnu.no/iocenter

International meeting place for business and science: www.ioconf.no

• 35 speakers from international oil and gas companies, service industry, R&D companies and universities

• Young Professional Program, Poster Session Area, Exhibition Area and Excursions to IO facilities

• SME Innovation Forum October 1st: Integrated Environmental Technologies for improved competitiveness and new business opportunities.• Registration and hotel reservation: www.ioconf.no

Jennifer Okimoto Social computing, IBM

Eduardo Salas University of Central Florida, USA

Laurent Coudert Program Director, Electricité de France, France

Dan LejerskarCOO, EON Reality, California, USA

Svein Ivar Sagatun Head of Corporate Initiative Integrated Operations, Statoil-Hydro

Roy Ruså Petoro, Vice president Technology ICT, Petoro

Contents

Can seismic be improved?There’s no better tool than seismic for finding oil. But can it be done any better? The fourthOilVoice / Finding Petroleum Forum, in London in June 24 2009 looked at some of the possibleways

Future of energy debate – GroningenA debate about the future of energy, including climate change and security, was held at aconference to celebrate the 50th anniversary of Groningen gas field – with speakers fromExxonMobil, Solar Century, Shell, Schlumberger and Texas A+M University, together withelectronic audience voting, chaired by Rien Herber, vice president exploration for Shell inEurope

Paradigm upgrades its softwareOil and gas software company Paradigm has launched a new suite of software covering the fullrange of subsurface tasks, including geophysics, geology, petrophysics and drilling engineering,called Rock & Fluid Canvas 2009.

Welltec – robots in the wellDanish company Welltec is making good progress with its robotic tools which can go into awell and make perforations, clean sand or scale, set barriers and open valves, says JørgenHallundbæk, founder and CEO

Linking SCADA development with operational needsJim Fererro, vice president of automation consultancy GlobaLogix, gives his advice on thebest way to get the information you need from your field– by starting with the end in mindwhen creating SCADA automation systems in oilfield equipment, and bringing operators intothe design phase

How you implement technologyCompanies have got very good at choosing technology – but maybe lose value by their lackof attention to choosing how the technologies will be implemented, and measuring thelikelihood of its success, says Dutch Holland

Using massively parallel processing databases?The use of massively parallel processing (MPP) databases could assist with productionsurveillance and optimization, drilling and completions optimization, supply-chain andmaterials-management optimization, and oilfield equipment reliability and maintainability.Mike Brulé, a consultant in E&P information management, explains how

19

Production

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LeadersGravity and cheaper 3D - transformational technologies?Finding Petroleum in the future will take us to tougher areas, more complex geology, more difficult reservoirsand, unless we are very smart, much higher Finding Costs, says David Bamford, Consultant Editor Digital EnergyJournal

BP – using connectivity to drive productivityBP has installed real time monitoring systems on 80 per cent of its high rate wells – along with 2 million datatags and 2,000km of fibre – but there’s plenty further it can go, said David Latin, vice president of E&PTechnology, speaking at a recent OilVoice / Finding Petroleum London forum

Exploration

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digital energy journal - September 2009

BP – using connectivity to driveproductivityBP has installed real time monitoring systems on 80 per cent of its high rate wells – along with 2 milliondata tags and 2,000km of fibre – but there’s plenty further it can go, said David Latin, vice president of E&PTechnology speaking at a recent OilVoice / Finding Petroleum Forum in London.

David Latin, vice president of E&P technol-

ogy with BP, says he believes that connec-

tivity is the grease that drives productivity at

BP, speaking at the recent OilVoice / Find-

ing Petroleum Forum (London, April 22nd).

Digital technology has “helped us do

things more efficiently, more effectively and

at lower cost,” he says.

So far, BP has fitted 80 per cent of its

high rate wells, and 40 per cent of its wells

in total, with technology for real time moni-

toring, he said.

It has already installed over 2m data

tags and has 2,000km of fibre connecting its

facilities.

The company has around 30 in house

staff and 70 consultants working directly on

its “Field of the Future®” project; it also has

a staff member in each of its business units

helping to roll it out, looking at change man-

agement aspects and application of the tech-

nology locally.

In a sense, everybody in the entire com-

pany has been involved in the project at

some point, he said.

“We think we've delivered something

like 80,000 barrels a day of extra production

as a consequence of using this technology to

date and saved more than 100m dollars of

capital expenditure,” he said.

This is a much cheaper way to increase

production than to drill more holes, he said.

“This is very low cost.”

The financial value works out at be-

tween $3 and $6 a barrel, which is is similar,

or better, to doing well workovers, he said.

BP’s digital oilfield strategy started

with its largest and most complex oilfields –

where it has a lot of money tied up.

For example, an early target was its

Gulf of Mexico Thunderhorse platform

which produces 350,000 barrels of oil per

day from 7 wells. “We need to manage them

carefully and ensure we get maximum val-

ue,” he said.

“Digital oilfield allows you to manage

your fields more effectively and more effi-

ciently,” he said. “It’s about reducing capital

costs and reducing operating costs and mak-

ing people more efficient in what they do day

to day.

The main benefits are being able to take

real time measurements of oil, water and gas

production, quickly optimise the complex

production systems, and feed the data

straight into reservoir models.

FutureBut there is still a lot further to go.

“If you think of a future where infor-

mation flows freely and easily to individuals

wherever they are, and it’s been filtered so

they're only getting what they need, and as

much as possible it’s automated, so it does-

n't need to go to an individual unless they

need to make a human decision, and it’s ap-

plied across the whole value chain, I would

say we're miles away from being done,” he

said. “We're all in the infancy really.”

Another challenge is working out how

to use it viably in low rate onshore wells. “It

requires different types of thinking and dif-

ferent solutions.”

“In North America a lot of the issues

are to do with people driving large distances

to gather data or do maintenance.”

There is plenty more progress to be

made in how the data is used to improved

reservoir management, he said; there is also

new nano technology being developed which

might be able to “revolutionise what we can

do with reservoir engineering,” he said.

BP is making efforts to protect its tech-

nology investments. “The market is quite

immature and we think we're quite far ahead

of where the market is and that adds value

to us,” he said. “I think this will ultimately

separate winners and losers in the future.”

Three layersBP sees the digital oilfield in 3 layers – data

infrastructure and architecture at the bottom,

then a middle layer where that data is turned

into information, then a top layer when you

try to work out if you can do with the data

to optimise what you are doing.

“That's how we think of digital oilfield

- and it really applies to everything from the

oil in the ground through to our terminals -

and we apply it to our refining as well. IT re-

ally touches every part o f he business,” he

said.

Fibre cableIn the Gulf of Mexico, BP has laid a 1300km

cable which connects all of its platforms.

The cables provide 2,500 times the band-

width of a satellite connection.

The cable has proved particularly use-

ful in hurricanes, he says. “We have 20:20

vision of what goes on in the platforms,” he

said. “We're down manned, but we can still

see everything, we know everything. We

know if anything has happened and we can

start to plan a recovery. We're the only com-

pany that has that capability in the Gulf.”

The system is very helpful for people

actually working on the platforms. “You can

use software and it downloads instantly,” he

said.

Remote drillingIn Indonesia, drilling engineers in Jakarta

watch real time drilling data from the field

operation 2,000 miles away in West Papua.

“Having this real time connected-ness

between the field team and experts in the of-

fice really does improve how people work

together,” he said.

"Connectivity is the grease that drivesproductivity" - David Latin, vice president ofE&P technology with BP

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Leader


eters and try to analyse in real time what

your drilling parameters are and try to pre-

dict when the bit might fail, and then choose

when you trip out of the hole rather than let

it happen to you.”

Data analytics could be useful to

analyse data from neighboring wells and try

to work out how they might be connected

underground.

PeopleThe biggest challenges with this kind of

technology is usually connected to people.

“Its 80 per cent about people, 15 per cent

about processes and 5 per cent about tech-

nology,” he said.

“When you have a brownfield - eg for-

ties field that's been running for a long time

people have been working on it for a certain

time in a certain way - the behavioural

change aspects to that are far greater than for

when you have a new field in a new environ-

ment with a new workforce and they start

working like that from day 1,” he said.

This means that it can be easier to in-

stall digital oilfield technology on new fields

rather than older ones.

“This particular team think they have

saved something like something like 7 days

of non productive drilling time on the 2nd

well.”

“They had a well control issue - they

solved it something like a week faster than

they would have done without this kind of

connectivity. It also saves a lot on travel

costs as well.”

InstrumentationThere is nothing new about installing tem-

perature and pressure equipment in wells,

but what is new is using this information to

calculate flowrates and production from the

well.

Oil companies always calculate what

each field is producing for management and

regulatory purposes, but they haven’t histor-

ically measured the production from individ-

ual wells.

“Historically it has been done by test-

ing wells at intervals - they can be quite big

intervals - between those intervals you won't

know what a well is producing. There's typi-

cally an allocation error of between 15 and

20 per cent in a normal oilfield,” he said.

However from the continuous tempera-

ture and pressure measurements, it is possi-

ble to measure the flowrate to an accuracy

of +/- 5 per cent, including flowrates of oil,

gas and water.

“If you’re managing a reservoir, you

need to know where your oil gas and water

are coming from and going to,” he said. “If

you have a 20 per cent error - that will result

in poor reservoir management and low re-

covery.”

It is also possible to measure the pro-

duction from different intervals within a sin-

gle well.

“In Azerbaijan, we run fibre down our

wells - it collects distributed temperature da-

ta, and that can be converted into informa-

tion about flowrates, real time,” he said.

“It shows where the flow is coming

from in those layer intervals. It can show you

where you want to add water,” he said.

Combined with 4D seismic, it gives

you a clear view about which zones are pro-

ducing.

Production optimisationA good example of how the technology has

been used to optimise is in the Schehallion

field, West of Shetland, where a new system

was implemented to reduce slugging by

changing gas injection and throttling the pro-

duction line.

The production system is very compli-

cated, with gas injection, production through

long horizontal wells, producing oil, gas and

water, gathered at an FPSO.

“It’s a very complex system and can be-

come very unstable,” he said. “One of the

things you'd like to do is stabilise that sys-

tem and increase overall production rates

from it.”

One of the biggest problems is slugs –

where liquid or gas builds up in the well and

comes out suddenly – instead of a continu-

ous flow of liquid and gas mixed together,

which is much easier to handle.

By manipulating the choke valve at the

top of the riser according to the computer

model, BP was able to keep the flow of oil

and gas coming smoothly through the well

and avoid slugs. “This mechanical calcula-

tion actually worked,” he said.

Data analyticsA growing area is data analytics services.

“These are already being used in oil re-

fineries, to try to predict when components

will fail,” he said. “But it is in its infancy in

terms of reservoir.”

“That's an area that will really take off

in the next few years.”

“There's a tsunami of data coming now,

how does one manage one's way through that

smartly?”

One of the things we're doing that we

find very valuable is using data about histor-

ical performance to bound future perform-

ance and to make business decisions,” he

said.

“So for example, we can look at our

pipeline and how measurements of wall

thickness over time and how corrosion takes

place - and use that to make empirical

physics calculations as opposed to theoreti-

cal physics calculations.”

“Another type is to use drilling param-

You can watch Mr Latin’s full presenta-

tion in video on the Finding Petroleum

website:

www.findingpetroleum.comclick on half day forums (top left), click

on "the digital oilfield" (top left), scroll

down to "The Digital Revolution and BP's

Field of the Future® Program", then click

on "Click here to View the David Latin

Presentation"

BP has fitted 80 per cent of its high rate wells, and 40 per cent of its wells in total, withtechnology for real time monitoring

DEJ20:Layout 1 14/08/2009 10:24 Page 6

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Exploration


Can seismic be improved?There’s no better tool than seismic for finding oil. But can it be done any better? The fourth OilVoice /Finding Petroleum Forum, in London in June 24 2009 looked at some of the possible ways.

Ian Jack, a past subsurface R+D manager at

BP and instigator of its ‘life of field seismic’

project, believes that the best way to improve

seismic is to increase the speed seismic sur-

veys are done.

If seismic surveys could be done faster,

they could be done cheaper; and both the in-

creased speed and lower price would make it

easier to approve decisions to undertake a

survey. So more surveys would be done, and

both oil companies and vendors would be

happy.

One relatively easy way to increase the

speed of land surveys, he suggests, would be

to get rid of the cables between data recorders

which are spread out over the field. This

would mean much less weight to carry

around (so a much faster survey) – and a low-

er capital cost for the overall equipment.

With the cables, there can be 20 to 60

tons of equipment that has to be moved in a

day, he says. So overall costs can be reduced

by 35 to 40 per cent by using lighter equip-

ment.

The recorded data can either be sent

wirelessly, or just stored it together with the

data recorder and downloaded it later.

Meanwhile Stuart Papworth, global ac-

count manager with WesternGeco looking af-

ter BP and Shell, believes that the most im-

portant thing is to drive efficiencies over the

whole process of gathering and processing

seismic data, and how the data is communi-

cated in the field (cables, wireless or stored

in receivers and downloaded later) is of sec-

ondary importance.

WesternGeco has managed to make

enormous improvements to the overall seis-

mic process by reducing noise, and can get

the same quality of signal from 4-8 receivers

as can normally be achieved with 12-48 re-

ceivers.

Current successIt is important to acknowledge that many

parts of the world are currently seeing as-

tounding success rates with the current tech-

nology. For example, BP and its partners

have had successes for 18 out of its past 19

wells drilled in DW Block 31 in Angola, said

conference chairman David Bamford (a past

head of exploration with BP), and in its one

failure, “they kind of ignored the regional ge-

ological message”. Similarly, Tullow Oil in

deepwater Ghana had had 8 out of 8 success-

es, he said.

The story is not so exciting in the North

Sea, he said, where oil companies are cur-

rently seeing a success rate of around 23 per

cent.

However the North Sea success rate did

increase from 15 per cent to 35 per cent over

the period 1996 to 2000, a factor Mr Bam-

ford mainly attributes to the increasing use

of 3D seismic. Clearly, oil companies would

love to see a new technology which could get

North Sea success rates back to 35 per cent

again.

Meanwhile there is a growing gulf be-

tween marine and land seismic surveys – be-

cause doing 3D surveys at sea has (so far)

proved much easier than 3D surveys on land.

Selling equipmentA crucial factor with new seismic technology

is that the companies who rent out seismic

equipment or do seismic surveys don’t nec-

essarily have an incentive to spend millions

of dollars on new equipment, particularly if

it hasn’t been tested.

It is easy to believe that if you invent

new, better technology there will always be a

big market for it, because this is how the con-

sumer goods market works. But it isn’t nec-

essarily true.

Some oil companies are starting to pur-

chase equipment themselves rather than wait

for their contractors to buy it. “I think that's

brilliant,” said I-Seis’ Mr Heath.

Jack Caldwell from Oyo Geospace said

the thought that the costs of marketing new

technology and getting it accepted are so high

there will probably only be 2 or 3 wireless

seismic suppliers by the end of it.

Mr Caldwell said he thought that now

many oil companies have closed their re-

search centres, it gets very hard to find some-

one at oil companies you can talk to about

new technology. “It’s difficult to find some-

one to talk to,” he said.

Cutting the costsThere was a discussion about how the costs

of seismic equipment can be cut. The most

important components – batteries, memory,

microchips, have been steadily (or rapidly)

decreasing in cost.

Ian Jack said he thought reducing the

number of wireless seismic equipment sup-

pliers would be a good step to reducing the

costs of wireless seismic, because the more

products individual companies were manu-

facturing, the lower the manufacturing costs

should be. “There should be just 2 suppliers,”

he said. “Volume is the key.”

The land seismic market needs some-

one similar to Anders Farestveit, he said. Mr

Farestveit, as managing director of Norwe-

gian seismic company Geco in 1972 to 1992,

can take a lot of the credit for making marine

seismic surveys viable, by getting the first

vessels specially built for seismic surveys, re-

placing vessels which were not very suited

for the task – expensive and unreliable.

Mr Jack said he has heard that any mi-

crochip can be manufactured for $5 each, no

matter how complicated it is, so long as there

are enough of them being made.

Mr Jack asked if it might be possible to

use more off the shelf products in seismic

equipment, for example, microchips for con-

sumer audio equipment are made for $5 and

can handle 24 bit audio.

These chips would not work for seismic

equipment because people want a dynamic

range of more than 100 decibels, said i-Seis’s

Mr Heath.

One obstacle to getting the costs down

is that customers expect to see a complex list

of specifications for new products and this all

costs money to make. “If you try to sell a sys-

tem that doesn't have them, the door can get

stuck in your face,” Mr Heath said. “But we

don't need a huge series of specifications.”

Mr Jack said he believed efforts were

currently underway to reduce the costs of 4D

seismic with receivers on the ocean bottom.

The current costs of this technology is a

big obstacle, he says, because it is normally

paid for out of an asset manager’s budget, al-

though the rewards for it don’t come for

many years, when someone else will proba-

bly be in the job.

Getting rid of cablesBob Heath, technical marketing manager

with International Seismic Corporation (I-

Seis), a wireless seismic data company set up

by Seismic Source Company, believes that

seismic exploration will be cheaper, safer and

more environmentally friendly if it is done

without cables.

“If you were inventing land seismic to-

day there is no way you would use cables.

But that's not what's happening, cables

haven't gone away, and cable free systems are

not really yet successful,” he said. “The

largest crews are with cable. The cable sys-

DEJ20:Layout 1 14/08/2009 10:24 Page 7

tems do rule, but I don't think it’s OK.”

Cable manufacture and disposal, not in-

cluding transportation before, during and af-

ter use, is responsible for 250,000 tonnes of

CO2, he said. “The biggest cost with a cabled

system is the plastic and copper that goes in-

to the system.”

“The biggest problem is actually chang-

ing your attitude – getting you to accept the

new technology,” he said, addressing the au-

dience. “We'll solve it only if you encourage

it more.”

“You’re all addicted to cables and you

don't admit it,” he said. “You like the feeling

of security with cables, be honest. And you’re

probably not worried about the maintenance

cost and downtime.”

The weight of equipment per channel is

just 3kg if there are no cables, compared to

6.5kg per channel if it is cabled, he said.

Meanwhile there is a steady increase in

the number of channels being used in seis-

mic survey (for the same number of crew) –

Mr Heath reckons that over the past 40 years,

the number of channels per crewmember has

roughly doubled every four-five years.

Tough seismic nutsIan Jack, a past subsurface R+D manager at

BP and instigator of its ‘life of field seismic’

project, talked about the range of difficult

problems which are often encountered doing

seismic surveys in shallow waters and on

land, or as he put it, “tough nuts to crack.”

For shallow waters, towed streamer sur-

veys are not very practical – with potential

damage to both the cable and the seabed.

Making a source for the seismic wave – set-

ting off explosives in shallow water – is not

very easy. “Shallow water surveys are slow

and expensive,” he said.

On land, the sources are normally vibra-

tor trucks, which are “generally slow, heavy

and expensive,” he said. But they can be half

the cost of explosives – which need to be

drilled into the ground, requiring the trans-

portation of drilling equipment to the loca-

tion.

BP has an interesting project to improve

the efficiency of vibration trucks – where the

receivers are kept recording all day, and the

drivers autonomously go to the different lo-

cations and set off shots, without co-ordinat-

ing their shots with the other trucks, which

slows everything down. He noted that West-

ernGeco recently announced a world record

of 13,315 vibrator points in one day while

conducting a survey for BP in Libya.So

things are improving.

There are plenty of other challenges

with land seismic. Mr Jack told stories of

when explosives set off in a rainforest caused

tree kangaroos to fall out of trees; when a

bridge was built across a river in Papua New

Guinea for a survey, which enabled two tribes

who had never spoken to each other to meet,

leading to various cultural problems.

WesternGeco’s UniQStuart Papworth, global account manager

with WesternGeco, looking after BP and

Shell, talked about WesternGeco’s UniQ seis-

mic survey system. Analysis from potential

exploration projects in North Africa show

that the system could be used to cover in ex-

cess of 30 km2 per day using a combination

of point-receiver super-spreads and simulta-

neous source techniques that use multiple vi-

brator groups shooting simultaneously at dif-

ferent locations

One of the key requirements to fast and

efficient acquisition is enabling the deploy-

ment of huge spreads with low sensor densi-

ty. The UniQ acquisition system enables

equivalent noise reduction with between 1/3

and 1/6 the sensor density of a conventional

acquisition and processing approach. This is

achieved by processing developed specifical-

ly for individual point-receivers.

WesternGeco calls the initial processing

for noise suppression and signal preservation

on point-receiver data “Digital Group Form-

ing” (DGF). The high channel capacity of

UniQ, combined with an overall reduction in

sensor density, provides the perfect platform

for large spreads within which simultaneous

source techniques can be used effectively.

“A typical UniQ exploration scenario

has 4-8 sensors distributed over each 50 m of

receiver line. Combining the data from 4-8

receivers with DGF will give you an equiva-

lent data to a conventional geophone array

with 12-48 geophones,” he said.

The system is equally good for doing

both full-azimuth high-resolution reservoir

surveys (with higher sensor density) and fast

and efficient exploration surveys (with a low

receiver density), he said. The 150,000 chan-

nels capacity makes the acquisition of full-

azimuth point-receiver surveys a commercial

reality.

The sensors are managed within an ac-

quisition grid rather the traditional linear

arrangement. The data can take any route

through the grid to the recording truck. So if

any part of the cable is cut, the data has an

alternative path to the recording truck. Hav-

ing such multi-path capabilities also enables

flexible deployment to get around obstacles.

These features ensure that such a high chan-

nel count system can be used reliably.

However, it’s not all about channel ca-

pacity and efficiency, the system also uses the

latest WesternGeco broadband sensor and

source technology to get low and high fre-

quency data, which are important for resolu-

tion, deep imaging (low frequencies) and re-

liable inversion to rock properties.

So what about cables vs. cable-less?

The system uses cables, as this was seen as

the most effective way of handling both the

required data capacity and point-receiver dis-

tribution. “It’s all about deciding on the de-

sired geophysical approach to solving tough

seismic problems, both in terms of quality

and efficiency, and then selecting the most

appropriate technology to support it. It’s not

about selecting a technology and then trying

to figure out what you can do with it,” he

said.

Oyo – store but don’t communicateJack Caldwell from Houston seismic instru-

mentation company Oyo Geospace talked

about a new system his company has devel-

oped for seismic data recording, called Geo-

space Seismic Recorder (GSR) which just

has a geophone, a data recorder and a battery

– so the seismic data is not communicated at

all from the recorder, until it is stored and col-

lected at the end of the survey.

The data recorder has a GPS system in-

side, so it can record its exact location and

keep accurate time. It can also keep accurate

time for several hours if it loses communica-

tion with the GPS.

It can store 4 gigabytes of data on each

channel (up to 4 channels). This gives it 740

hours or 1480 hours of recording time (de-

pending on the size of battery used).

The devices can communicate critical

data a short distance – for example to a truck

or helicopter, so you can drive or fly around

the survey area periodically to check that

they are all functioning properly and the bat-

teries are charged.

The recorder uses one highly sensitive

geophone, instead of using 6 geophones and


Exploration

8

The UniQ Geophone Accelerometer (GAC) canbe part of a network of up to 150,000channels and provides an improved lowfrequency response and an essentiallyperfectly flat response curve throughout thenormal range of seismic frequencies

DEJ20:Layout 1 14/08/2009 10:24 Page 8

“Embedding Energistics open standards into our E&P products allows Landmark to reduce R&D costs and enhance connectivity with our global customers.”

Paul KoellerPresident Landmark Software & Services, Halliburton

DEJ20:Layout 1 14/08/2009 10:36 Page 9

Authority and the Ugandan Army on the proj-

ect.

Combating the threat of disease was a

big challenge, with cholera outbreaks being

reported twice close to where crew were

working.

The oil reservoirs were at depths of 500

to 1200m, so they could be drilled “really

quickly,” he said.

The seismic survey team worked very

closely with the company’s geological and

geophysics groups, with software tools which

could enable them to look at the same im-

ages.

One project, the initial seismic survey

did not show up a fault, although it was

known to be present. The company was very

keen to find out more about where the fault

was, so it did not end up drilling through it.

A closer look at the seismic data was neces-

sary.

The company thought it would be bet-

ter to process the seismic data in house. “It

would be hard to ask a seismic contractor to

just process the central bit first,” he said.

Tullow modelled the ray paths where

they were bouncing from the surface rock,

then up to where the fault was thought to be,

and up to the surface; and as a result got a

much better image. This work was made over

a period 9 months from May 2008 to March

2009.

case with mesh radio networks, he said.

The system has a highly accurate time

clock, so can still keep recording for a few

hours even if it loses connection to the clock

from the GPS (GPS lock). It has the option

to use GPS time retransmission for where

GPS lock may be marginal, and is about to

offer its SynchroSeisTM technique for the Sig-

ma system meaning no radio communica-

tions at all is required to provide timing to re-

mote ground units, allowing units even to be

submerged.

Along with Sigma’s “Smart Harvest”

techniques, the Sigma system solves the three

major issues associated with first generation

able free systems (shootblind, timing distri-

bution, and intelligent downloading) making

Sigma a much more universal acquisition

system.

Finally, given Sigma’s parentage, Bob

Heath states that source controllers are hav-

ing to change to cope with the new ways in

which land data can be acquired using sec-

ond generation cablefree systems.

John Doherty, Tullow OilJohn Doherty with Tullow Oil, talked about

his company’s experience exploring for oil

in Uganda using seismic.

The company has acquired license

blocks in the Albertine Graben, much of

which is under Lake Albert in Uganda. It has

12 oil fields discovered in the past 3 years. It

is comparable in size to the South Viking

Graben in the North Sea, which has over 50

fields. “It’s a new and exciting frontier

province we’ve opened up,” he said.

The area has been a target for oil explo-

ration for many years, because there are

abundant oil seeps coming to the surface.

Licenses to explore for oil were held by

the Anglo Persian company (which later be-

came BP) as far back as the 1920s.

Tullow acquired 2D data in the area be-

tween 2001 and 2005. In 2006 it found oil in

two different blocks, which was “very en-

couraging,” he said. Lately, it has been suc-

cessful with 24 out of the last 27 wells

drilled.

The terrain has proven very challeng-

ing, with a big escarpment (cliff) leading

down to a level area of land, next to the lake.

All of the equipment for surveying and

drilling needed to be carried over the escarp-

ment.

Tullow had to build its own roads,

bridges, runways and jetties.

There were plenty of hazards to the seis-

mic survey. The area being surveyed has 20m

high cliffs in it, and frequent bush fires in

summer. There are alligators and hippos.

There was also a firing range. Tullow needed

to work closely with the Ugandan Wildlife

summing the output from them (which is the

standard practise).

The system is designed to be easily

portable. A 1,000 channel system can easily

be handled by a 12 person crew, he said. You

can install 40 to 60 complete stations

(recorder, battery, and geophone) in a mini

pick-up truck. Equipment carried in a 20 foot

container can service 2,000 channels.

The unit has been tested at -40 degrees

C, under 3 feet of snow, and the GPS recep-

tion still worked fine, and the communica-

tions by line viewer worked fine, he said. It

has also been used in desert and brush. Units

have also been buried 6 to 8 inches deep and

worked fine – it can be useful to bury them

to avoid the batteries getting stolen, he said.

I-SEIS - wirelessBob Heath, technical marketing manager

with International Seismic Corporation (I-

Seis), a wireless seismic data acquisition sys-

tem company set up by Seismic Source Com-

pany, a manufacturer of seismic source con-

trollers, talked about his company’s seismic

recorders, which communicate “health” in-

formation via a proprietary mesh radio net-

work using the 2.4 GHz radio band, but oth-

erwise store the data rather than immediately

sending it to the recording truck.

This can provide information that the

unit and geophones are still functioning prop-

erly, along with their location, the battery

voltage – everything you need to know to

know that it is working as a seismic system.

So you can quality control the data, although

you’re not sending the data back to the

recording truck as it is being recorded.

The advantage of the 2.4 GHz radio

band is that no license is required to use it.

Many people have had bad experiences

with 2.4 GHz radio, he acknowledged; they

say that the data can get absorbed by foliage;

this can be true, but the data communications

is more reliable at lower bandwidth and when

it only needs to go a short distance, as is the


Exploration

You can watch a video and presentations

from the conference at:

www.findingpetroleum.com– click on half day forums (top left), tough

problems in geophysics (top left)

Storing seismic data with no cables using thei-Seis system

The I-Seis sigma seismic receivers

10

DEJ20:Layout 1 14/08/2009 10:24 Page 10

Exploration


Future of energy debate – GroningenA debate about the future of energy, including climate change and security, was held at a conference tocelebrate the 50th anniversary of Groningen gas field – with speakers from ExxonMobil, Solar Century,Shell, Schlumberger and Texas A+M University, together with electronic audience voting, chaired by RienHerber, vice president exploration for Shell in Europe.

As part of the celebrations for the 50th an-

niversary of Netherlands’ Groningen gas

field, a debate was held about climate

change, security of supply,

Participants included Jeremy B. Ben-

tham, vice president Global Business Envi-

ronment, Royal Dutch Shell; Hans Door-

nenbal, project manager GASH – Euro-

pean Black Shale Database; Brad Corson,

chairman and production director of Exxon-

Mobil International Limited; Rien Her-

ber, vice president exploration for Shell in

Europe; Stephen A. Holditch, head, Petro-

leum Engineering Department, Texas A&M

University; Philippe Lacour-Gayet, senior

scientific advisor to the Chairman of

Schlumberger; David Lawrence, executive

vice president exploration for Shell; Jeremy

Leggett, founder and executive chairman of

Solarcentury, founder and Chairman of So-

larAid, director of New Energies Invest

AG; David J. Scott, director of economic

development programs in the Earth Sciences

Sector of Natural Resources Canada.

The audience participated through elec-

tronic voting.

Groningen gas field is 30 per cent

owned by Shell, 30 per cent by ExxonMobil

and 40 per cent by EBN (Energie Beheer

Nederland). The field is operated through

NAM, the 50/50 joint venture of Shell and

ExxonMobil. It is one of the top 20 fields in

the world.

The field will provide an estimated

2800 billion m3 (100 trillion cubic feet -

TCF) over its lifetime, and has produced

around 1800 billion m3 (65 TCF) so far. This

compares to an annual gas production for the

whole of the US of 20 TCF.

“Its one of the largest gas discoveries

of all time,” said David Lawrence, VP ex-

ploration of Shell, speaking at a conference

to celebrate the 50 years anniversary of the

field.

When efforts to produce the field start-

ed in the 1950s, “we didn’t expect what we

saw,” said Mr Lawrence. The technology

used to discover Groningen was “quite basic

compared to what we have today,” he said.

“There's a debate about if it was drillers

or geologists who wanted to drill deeper,” he

said. “One of the lessons of Groningen – is

patience, persistence and confidence in your

plays.”

“Groningen

is one of the great

discoveries of the

20th century,”

said Brad Corson,

VP of Europe and

Caspian with

ExxonMobil.

Climate changeShell estimates

that if we carry on

tackling the prob-

lem of reducing

carbon dioxide

emissions in a dis-

organised fashion,

with everyone fol-

lowing their own interests (a scenario it calls

‘scramble’), we will end up with around

1000 parts per million carbon dioxide equiv-

alent in the atmosphere by 2100.

Meanwhile if the world is organised

and makes a co-ordinated effort (a scenario

it calls ‘blueprints’), we will end up with 660

parts per million carbon dioxide equivalent

in the atmosphere.

Meanwhile many scientists have pre-

dicted that the maximum safe amount of car-

bon dioxide in the atmosphere is around 450

parts per million, in order to keep the maxi-

mum temperature rise to due global warm-

ing to under 2 °C.

In a vote, 68 per cent of the audience

agreed or fully agreed that we are currently

following the ‘scramble scenario’ rather than

the ‘blueprints’ scenario, and 32 per cent dis-

agreed.

Jeremy Leggett, founder and executive

chairman of solar energy company Solarce-

ntury, says that what we really need is an ap-

proach he calls “deep blueprints” – going

further than suggested in the Shell scenario.

“Neither of these scenarios come anywhere

close to where we have to be. It has to be

more advanced than any of these scenarios,”

he said.

Mr Leggett said that if we are going to

avoid going over the 450ppm, we can only

extract about a third of the remaining known

reserves of coal, gas and oil (if we don’t have

carbon capture) – suggesting that looking for

new types of gas is maybe not such a good

idea.

Jeremy Bentham of Shell, who wrote

the scenarios, agreed that if we’re going to

get closer to the advanced levels of environ-

mental impact, you need to go further than

the blueprints outlined. However he stressed

that the scenarios have been designed around

expected human behaviour. So in order to go

beyond them, “you need unprecedented be-

haviour to meet where we should be.”

“We we’re either deluded or self-delud-

ing in some of these things we are talking

about.”

Rien Herber, vice president exploration

for Shell in Europe, chairing the session, said

he felt very optimistic, using the example of

the recent increased increase in electric cars.

The technology used to discover Groningenwas “quite basic compared to what we havetoday" - David Lawrence, VP exploration, Shell

Delegates at the conference to celebrate the 50th anniversary ofGroningen gas field

11

DEJ20:Layout 1 14/08/2009 10:24 Page 11

12

Exploration


“A year ago electric cars in the Netherlands

was cloud cuckoo land. Now it’s in people’s

minds.”

Public opinion is crucial, Mr NAM

said, because this is what politicians will fol-

low.

Mr Leggett acknowledged that progress

to date more fits the “scramble” scenario, al-

though there are exceptions – for example,

the European Union commitment to a 20%

cut in emissions of greenhouse gases by

2020, compared with 1990 levels; a 20% in-

crease in the share of renewables in the en-

ergy mix; and a 20% cut in energy consump-

tion. “Governments are taking this seriously

and that’s encouraging,” he said.

Philippe Lacour-Gayet, senior advisor

to the chairman of Schlumberger, said he

thought that it was unfortunate that climate

‘sceptics’ were often looked upon in a

derogatory fashion. “Science needs scepti-

cism to progress,” he said.

In particular the phrase ‘global warm-

ing’ is wrong and misleading – because the

warming does not occur evenly around the

globe, but much more at the poles than at the

equator.

However Mr Lacour-Gayet said that if

people are not convinced about global warm-

ing science, they can also see the increasing

acidification of the ocean, and its effect on

coral, as evidence that man made carbon

dioxide emissions need to be reduced.

“Even if you have doubts about global

warming – the acidity in the ocean is some-

thing people can relate to. Eg if you’re a div-

er and you see the state of coral around the

world,” he said.

If it is possible to do carbon capture at

industrial scale (capturing about 30 times as

much carbon dioxide as the 1m tonnes per

year pilot projects under development), then

it should be done, he believes.

Energy securityBrad Corson, VP of Europe and Caspian

with ExxonMobil, focussed his talk around

providing energy security – providing ener-

gy which is available, affordable and reli-

able, and provided in a manner which takes

political and environmental considerations

into account. “Energy security will forever

be a challenge,” he said.

Both industry, government and con-

sumers have a big role to play in ensuring

energy security, he said.

Governments can help by “opening ac-

cess and providing incentives to develop –

providing stable open markets where indus-

try can invest,” he said.

Industry should “press for energy effi-

ciency – ensuring items are affordable,” he

said. “Consumers have a role too – they must

ment funding – if so the solar industry looks

a lot more attractive.

“The next generation of reactor in Fin-

land are 100 per cent over budget and 100

per cent behind schedule. This industry has

been out of practise for a long time,” he said.

“This industry has had half a century to get

it right and it’s failed to do it. And no-one is

going to invest in nuclear without any subsi-

dies.”

“The issue is how much collateral dam-

age this does to renewables. Nuclear indus-

try is saying to politicians – renewables or

nuclear. They’ve kind of declared war on

us.”

David J. Scott, director of Economic

Development Programs in the Earth Sci-

ences Sector of Natural Resources Canada,

said that the fact that no-one wants nuclear

waste stored near their backyard is a formi-

dable obstacle. “We need to move to a more

robust solution.”

RecruitmentOne of the biggest potential constraints on

the oil industry’s ability to meet the demand

for energy is staff recruitment.

In an audience vote, the audience was

asked whether the industry will be short of

young professionals in 5-10 years. 70 per

cent agreed or fully agreed, whilst 30 per

cent disagreed.

Steve Holditch from Texas A+M Uni-

versity said that the question was maybe

framed wrong. It is always possible for uni-

versities to find students, train them and

graduate large numbers of students. The

challenge is more to provide a stable job

market for them despite industry cycles –

and particularly training someone who has

been in the business for 1-5 years to do the a

job which is normally done by someone with

15 years experience.

“I think oil and gas industry is a grow-

ing industry – we will produce more oil and

support industry and government in their ef-

fort and encourage efficient use of energy.”

ExxonMobil strongly believes that

world energy demand will continue to grow

– with China and India accounting for over

40 per cent of the increase in demand.

A lot of this increase in demand will be

satisfied with natural gas, Mr Corson be-

lieves. “We expect natural gas to be the

fastest growing fuel source increasing by 50

per cent by 2030. Much of this growth in de-

mand will come from the power generation

sector, which is expected to increase gas de-

mand by 1.8 per cent per year.”

Meanwhile Europe’s natural gas supply

will increasingly come from outside Europe.

“By 2030, 70 per cent of Europe's gas sup-

ply will come from imports, particularly

LNG,” he said.

On the subject of peak oil and alterna-

tive energy, Mr Corson agrees that “oil and

gas are limited reserves and other energy

will play a growing role.”

“But for the foreseeable future, oil and

gas will play a big role. There are substan-

tial resources left to be recovered,” he said.

The big challenges for the future are

working out how to develop different types

of gas fields – including extended reach

drilling and multizone simulation, Mr Cor-

son said.

Then it is important to develop ways of

moving the gas from field to market – one

of the most important being by liquefying it

(LNG). “New LNG liquefaction trains are 60

per cent larger than previous generations,”

he said. “New LNG vessels are 80 per cent

larger than 2 years ago, using 40 per cent less

energy to power the vessels per cargo ton

mile.”

Nuclear powerIn an audience vote of whether nuclear pow-

er is an essential component in meeting en-

ergy demand, 61 per cent agreed or fully

agreed and 39 per cent disagreed or fully dis-

agreed.

Jeremy Bentham stressed that if no new

nuclear power stations are built, there will

be a big decline in energy supply due to ex-

isting nuclear power stations going out of ac-

tion.

However there are big challenges in re-

building the nuclear power industry – includ-

ing construction, mining, waste management

and redeveloping – and education.

“It takes 10-15 years to develop new

plants, and there aren’t many that are ready

to start,” said one delegate.

Solar Century’s Jeremy Leggett said

that the nuclear industry is starting to posi-

tion itself as in opposition to the renewables

industry, if they are both fighting for govern-

"As soon as it hits someone in the bankaccount, [energy consumption] behaviourswill change" - David J. Scott, director ofEconomic Development Programs in theEarth Sciences Sector of Natural ResourcesCanada

DEJ20:Layout 1 14/08/2009 10:24 Page 12

DEJ20:Layout 1 14/08/2009 10:25 Page 13

gas going forward,” he said. “It’s a good line

for young professionals to join our industry,

But we need industry to hire some of

our students to make sure they show up

again next year.”

The oil and gas industry does need to

work out ways to train people faster, said Mr

Holditch. “We can’t do training like we’ve

always done it and hope to get there. We

have to come up with a new training system

that doesn’t’ exist now. For example systems

that can spot the gaps in [someone’s] com-

petency. There are companies working on

that right now.”

There might be less students applying

to work in the oil and gas industry from Cal-

ifornia, but there are still plenty of people

from other regions – for example, Texas and

Egypt, Mr Holditch said.

Brad Corson from ExxonMobil ac-

knowledged that “Texas A+M is a very

strong pipeline of strong talent coming into

ExxonMobil.”

“It’s not about having enough new em-

ployees – its ensuring we can capture the

knowledge of the people leaving the indus-

try,” he said. “That’s a great wealth of

knowledge and we need to capture that.”

We also have a responsibility with chil-

dren in grade school and high school to show

them “the opportunity that the technical pro-

fessions provide so they see the excitement

and want to pursue these career paths.”

Mr Lacour-Gayet from Schlumberger

said that the oil industry should never be in

the situation it is currently in, with the aver-

age age of its employees much higher than

the average age of working professionals,

because it means that the company gets out

of touch with society.

“If your employees are older than your

society there are great difficulties in under-

standing new things coming,” he said.

“Young people play an important role in

bringing new things in.”

Companies should continue recruiting

even though there is a downturn, he stressed.

“I think, in a downturn, you have to make

room for young people.

“New” energy is often proving much

more attractive to employees than the old oil

and gas industry. When working as CEO of

Shell Hydrogen, Mr Bentham said he would

sometimes get “several hundred” people a

week applying for jobs. “There was some-

thing about the area that attracted people to

work within it,” he said.


that the average age of many people work-

ing in cleantech companies such as his is in

their 20s, compared to the average age of

people in the oil and gas industry of around

49. “We have defections from BP and Shell

cians are very confused with the possible ex-

ception of Denmark. They don’t know where

to go and they need very good advice,” he

said.

Another delegate said that politicians

might solve the energy problems if they had

100 years to do it. “If you have less time, in-

dustry has to do it,” he said.

Mr Scott said that we might need gov-

ernment to make low carbon fuels viable.

“Until there is a price on carbon that reflects

the lifecycle cost, there must be a stimulus,”

he said.

Public responsibilityMany speakers emphasised the importance

of the general public taking responsibility

and getting involved in energy issues – too

often, the only time industry comes into con-

tact with the public is where there are com-

plaints or someone doesn’t want something

built next to them. The politicians ultimately

follow the public’s will.

Schlumberger’s Philippe Lacour-Gayet

emphasised the importance of the public as

the ultimate decision maker. “It’s very clear

that if the public doesn’t buy the solution, it

won’t work, as we see with nuclear power,”

he said.


for Shell in Europe, chairing the session,

pointed out that the public will “generally”

look for the cheapest, rather than the most

environmentally friendly products.

However oil and gas isn’t necessarily

cheap. “– I look at last summer when oil cost

$147 – consumers took different choices

about their automobiles. As soon as it hits

someone in the bank account, behaviours

will change,” said Mr Scott.

There is plenty of frustration in the in-

dustry about how much the public seems to

end up obstructing development. “I heard an

expression ‘caveman’ which stands for ‘citi-

zens against virtually everything,” Mr

Holditch said.

in my company,” he said.

“Young people can see the trend – with

companies struggling to replace their re-

serves – or they replace them by merging

companies, then they cut jobs. It can be bru-

tal in the oil industry. It’s much more attrac-

tive for many of these folks on the other side

of the fence.”


for Shell in Europe, said that the company is

currently recruiting people directly from In-

dia and the Far East.

One “young professional” in the audi-

ence, working at ExxonMobil/Shell joint

venture NAM, said he often finds himself in

difficult situations, due to the fact that the

company has “a huge gap in your structure

with a lot of very inexperienced people and

a lot of very experienced people. How are

we going to fill that middle bit?” he asked.

“The gap we have in the middle sector

could be due to cycles in recruitment.

I hope that doesn’t happen again,” he

said.

Where will new technology comefrom?The audience was in strong agreement that

the energy solution of the future “will be

found by technological ingenuity led by in-

dustry and less by politicians,” with 73 per

cent agreeing / strongly agreeing and 27 per

cent disagreeing.

“As industry we are the legs of society

and get things done,” said Shell’s Mr Ben-

tham. “But we need the ‘brains of society’ –

government – to provide direction.”


that whilst historically it is always industry

rather than government that leads, in future

it is not obvious if the right new technolo-

gies will be developed without government

support, because of people’s lack of incen-

tive to change.

There have been studies showing that

no company has ever launched a product

which threatened its core product, he said –

and so realistically but sadly, it is probably

unwise to expect BP and Shell to damage

their core fossil fuels business with invest-

ment in renewable energy.

“So it’s very sad but understandable

that BP and Shell are now (after dabbling

with these new technologies) miles behind,”

he said. “That’s not to say that it can’t be

done. “Clean tech is highly disruptive tech-

nologies that can invade fossil fuel markets

very quickly.”

One delegate from the Technical Uni-

versity of Delft pointed out that whilst politi-

cians will never lead on technological break-

throughs, they have an important role; and

industry has a role in advising them. “Politi-

"The big challenges for the future areworking out how to develop different types ofgas fields – including extended reach drillingand multizone simulation" - Brad Corson, VPof Europe and Caspian with ExxonMobil


Exploration

14

DEJ20:Layout 1 14/08/2009 10:25 Page 14

15

Exploration


The release has been in the making for about

four years and has been designed to respond

to the industry’s requirement to explore, de-

velop, and produce in areas of increasing op-

erational and technical complexity.

It includes upgrades to 15 of Para-

digm’s “anchor” products and more than 100

add-ons and plug-ins. There are also en-

hancements to its infrastructure and interop-

erability framework (Epos™), enabling geo-

scientists to carry out multi-disciplinary and

concurrent workflows.

“This will be the largest synchronized

release of geosciences applications in Para-

digm’s history, says Duane Dopkin, Para-

digm senior vice president of technology.

“The Rock and Fluid Canvas 2009 re-

lease provides geoscientists and engineers

the ability to carry out advanced workflows

without technology compromises”.

The new software moves towards a full

client-server architecture with new and com-

prehensive data services for interpretation

and project /survey data.

These services facilitate and stabilise

the many data transactions that can take

place when working with data at the project

level and contribute substantially to the data

management capabilities of the system.

The client-server architecture was also

implemented so that the system can easily

scale from laptop to high performance com-

puting clusters, from small local operations

to global enterprise deployments, and from

prospect-scale to regional-scale investiga-

tions.

The services are complemented with

many new data model extensions that facili-

tate multi-survey operations, data queries,

and management of project and survey data.

In Rock & Fluid Canvas 2009 all inter-

pretation data, vertical function data, and

project/survey data are stored in SQLite

repositories. These public domain, self-con-

tained, hierarchical, and relational database

engines are highly suited for exploration and

production data transactions.

Optimized for each data type, the

SQLite repositories are ideal for efficient

handling and management of large numbers

of files.

The release also introduces new data

managers and applications (e.g. Web Asset

Manager) for performing global queries on

data distributed across multiple repositories

and for assembling data from multiple sur-

veys at the project level.

These infrastructure enhancements, in

turn, enable geoscientists and engineers to

optimize their work process across the entire

exploration and production value chain.

Paradigm calls this cross-discipline en-

ablement Higher Order Workflow (HOW),

describing it as a “collective, knowledge-

building process that reduces data loss or

simplification.”

Today’s geoscientists face exponential-

ly larger datasets, increasingly complex geo-

logical structures, and complicated, integrat-

ed operations. Yet, they are being asked to

handle all of this complexity in less time

with fewer people, the company says.

“What was considered a “special proj-

ect’ five years ago is now considered a rou-

tine project,” says Mr Dopkin. “Imaging

seismic data in the presence of anisotropy,

geosteering through naturally fractured

reservoir formations, modelling large and

complex salt structures, performing multi-

azimuth AVA inversion and analysis, corre-

lating hundreds or thousands of wells, and

integrating and modelling electrofacies and

seismic facies are handled quite efficiently

in the Rock and Fluid Canvas 2009 release”.

Other themes of the Rock and Fluid

Canvas 2009 release include “extending the

reach” of seismic interpreters with common

interfaces, common data managers, and

common data models.

This theme has specific interest for

SeisEarth, VoxelGeo, and Stratimagic users

conducting regional to prospect scale inter-

pretation projects.

The Rock and Fluid Canvas 2009 re-

lease also supports data connectivity be-

tween Paradigm interpretation and modeling

solutions. This connectivity enhances work-

flows that move data between Epos data and

Paradigm’s GOCAD and SKUA suites and

was specifically targeted at making inter-

preters better modellers.

The release has practical uses for de-

ployment and investigation throughout the

life cycle of oil and gas fields, including

opening of new plays to reversing produc-

tion decline in mature fields.

“Some of the enhancements in seismic

processing and imaging, AVO, and seismic

inversion also should have a huge impact for

unconventional plays including heavy oil

and naturally-fractured gas reservoirs” said

Mr. Dopkin.

The release has been vetted by Para-

digm early access partners and is scheduled

for general release in July 2009.

Paradigm upgrades its softwareOil and gas software company Paradigm has announced the launch of Rock & Fluid Canvas™ 2009, amajor upgrade of its suite of software that integrates applications for geophysics, geology, petrophysicsand drilling engineering.

“What was considered a ‘high end’ or specialproject 5 years ago is now being considered aroutine project” - Duane Dopkin, Paradigm’ssenior vice president of technology

Finding Petroleumnetwork.findingpetroleum.comJoin our social network!

DEJ20:Layout 1 14/08/2009 10:25 Page 15

Welltec – robots in the wellOilfield service company Welltec is making good progress with its robotic tools which can go into a welland perform perforations, clean sand or scale, set barriers and open valves, said Jørgen Hallundbæk,founder and CEO of Welltec.

Welltec designs and manufactures robotic

tools which can go into wells on a wireline

(electric cable) and perform jobs like remove

scale and sand, make perforations, set barri-

ers to isolate specific areas of the well and

do small clean up jobs, said Jørgen Hallund-

bæk, founder and CEO (speaking at the re-

cent OilVoice / Finding Petroleum Forum in

London).

Applying Welltec’s precision robotics

usually proves more cost-effective than oth-

er methods, such as using a well intervention

rig (snubbing) or coiled tubing, or pumping

high pressure chemicals down the well.

With Welltec’s tools you can also get

the job done quickly, if you need to. “We can

do really rapid response,” Jørgen Hallund-

bæk said. “If that sort of urgency is within

hours it’s all completely feasible. In some

contracts we have equipment standing by -

we can be in the ground within a few hours -

solve the problem and get out again,” he

said.

StatoilHydro has virtually stopped do-

ing interventions by snubbing, doing them

instead using electric wireline with equip-

ment like this, he said.

Welltec has about 500 tools in use and

does about 200 operations a month around

the world.

Welltec started off in 1994 with the

Well Tractor, a tool which can go into the

well pushing its wheels against the side of

the well to convey logging and other tools.

Wireline conveyance presents an alternative

to lowering tools in hole by relying on grav-

ity– and is more effective when the well is

not vertical.

Since then the company has expanded

to offer a range of different precision equip-

ment, including the Well Stroker launched in

2003 with support from BP.

CostsStatoilHydro did a study to compare the

costs of increasing production from drilling

new wells or getting more out of existing

wells using equipment such as Welltec’s.

They found that the ratio of cost of in-

creasing production from a new well com-

pared to from an existing well was some-

thing like 1:6.

“The oil is 'practically free' compared

to the cost of drilling new wells,” Jørgen

Hallundbæk said.

“In the past the approach was that you

had 40 well slots on a platform - and once

production started deteriorating you would

sidetrack to a new well and start producing

from there,” he said.

“But they realised from using Welltec’s

technologies it paid off 6 times better by us-

ing these technologies - and then they still

have the drilling rig available on the plat-

form,” he said.

“Very often, problems are actually

caused by simple well issues,” he said.

HSE benefitsThere are big environmental benefits to us-

ing Welltec’s equipment rather than equip-

ment that requires a drilling rig in order to

function. For example, there is much less

equipment needed to be delivered to the

wellsite (and equipment can sometimes be

delivered by helicopter), which leaves a

much smaller carbon footprint than alterna-

tive methods.

As mentioned, the Welltec equipment

makes it easier to get more production out

of your mature wells, so there is less need to

drill new ones, something that has a huge im-

pact on the environment.

You can also avoid pumping high pres-

sure chemicals into the well for further envi-

ronmental benefits.

There are also safety benefits – the

equipment can normally be operated with

less people than if you need a workover rig.

As the equipment is remote controlled from

surface, as little as two people can perform

an operation miles away from the well. In

Norway, the equipment has even been run-

ning in offshore wells and operated from

shore.

“We can even operate tractors from the

shore. We can remotely operate the wireline,

drum and tractors downhole. Some of the

jobs we are doing in Norway are remote con-

trol - via fibre optics,” he said.

The company decided it would make

all of its tools 90 per cent recyclable from

the beginning. “All the metals are scrapped

and recycled again,” he said. “And we have

an oiling system - a small can of oil - it’s

brought back and recycled, which means that

we leave no mark.”

Improved planningHaving the tools available also makes it pos-

sible to plan the well in a different way. In-

stead of putting a great deal of equipment

down the well when it is built to be ready for

future challenges, you can build the well

simply and add more equipment as required

using Welltec’s tools.

“A lot of wells have been designed to

be intervention free for their whole lifespan,

say 30 years, but we often see a few years

down the road something went slightly

wrong or didn’t behave and it needs some

kind of intervention,” he said.

Welltec’s tools allow a different ap-

proach. You can start your reservoir with a

low capital expenditure and then change

your well as you realise your original as-

sumptions were not exactly what you

thought.

“With our system - you can see as you'redoing the operation that it actually works” -Jørgen Hallundbæk, founder and CEO ofWelltec


Production

Welltec´s "Well Miller" tool will mill outobstructions in the well

DEJ20:Layout 1 14/08/2009 10:25 Page 16

Production

September 2009 - digital energy journal 17

valves. The tools can have a power of up to

1.5 kW, as much as a home hairdryer – but

this is enough to mill through scale.

The tools are often used for sand re-

moval. “A lot of oil wells create sand dunes

at the heel and then production sort of stops,”

he said. “Today, operators are willing to let

us engage in jobs where we do 50 runs of

sand removal.” The reason is that despite the

many runs, the sand can be removed quick-

ly, safely and with a much lighter impact on

the reservoir.

Recently, Welltec introduced a new sys-

tem that is able to both mill out obstructions

and also retrieve the cuttings generated dur-

ing the milling process to surface.

Previously, this could not be done in the

same run so with this new system cost can

be reduced by more than 2/3 compared to

coiled tubing or rig work-over operations.

When downhole obstructions are re-

moved from the well, full flow can be estab-

lished to increase production.

Forget ‘smart wells’Instead of installing expensive ‘smart wells’

where a part of the well can be closed off

once it starts producing water and open an-

other part of the well, why not use Welltec’s

equipment to block and perforate new areas

of the well as needed?

With ‘smart wells’, a large amount of

expensive equipment (also referred to as

‘jewellery’) is put in the well at the begin-

ning, which might never be needed – or if it

is needed, the valve might have seized shut

by the time it is needed.

“Most intelligent well systems have

manual override systems - we can go inside

a smart completion and manipulate the

valves inside if they fail,” he said. “But is it

necessary to build them that fancy [in the

The tools also make it possible to plan

well interventions in a different way. For ex-

ample, if a well intervention is needed but

you don’t know how difficult it will be, you

can start using Welltec’s tools and then bring

in heavier equipment once you are sure that

it is required. This results in both lower cost

and environmental benefits if the lightweight

tools can perform the same job as huge and

heavy equipment.

“If a snubbing operation is not neces-

sary - why not start with something light and

move to the heavier operation when you

need it?” he asks.

“We can solve a lot of problems which

were solved 10 years ago by snubbing,” he

said. “Things which would have been impos-

sible in the past are being done on wireline

today.”

Oil companies are doing more and

more well interventions, because it is be-

coming much cheaper to look for ways to in-

crease production from the wells you have,

rather than look for new areas to drill. Some

mature fields have interventions done every

18 months. “It’s a massive amount of oil you

can produce from these well interventions,”

he said.

Pressure pumpingWelltec often finds itself competing against

the $20bn oilfield pressure pumping indus-

try where chemicals are pumped into the

well at high pressure to do jobs like remove

scale.

These tasks could often be better done

using robotic tools, which can carefully mill

the shale away with keyhole precision, and

then polish the inside of the well so that

shale won’t stick to it again.

There are examples of how the reser-

voir has been damaged from pressure pump-

ing. “Often on depleted reservoirs, it’s not a

good idea to pump fluids down the hole -

you might mess up the reservoir and it won't

produce afterwards,” Jørgen Hallundbæk

said. “You then spend an awful lot of time

stimulating the reservoir to try to get it back

again.”

When working with liquids, a lot of

money is spent just pumping liquid out of

the well at the end. “It's a major fluid col-

umn we have to remove,” he said. “We have

to bail it out or continuously well lift. It

might take 2-3 weeks to get the column bal-

anced again.”

“With our system - you can see as

you're doing the operation that it actually

works.”

Establishing full flowThe Welltec systems can also clean scale

from equipment, such as downhole safety

first place]?”

“To put all that in the ground - you need

a big well head or a narrow production tube.”

Instead, Jørgen Hallundbæk suggests

that you “start your well design very simply,

then as time passes by, you can repair your

field, put in flow control valves in existing

well bores, and they can be maintained and

de-scaled.”

“What is the right balance between how

many sensors, valves, how many permanent

things?” he asks. “Can some reservoirs bet-

ter be drained with more simple completion

technology, allowing smaller wellheads and

smaller equipment in the ground? It’s a dif-

ferent approach to slimhole drilling.”

Well Tractors can be used to inflate bar-

riers downhole, which can control liquid

flow within the well.

So, for example, you can gradually

move the part of the reservoir you are pro-

ducing, by blocking the flow from one per-

foration and creating a new perforation. For

example, if the water level is steadily rising

in the well and you want to make sure you

are producing oil, not water.

“It’s a very simple, cost effective way

of producing from several zones - you can

produce from each zone [then move to the

next],” he said.

How Statoil did well interventions 1992 to 2008 – see the trends in its use for snubbing / rigassisted snubbing (RAS), coiled tubing, well tractor and Riserless Light Well Intervention

For more information about Welltec and

precision robotics, please visit

www.welltec.com

Welltec, Well Tractor, Well Stroker, Well Key,Well Cleaner, Well Miller and Welltec ReleaseDevice are trademarks of Welltec A/S andmay be registered in Denmark and/or in oth-er countries. All products are protected bypatents or patent pending.

DEJ20:Layout 1 14/08/2009 10:25 Page 17

Linking SCADA development withoperational needsJim Fererro, vice president of automation consultancy GlobaLogix, gives his advice on the best way to getthe information you need from your field– by starting with the end in mind when creating SCADAautomation systems in oilfield equipment, and bringing operators into the design phase.

Developing a good SCADA system requires a

two-pronged approach: first defining what in-

formation is important, and then capturing the

data that feeds it.

Information management is the key to

developing the best possible SCADA system.

It is all about the data: the quality, quantity and

the timeliness of data, and how it will be used.

When companies skip the first compo-

nent, and focus just on capturing all the data

they can, they fail. This equates to answering

a question about a specific well site location

by delivering a map of the United States.

Data is valuable when it is understood in

context, in relation to time and other points of

data, and most importantly, when it leads to

action. Companies don’t use data to make de-

cisions—they use actionable information.

Begin at the endImproving an information management sys-

tem doesn’t always require significant expen-

ditures for new technology infrastructure.

It often is as simple as talking to the end

users about improving the tools already in

place.

SCADA systems are often much more

modular than can be imagined. For example,

existing systems can often be expanded or

made more efficient. But even improving ex-

isting systems should take into account the in-

put of the users.

When oil and gas companies facilitate

communication between the team creating the

information management system and the em-

ployees expected to use it, it does more than

improve data capture processes—it creates

ownership and authorship among end-users.

Allowing end users, whether the CFO, a

production engineer or a field technician, to

have a hand in designing the system they need

to do their job creates advocates for the sys-

tem.

Companies enjoy a dual benefit of a

more efficient information management sys-

tem (that produces usable information), and

users who know how to use it to its fullest ca-

pabilities.

A typical example involved an oil and

gas company in Wyoming with an existing

SCADA system.

Though fully implemented, the system

was not employed by the client’s operations

group because it was deemed unusable by the

control room personnel. They had not been

consulted during the system’s design, nor had

they even received training by the system’s de-

signers.

When tasked with redesigning the sys-

tem, GlobaLogix, as the consultancy check,

spent a considerable amount of time with

those operators learning how they worked and

what was important before beginning the re-

design. The revamped system is now a viable

tool.

The control room operators have a sense

of ownership in the system because they

helped create the new screen designs.

In the oilfield, information management

systems are frequently created by the IT team,

which has the technical expertise for the job

but frequently lacks operational experience.

Operational managers are rarely asked how

the systems will be used, or brought in on the

front-end to shape data capture systems.

But they can provide valuable input into

the system when asked to consider questions

like: Which data points should be captured?

How do points relate to each other? How are

alarm management systems structured, and

alarms handled? Are the trending screens

trending things that users actually care about?

When operators aren’t involved, users

often end up with too much information,

which doesn’t lend itself to quick (or accurate)

decision making.

Screen navigationA common issue that impacts the end user is

the screen navigation approach. Simple navi-

gation tools should be created that allow the

control room operator to respond to quickly to

emergencies.

Navigating to relevant screens with a sin-

gle mouse click, rather than using pull down

menus with hierarchical selections requiring

several steps can save time and potentially

lives.

In terms of efficiency, eliminating mini-

mizing/maximizing actions to pull up screens

cleans up the desktop.

A simple early task in the information

management system design process should be

the observation of what operators do each

morning. This gives the SCADA development

team a clear picture of the common repetitive

work processes the control room operator

faces each day, pointing to the reports that

need to be built into the system.

If an operator is taking time each morn-

ing to import data into Excel, then manipulate

it to create the same reports, he is wasting

hours each day rather than focusing on opti-

mizing operations, dispatching personnel and

contributing to overall profitability.

Other questions to consider when devel-

oping a successful information management

system are:

How current is the information, and how

current does it need to be? Is the most effi-

cient and economic polling frequency em-

ployed?

What information does management al-

ways ask for (and how can we deliver it be-

fore they ask for it?)

What is the data path, and is it easily

traceable through the system?

What happens to the data after it leaves

the SCADA system? For example, should it

be made to feed into an Enterprise Resource

Planning (ERP) platform automatically?

What is the purpose of the SCADA sys-

tem? Should it just provide a historical report,

or will it drive dispatch operations, inform

management or provide an accounting func-

tionality? Can the use be expanded?

What are the limitations to growth in the

current SCADA system? How can scalability

be engineered in at the beginning to reduce the

life cycle costs of the system?

What are the security concerns of the

company? How can we satisfy those concerns

without adding cost or levels of complexity?

Are there issues involving custody trans-

fer or hydrocarbon allocation?

Jim Fererro is a Vice President with Glob-

aLogix, a Houston-based oilfield services

company that helps oil and gas companies

achieve greater efficiency, productivity

and accuracy in their oilfield operations

by providing access not just to data, but

to the right information at the right time.

For more information, visit

www.globlx.com.


Production

DEJ20:Layout 1 14/08/2009 10:25 Page 18

Production


How you implement technologyCompanies have got very good at choosing technology – but maybe lose value by their lack of attentionto choosing how the technologies will be implemented, and measuring the likelihood of its success, saysDutch Holland.

Of three major criteria used to make the de-

cision about what to do with a digital oilfield

(DOF) opportunity, two are tagged ADD be-

cause of their additional value that’s previ-

ously flown under the radar:

Technical Assessment of the DOF tech-

nology for proposed utilization in a specific

opportunity

ADD - technical assessment of the im-

plementation method that will be utilized

ADD - Assessing implementation

probability: Economic Pro Forma (or busi-

ness case) based on the relevant implemen-

tation function (i.e., utilization over time).

The upshot is that when companies pre-

pare to make a decision about a DOF oppor-

tunity, leveraging these three criteria will

best help them.

Then, once the decision is made, it

should be clearly and formally communicat-

ed without exception to all affected employ-

ees within the organization to ensure suc-

cess.

Technical assessment of technologyOn the first criterion, Technical Assessment

of the DOF technology, the salient point is

that most companies of any size are not won-

dering how to make decisions.

They already have a way of making de-

cisions around utilizing new technology;

they have specific procedures for bringing

new technologies to the table for discussion,

evaluation and selection.

Additionally, they have technical ex-

perts who are quite accomplished at this en-

tire process. Therefore, no breaking news is

occurring about making a Technical Assess-

ment because of companies’ continued skill

in this facet of the digital oilfield about as-

sessing how the new technologies work and

how they may be best used.

ADD: Technical Assessment ofImplementation MethodBeyond the first criterion, however, new per-

spectives have emerged and proven their

merit in the oil and gas industry beginning

with the second criterion, Technical Assess-

ment of the Implementation Method.

A red flag should pop up for manage-

ment because this particular technical assess-

ment is not made at a detailed or robust lev-

el by most companies’ management.

Specifically, implementation is not han-

dled like the rigorous technical assessment

conducted on the technology itself although

it certainly should be.

Why? One of the problems which hap-

pens too often in the field is literally the lack

of implementation detail available for deci-

sion-making, hence an obstacle to new tech-

nology adoption.

Instead, the scenario which unfolds is

that the individual describing the new tech-

nology is typically unable – in lieu of a de-

tailed implementation methodology – to pro-

vide end-users an accurate picture of (a) ex-

actly how the technology will be integrated

into day-to-day operations and (b) how all

the various risks to business interruption will

be addressed in detail.

In these situations, outcomes can be

somewhat less successful than anticipated.

Sometimes management makes a decision to

move forward with a new technology even

though the implementation methodology has

not been clearly thought through.

Thus, to coin a word, they may make a

decision to implement an “unimple-

mentable” technology.

This outcome obviously produces little

more than a waste of the company’s time and

money, with nothing useful having been put

into motion.

AirlinesLook at a real-world example. Say a major

U.S. airline wants to expand its fleet. Realis-

tically, they only have two supplier alterna-

tives: a major U.S. manufacturer or its Euro-

pean competitor.

When analyzing two competing manu-

facturers, airline management will likely not

find major differences in size, shape, fuel

economy or other major aspects of the of-

fered aircraft. Therefore, they usually make

their selection not based on the airplane it-

self but on which of the two manufacturers

will best help the airline integrate the air-

plane into day-to-day operations.

Essentially, airplane selection boils

down to conducting a highly detailed exami-

nation of the implementation methodology.

In some cases that calls for more detail and

more calculation than required for the air-

craft part of the selection process. At this

juncture is an important advisory. As part of

the Implementation evaluation, implementa-

tion should be simulated so that potential

users can best understand what is required to

actually get the new technology on board at

the company.

This is no different than what a soft-

ware salesman does when conducting demos

of new releases so that users can see what

the software will look like, with all its “bells

& whistles,” once it’s up and running.

Applying that concept to new DOF

technology, management needs to see a de-

mo of the process of implementation of new

technology to visualize what the time and re-

source requirements will be.

To provide some perspective, integra-

tion of new technology into day-to-day op-

erations usually takes both months, not days,

and FTE (full time employed) man-months,

not just number of people involved.

Using the airplane analogy, manage-

ment needs to be able to see how a technol-

ogy implementation will be done: how main-

tenance procedures will be written and im-

plemented to fit new airplanes; what train-

ing will be required of pilots, mechanics and

other personnel; what adjustments to facili-

ties will be needed … with all this folded in-

to a simulation.

Frequently, business cases for new technologyare built on the faulty premise that when anew technology is “up and running” ondesktops and laptops throughout an energycompany, “utilization occurs by magic.” -Dutch Holland,CEO Holland & Davis

DEJ20:Layout 1 14/08/2009 10:25 Page 19

(This step is happening now: Detroit-

based EOS Solutions has constructed sever-

al very successful implementation simula-

tions for the oil patch).

Again, the purpose is to best position

companies for making optimal decisions

about the implementation process for new

DOF technology.

ADD: Economic Pro Forma or BusinessCaseIn the third criterion, companies need to have

an Economic Pro Forma or Business Case

that builds relevant implementation proba-

bilities into it.

Why? Frequently, business cases for

new technology are built on the faulty prem-

ise that when a new technology is “up and

running” on desktops and laptops through-

out an energy company, “utilization occurs

by magic.” Supposedly, there will be a rap-

id pick-up of the new technology by all em-

ployees whereby they can immediately do as

intended by the newly installed tool.

Unfortunately, as demonstrated repeat-

edly at companies, that is a heroic assump-

tion. The reality is that the utilization rate,

or pick-up on the new tool, has been all over

the map for most companies.

Pick-up probability is dramatically dif-

ferent for the two most common cases.

Case one occurs when the company

makes the formal decision to deploy the

technology organization-wide with a date-

certain implementation that holds managers

accountable. In this case, the result is typi-

cally the curve represented in Figure 1. It

means that with explicit top management de-

ployment decisions, a high utilization rate

(up to 90%) usually occurs at the “Go Live”

of the new technology, quickly surging to

100% or full utilization as the final stragglers

overcome their individual obstacles and get

on board.

The second case occurs when the com-

pany does no more than give permission for

new technology Adoption at users’ own dis-

cretion and timetable.

That approach results in a very differ-

ent curve, as in Figure 2 showing the typical

“Diffusion of Innovation” curve that has

been validated for more than a half-century.

For voluntary adoption, usage begins at an

alarmingly low rate of about 20% of users

volunteering to use the new technology as

soon as it is available. Gradually other users

come online, with the painstakingly slow (2-

3 years) pick-up by most of the remaining

80%. With the latter there is even a caveat

that in too many instances the likelihood is

substantial that a remaining 10-20% will

never voluntarily pick up the new technolo-

gy.

So, the underlying

point in this discussion is

that when companies are

contemplating employing

new technology in the

field, they need to build

those two distributions in-

to the economics of their

case for change. In other

words:

- What will be the

business value of the new

technology if management

formally makes the deci-

sion to implement new

technology by date-cer-

tain?

- What will the

business value be if man-

agement opts to allow vol-

untary adoption of new

technology throughout the

organization?

CommunicationWith the three key criteria

covered – Technical, Im-

plementation & Economic

– the next step should nev-

er be underestimated.

That is, once management

makes the decision to de-

ploy by date certain or to

encourage voluntary adop-

tion, this decision must be

clearly and explicitly com-

municated to all potential

users and technology

providers.

Thereby, the compa-

ny is stating emphatically

that through proven meth-

ods they have determined

the new technology is good and beneficial

for the company and, therefore, will be de-

ployed as the new standard for doing busi-

ness worldwide by date-certain … or that the

technology has real merit and should be con-

sidered for adoption by all users

ConclusionMany energy companies are unnecessarily

re-inventing the Implementation wheel by

not connecting the dots in integrating new

technology.

For all that may be said, the integration

of new DOF technology is not a mysterious

UFO but a known process in the world of big

technology (as executed for decades by or-

ganizations such as Houston-based Holland

& Davis LLC, following a specific formu-

la).

Anecdotes abound throughout the oil

industry about new DOF technology launch-

es that fizzled or outright flopped. While

these make colorful cocktail banter, think

about the time and money this costs compa-

nies globally. When that hard fact hits home,

forward-looking company management typ-

ically splashes cold water on its collective

face and decides to take an Implementation

page from the experts for dramatically better

results.

Dutch Holland is CEO of Houston-based

Holland & Davis LLC management con-

sultants to the oil and gas industry for

more than three decades.

www.hdinc.com


Production

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Production

22

Using massively parallel processingdatabases

The E&P industry has made steady progress

in data capture, accumulation, visualization,

analysis, and automation. It also boasts so-

phisticated full-physics models.

We employ many thousands of MPP

(massively parallel processing) workstations

for complex seismic interpretation and inte-

grated asset modeling (IAM).

But paradoxically our industry has very

little experience using MPP databases.

Recent research has uncovered several

ways MPP databases could be used in E&P

to achieve right-time, multidimensional

business insight, collaboration, and decision-

making.

The hundreds of data silos that dot the

engineering, geoscience, and operations

landscape are just too difficult to access and

use, and more than half of the oil & gas pro-

fessional’s time is lost finding and assem-

bling data, instead of analyzing the data and

making operational decisions.

If better decisions can be made faster

because the inconsistency and latency in da-

ta management and analysis are reduced,

then business performance can be signifi-

cantly improved.

The wake-up call in E&P has come

with the data explosion from advanced field

instrumentation and the aggregation of data

from the internet.

The industry is also pushing the inte-

gration of data for shared earth modeling and

other applications, and expending efforts to

improve E&P workflow processes to ad-

vance the digital oilfield.

MPP databases have to support more

than just large data volumes. They must have

multidimensional scalability and perform-

ance to support the mixed workloads re-

quired for Operational business intelligence

(BI).

The goal of Operational BI in E&P is

to enable event-driven, tactical, and long-

term strategic decisions—across multiple

subject areas—along all process workflows

in drilling, production, and other E&P oper-

ations. Increasing data detail, volume, inte-

gration, and schema sophistication vs. in-

creasing query and workload complexity

industry use MPP databases to integrate and

analyze data from many operational and fi-

nancial areas, for deeper insight and faster

decision-making.

For example, Boeing and the US Air

Force use operational business intelligence

for aircraft engine design, fleet-wide aircraft

maintenance, reliability and parts tracking,

analysis, and 24x7 collaboration with serv-

ice providers

Caterpillar and Ford use them for sup-

ply chain and inventory analysis, early-

warning system, quality, & warranty analy-

sis

Wal-Mart, eBay, and amazon.com use

them to take actions based on data combined

across all enterprise subject areas, within

seconds of a transaction anywhere in the

world.

Disk-drive manufacturer Western Digi-

tal uses MPP database technology to mine

millions of detailed data points streaming in

real-time from many pieces of manufactur-

ing equipment and also data from their sup-

ply chain. The data are processed with a sys-

tematized and automated “analytics factory”

approach, with in-database Weibull or gam-

ma-distribution analytics, based on princi-

must all be fully supported without concern

for scalability and performance limits.

In-database analytics is an especially

exciting capability accompanying MPP data-

bases, especially for the highly technical

E&P industry. It allows complex mathemati-

cal functions and even whole simulation

models to be parallelized alongside relation-

al-database operations, to create a powerful

predictive engine. Built-in geospatial capa-

bility that also runs in the parallel engine of

an MPP database completes the predictive-

analytics kit for E&P.

An automated “analytics factory” can

be set up for any field-monitoring situation,

with continuous data loading, cleansing, in-

tegration, and analysis, in parallel with mod-

els calculating in real-time. Such Opera-

tional BI systems can constantly monitor for

operational problems, perform predictive an-

alytics, and preemptively issue remedial ac-

tions.

Experienced operations experts can

watch “Well TiVo,” monitor events, and

through their deep experience, make predic-

tions and meaningful decisions about how to

better operate a field.

However, what about when these ex-

perts retire?

What about the hidden insights that can

be gained by analyzing detailed, highly-at-

tributed data across dozens of subject areas,

so that E&P assets can be better managed

from many different standpoints, including

supply chain, equipment maintenance,

process optimization, taxation and profitabil-

ity, and other ways to improve the business?

How do we scale prediction capability

by adding Operational BI and automated da-

ta mining to the industry’s mature and im-

pressive simulation models?

The field of Operational BI, data ware-

housing, and predictive analytics depends on

cleansed and consistent detailed data across

as many subject areas as possible, not just a

sampling, which statistics experts have

proven can lead decisions astray.

Other industriesOver a thousand companies outside the E&P

The use of massively parallel processing (MPP) databases could assist with production surveillance andoptimization, drilling and completions optimization, supply-chain and materials-managementoptimization, and oilfield equipment reliability and maintainability. Mike Brulé, a consultant in E&Pinformation management, explains how.By Mike Brulé, president of Technomation

Massively Parallel Processing databases canhelp decision making, because theinconsistency and latency in datamanagement is reduced - Mike Brulé,president of Technomation

DEJ20:Layout 1 14/08/2009 10:25 Page 22

Production


ples of statistical process control. The sys-

tematized gathering and analyzing of high-

ly-attributed data in real-time provide more

insight compared to just analyzing a small

sample of rolled-up data, which can easily

miss a statistically important event.

Improving E&P operationsMany E&P operations improvement oppor-

tunities exist in real-time production surveil-

lance and optimization, drilling and comple-

tions optimization, supply-chain and materi-

als-management optimization, and oilfield

equipment reliability and maintainability.

MPP database technology and Opera-

tional BI provide three high-level capabili-

ties crucial to E&P: integrating data of dif-

ferent timescales, integrating data across dis-

ciplines and across multiple subject areas,

and augmenting the industry’s traditional

modeling methods with statistical and sto-

chastic methods, which can be calculated in-

database.

Drilling, reservoir, and production en-

gineering would all benefit from being able

to combine historical (accumulated over

years), tactical (weeks to months), and high-

frequency data from historians (seconds to

days) with data from other discipline-orient-

ed source systems, including the underlying

data stores of shared-earth-modeling and

other application suites. Integration of data

across many disciplines facilitates a new lev-

el of people collaboration, process intelli-

gence, and model correlation, which can lead

to additional insight.

Equipment Reliability and Materials

Management has been significantly im-

proved through the use of MPP databases in

other industries, so they are obvious areas

for MPP databases to be deployed in E&P.

With the unlimited scalability and perform-

ance of MPP databases, the same methods

that the high-tech industry uses can be ap-

plied to equipment operation and mainte-

nance in the E&P industry.

The improvement of oilfield equipment

reliability and maintainability with MPP

databases also offers large returns critical in

areas of production optimization, production

loss management, operational safety, and

OPEX reduction. To harness these benefits,

E&P operators will need to gather, store, and

analyze device and sensor data on a high-

volume/high-detail scale, in a timeframe that

will enable prediction of outcomes in real

time. Such Operational BI systems allow ac-

tions to be taken before deleterious operat-

ing changes or catastrophic failures occur,

and can also alert the company’s supply

chain to prescribe changes needed in equip-

ment and materials inventory, to minimize

downtime.

Real-Time Drilling and Completions

(D&C) Optimization involves analyzing typ-

ical daily-drilling-operations data combined

with high-frequency MWD/LWD (measure-

ment/logging while drilling) data to reduce

nonproductive time and invisible lost time

(NPT/ILT). NPT/ILT reduction and managed

pressure drilling (MPD) optimization also

require real-time analysis of high-frequency

data.

Traditional daily drilling reports show

data recorded at relatively low frequency

(typically every 30 minutes). Such data in-

clude feet drilled per unit time, bit rate of

penetration (ROP), mud consumption, bit

tally, casing tally, and many cost items to

reconcile FCE vs. AFE, for example.

For more subtle drilling problems that

are not obvious to the rig crew while drilling

a well, drilling surveillance often includes

MWD/LWD data recorded at high frequen-

cy, at millisecond intervals. Such high-den-

sity LWD events are typically recorded

every 1/10th of a foot. Wired pipe is likely

to increase the frequency of data acquisition.

Real-time surveillance of engineering

data related to porosity, saturation, perme-

ability, and other reservoir, petrophysical,

and engineering data, are necessary for im-

proved well placement, pay determination

for perforating, sand-control parameters

such as screen-slot size, and for estimates of

3P reserves and well deliverability.

As is the case for the above equipment

reliability and maintenance example, such

high-frequency monitoring data can be sta-

tistically analyzed in real-time, parallelized

in-database, along with many other highly

attributed data relevant to the drilling

process. The resulting predictive-analytics

system can automatically make changes dur-

ing the drilling process to avoid problems

such as stuck-pipe incidents, to place the

well in the best possible location, and to re-

duce D&C time and costs.

Real-Time Production Surveillance and

Optimization have been addressed by a num-

ber of different technologies including histo-

rian and mash-up portals for monitoring, and

IAM that couples well-established subsur-

face and surface simulation models, and in-

cludes gradient-based numerical methods for

optimization. MPP databases and Opera-

tional BI can augment these traditional full-

physics models for optimization with real-

time stochastic and statistical “proxy-mod-

el” analytics of the incoming streaming da-

ta.

The downhole instrumenting and pre-

cise choke control available with “smart

wells” allow new approaches for dynamic

optimization in difficult production situa-

tions. Areas that have the highest impact in

improving operations include optimization

of gas lift, ESP operation, rod pumping, wa-

terflooding, and others.

The use of Neural Nets (NN), Monte

Carlo, Ensemble Kalman Filter, and other

statistical and stochastic methods have al-

ready been established as an effective ad-

junct modeling approach to solve problems

in situations where data are sporadic and the

effects are not always well understood and

are consequently difficult to model. All of

these methods can be parallelized in-data-

base, while analyzing massive amounts of

data. Such empirical methods do not replace,

but augment the industry’s traditional deter-

ministic methods, allowing a problem to be

solved quickly without waiting until the un-

derlying phenomenological mechanisms are

completely understood.

An example is the unexpected improve-

ments in oil recoveries experienced in low-

salinity EOR flooding of mature offshore

fields. Currently the mechanism is unknown

and no full-physics models are available. In

the meantime, the E&P industry can analyze

such a seemingly intractable problem like

Wal-Mart does, by performing data mining

and predictive analytics on the available da-

ta for lo-sal flooding.

Integrated Reservoir Studies point to

the need for cross-discipline collaboration

and multiproperty correlation and predictive

analytics across subject areas. A classic ex-

ample is the correlation of reservoir and seis-

mic data, normally kept separate, to deter-

mine the oil-water contact (OWC) and where

to drill additional wells to increase produc-

tion. The solution cannot be found by a

reservoir engineer or geoscientist working in

isolation with their silo’d data, but when they

combine their PVT fluid density and

acoustic velocity data, the OWC is revealed

and the drilling risk is reduced.

SOA, federation, and historiansSOA (Service Orientated Architecture) is

sometimes assumed to be synonymous with

federation, but MPP databases can also be

deployed with web services.

SOA and its evolving variants of SaaS

(Software as a Service) and Cloud Comput-

ing can benefit from the increased scalabili-

ty and performance that MPP databases pro-

vide, even in mixed topologies with federat-

ed and hub-and-spoke architectures.

Global companies operating 24x7 in

other industries have found that federating

data marts for reporting and analytics across

multiple subject areas inevitably becomes

unmanageable as the Operational BI system

grows to cover more of the enterprise. When

many hundreds of database silos propagate,

the enterprise is riddled with redundant, in-

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Production

24 digital energy journal - September 2009

consistent copies of poor-quality data, with

thousands of data-transfer lines bogged

down by accumulating latency, which ulti-

mately runs into a scalability brick wall.

OLAP (on-line analytical processing)

is a useful technology that enables the cre-

ation of multidimensional data cubes that

can be easily queried. OLAP can solve the

problem of ad hoc query performance, but

the overhead of having to build and refresh

the cubes is burdensome, and OLAP also has

scalability limits.

Will MPP databases obsolesce federa-

tion and OLAP? Federation and MPP data-

base technology are not in competition. Rea-

sons will always exist to federate, but feder-

ation should not be justified solely because

the underlying database is limited in scala-

bility and performance. Microsoft and Ora-

cle have for years prescribed federated

“spaghetti” architectures to its customers for

creating large-scale BI/data warehousing

systems and for integrating application

suites, because these mainstream vendors

sold databases that were more effective for

simple transactional rather than complex an-

alytical workloads. Vendors have offered

OLAP as a workaround, but as MPP databas-

es improve in price vs. performance, OLAP

is less likely to be needed.

MPP enterprise data warehousing ven-

dors IBM and Teradata have been used by

well known global companies to support an-

alytics workloads since the late eighties, fol-

lowed in the early 2000s by MPP database

appliance vendors such as Netezza and

Greenplum. The mainstream database mar-

ket is finally acknowledging that conven-

tional, transaction-oriented databases cannot

keep up with the exponential increase in da-

ta, and that shortcomings exist in the Opera-

tional BI capabilities of federated architec-

tures.

Now Microsoft is entering the market

with an MPP edition of its SQL Server prod-

uct, based on its DatAllegro acquisition. Or-

acle and HP also began leaping tall petabytes

with their new “Exadata” product. The entry

of these dominant vendors will help make

MPP databases mainstream.

Master data management (MDM) can

help federated architectures with redundan-

cy, but not with latency. With MPP databas-

es, companies can “move the data once, and

use it many times.” MDM and large-scale

logical data models are supportable. Data-

mart consolidation will reduce data redun-

dancy, excess storage, and hardware and

software costs. A sustainable data-gover-

nance plan company-wide will finally be

feasible. This strategy is not just about re-

ducing IT complexity and cost; such integra-

tion, speed, and efficiency positively impact

decision-making, operational

safety, and business profitabili-

ty.

Federation has succeeded

in achieving localized, fit-for-

purpose integration, basic re-

porting, and operations visuali-

zation, but few examples exist

for full analytics capabilities

across many subject areas, in-

cluding the operational and fi-

nancial analytics of the overall

enterprise. The current fad of

“integration by portals” and

“SOA mash-ups,” does not ful-

ly support Operational BI. Por-

tal integration is only at a visu-

al level, not at a data level. In-

teractive visualization with his-

torians is useful from a monitoring stand-

point, but is still not predictive.

Stages of developmentThe maturity of a company’s Operational BI

roadmap typically has five stages:

Stage 1 - reporting what has happened:

reporting systems, commonplace in E&P

Stage 2 - analyzing why did it happen:

ad hoc queries, KPIs, gaining in E&P

Stage 3 - predicting why will it happen:

analytical modeling, full-physics models and

IAM in E&P, but still not statistical and sto-

chastic analytics on massive amounts of

multi-subject data, which has clearly been

shown to be an advantage in other industries

Stage 4 - operationalizing what is hap-

pening: continuous update, time-sensitive

queries and in-database analytics on “bil-

lions of rows of data”

Stage 5 - real-time decisioning to make

it happen: actionable data driving real-time

optimization. Early success with event-driv-

en closed-loop IAM in E&P. Stages 4 and 5

is the goal of many IOCs for digital-oilfield

automation years from now, but Intel, Boe-

ing, eBay and other marquee companies are

already at this stage of BI maturity.

Today the oil & gas industry is some-

where between Stages 1 and 2, but leapfrogs

to impressive predictive capabilities (Stage

5) in certain operational areas, e.g., gas-lift

optimization, through the use of full-physics

models coupled in a closed-loop IAM opti-

mizer.

E&P operators rely on portals with

mash-ups to provide visual integration in a

role-based, meaningful context. These por-

tals are becoming rich in animation and in-

teraction, and give operators the visibility to

run improved operations, but not necessarily

the transparency to improve the overall busi-

ness.

Transparency comes in Stages 4 and 5,

and provides predictive insights derived

from analyzing highly detailed data from

many subject areas, from different

timescales—more data than any single ex-

pert, or even a group of experts, can under-

stand at any given time. The BI field of data

mining, predictive analytics, and the “new

AI,” i.e., artificial intelligence with stochas-

tic and statistical methods, goes far beyond

the typical visualization and reporting that

are commonplace in oil & gas.

In futureMPP database technology enables real-time

processing of mountains of operational and

financial data, with in-database statistical,

stochastic, and traditional full-physics mod-

el parallel processing, to achieve Operational

BI.

Today the E&P industry has very ad-

vanced monitoring and alerting capabilities,

and achieves advanced full-asset process in-

telligence through modeling, simulation, and

IAM.

The opportunity exists to combine the

best of E&P monitoring and IAM with MPP

in-database data mining and predictive ana-

lytics. Such real-time continuous Opera-

tional BI systems are able to integrate, mod-

el, and analyze data from across many sub-

ject areas, process steps, and timescales, re-

sulting in advanced decision-making capa-

bility that markedly improves the E&P busi-

ness.

Mike Brulé, PhD, P.E., is president of

Technomation, a consultancy providing

research and advisory services on E&P in-

formation management, Operational BI

systems, and E&P software development.

Mike can be contacted at:

[email protected]

Many other industries use Massively Parallel Processingdatabases to integrate and analyse data from across thecompany - is it time the oil and gas industry joined in?

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