#22 Digital Energy Journal - Janruary 2010

8/9/2019 #22 Digital Energy Journal - Janruary 2010

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January 2010 Issue 22

Prospects in Brazil,

Angola, Uganda

and Siberia

Getting the mostout of reservoir

software

Remote monitoring gas wells

Using IT to manage inventory

Connecting mobiles into your network

Associate Member


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January 2010 Issue 22

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

Printed by Printo, spol. s r.o., 708 00 Ostrava-Poruba,

Czech Republic. www.printo.cz

Digital Energy Journal213 Marsh Wall, London, E14 9FJ, UK

Digital Energy Journal is part of Finding Petroleum

www.findingpetroleum.com

www.digitalenergyjournal.com

Tel +44 (0)207 510 4935

Fax +44 (0)207 510 2344

EditorKarl Jeffery

[email protected]

Consultant editorDavid Bamford

Technical editorKeith [email protected]

Finding Petroleum London ForumsNew places new technologies for Finding

Petroleum conference - London Jan 20-21

Use of collaborative technologies in oil and gas

London - London February 16

Advances in geophysics - London March 16

For further information see

www.findingpetroleum.com

Social networknetwork.findingpetroleum.com

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

Cover photo -

Staff onboard a

Petroleum Geo-

Services vessel

monitor the

acquisition of

seismic data

from the

instrument

room. See page

12

David BamfordConsultant Editor, Digital Energy Journal

What is the pull fornew technology?

Digital Energy Journal tells stories about tech-

nology successes, technology innovations. It is of-

ten reactive, able to pick and choose from the

many stories that are out there.

Another, proactive, approach is to look at oil

& gas trends, especially in exploration and pro-

duction, to identify the key pulls on technology;

it seems important to think about the issue this

way round as opposed to identifying wouldnt

it be neat if. technologies and pushing

them into the oil & gas world.

So what might be the key themes for the

next 12 months, and beyond?

Well, as these are personal views, I should

first of all declare my views on energy policy, cli-mate change. Where I am on this is that: There's

just no point in denying that burning fossil fuels is

having an impact on the planet. I was very much

in the 'old' BP position of "as scientists we should

accept the evidence and think about how to re-

spond". Pretty well as Shell articulate today.

As we see in most of life, we will wait a long

time for politicians to do anything sensible. I don't

believe wind and solar will provide more than a

fraction of the energy we need (tides may be a spe-

cial thing for the UK) and I still find nuclear a bit

scary [partly because of the above. Imagine if ourUK Government treated the nuclear industry like

they treat the armed forces!].

So I see little alternative to fossil fuels for

the foreseeable future. That said, I'm going to trust

our inventiveness and technology. For example,

you will perhaps have seen that the US has dis-

covered enough gas (which is by far the cleanest

of the fossil fuels) that somebody as experienced

as T Boone Pickens thinks they could aim at get-

ting by without 'foreign oil'.

I like Carbon Capture and Sequestration if it

means we can use all that coal without choking

everything and everyone.

So the first question I ask myself is, where

are the majors (and larger independents) going to

find new oil & gas resources in the next decade?

It seems to me that they have two distinct options:

One, building relationships of mutual ad-

vantage with resource-rich governments and

their national oil companies who need help in

bringing their current assets to production and in

discovering new ones, for example in Iraq and

Russia. IOCs bring finance, Know How and

technology.

Two, re-engagement with Frontier Explo-ration in, for example, the Arctic, onshore (notably

in central Africa and East Siberia), and in deep-

water, the last handful of unexplored areas.

After a decade of easy exploration, in

which relatively young (mainly tertiary) sediments

were explored offshore using regional 3D seismic

as the principal exploration tool, we are returning

to a style of exploration which is hard, requiring

clever geological work and integrated geoscience,

in deeper targets, in more remote environments.

Nonetheless, the performance levers that

sub-surface folk have available to them are in-

creasing their success rate at the same time as re-

ducing the cost of what they do: this is true

whether drilling exploration wells in a frontier

province, development wells in a field that is be-

ing brought onto production or new wells in a cur-

rently producing field.

Ultimately, this is about spending less on

drilling, completion and well work, these costs be-

ing the single biggest component (typically 50%

or more) of any campaign to Find Petroleum.So there should be enormous pull on tech-

nologies that allow us to find the required resource

with significantly less wells and/or spend signifi-

cantly less on any one well.

Gas will be an increasingly important glob-

al theme, particularly unconventional gas, perhaps

especially in Europe, emulating the massive suc-

cesses onshore in the USA.

For some countries, gas storage will be an

important sub-theme; the UK is very exposed to

gas market swings, having only about two weeks

storage capacity whereas Germany for examplehas more like 100 days.

Staying with a storage theme, the oil and gas

industry will also increasingly involve itself in the

storage of CO2, the S part of CCS, both with the

deployment of enhanced oil recovery schemes that

utilise CO2 and its eventual permanent storage in

fully depleted, rightly abandoned fields.

This will fit neatly into a focus on increasing

the recovery factor of each and every oil or gas

field, including developing fields that are currently

stranded, extending the life of mature fields and

resurrecting prematurely abandoned ones.

The common pull of these last three para-

graphs is on technologies that improve the quality

and reliability of our insights as to what is going

on in the sub-surface digital technologies for col-

laboration, visualisation, building static and dy-

namic reservoir descriptions, geophysics espe-

cially 3D and 4D seismic, understanding rock

physics away from well penetrations.

My guess is that the technology break-

throughs, the real innovations, that I am looking

for will come from the smaller, more entrepre-

neurial, players rather than the big battalions who

are perhaps more interested in incremental im-provements to established products lets see if

Im right!

David Bamford is non-executive director of

Tullow Oil, and a past head of exploration,

West Africa and geophysics with BP


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Contents

PPDM, Energistics and RFID consortiumThe Oracle oil and gas OpenWorld event brought together representatives of oil and gas standards bodies PPDM, Energistics and the

RFID consortium, to see how the different standards fit together

Weatherford minimizing inventory costsOil services giant Weatherford recently embarked on a project to try to reduce the amount of capital it has tied up in inventory

(storage)

Optimising gas wells with remote monitoringCalgary oil and gas data management company Zedi helped a oil and gas operator

in Southeast Alberta (Canada) to get a much better understanding of how to

optimise production on its 2,500 shallow gas wells using a fleet of portable flow

measurement systems

GE Oil and Gas - new UK support centresGE Oil and Gas has opened new facilities in the UK for refurbishing control systems

and remote monitoring and diagnostics of subsea equipment

How virtual collaborative environments can save $120mCap Gemini recently put together two proof of concept projects with virtual

collaborative environments for oil companies and one of them estimated that itcould lead to savings of $120m

Software for pipeline networksCalifornina company CygNet believes that long distance gas pipeline operators could update their operations software much faster, if

it was available off the shelf rather than custom built and they have created a product to do it

People and the digital oilfieldUnlike many re-engineering, or slash and burn industry initiatives, the digital oilfield promises to empower people and improve their

working lives. But it only works if people take people management seriously not discounting it as soft stuff which will take care of

itself, writes Dutch Holland

Connecting mobiles to the networkVirginia (US) company Reality Mobile has won $6.5m venture capital investment from Energy Ventures, Chevron Technology Partners

and the Dobson Partnership to enable remote workers to gain access to video, data and remote expertise via their mobile phones

18

Production

17

4Exploring off Brazil and AngolaSince South East Brazil used to be attached to what is now Angola, you might expect the geologies in both to be similar. Neil McMahon,

senior analyst with Bernstein Research gave his views at the recent Finding Petroleum forum (Oct 20, 2009) about the potential

Tullow - success in UgandaTullow Oil and its partners have found oil in the Albert Rift of Western Uganda - but still faces the challenge of what to do with it - theoil is too thick to pump without heating, and the well is 1200km from the coast

Reservoir software false sense of confidence?Reservoir simulation software can easily give people a false sense of confidence while it takes them up a blind alley, says Luiz Amado,

senior reservoir engineer with Petrobras America. It is very important to have reservoir engineering training

Integra Western exploration technology in difficult placesMoscow based oilfield services company Integra has an interesting business model - applying Western exploration technology in

difficult parts of the world, including Siberia and Kazakhstan

Improved marine seismic streamer technologyPGS has developed a new streamer technology using particle velocity sensors as well as conventional pressure sensors, which promises

to greatly improve seismic image resolution, Tom Ziegler told the Finding Petroleum conference

Exploration

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3January 2010 - digital energy journal

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Exploring off Brazil and AngolaSince South East Brazil used to be attached to what is now Angola, you might expect the geologies inboth to be similar. Neil McMahon, senior analyst with Bernstein Research gave his views at the recentFinding Petroleum forum (Oct 20, 2009) about the potential.

There have been many exciting recent dis-

coveries in the Santos Basin, offshore Brazil,

including Tupi and Guara (June 2008).

Considering that the land which is now

Southern Angola and Namibia used to be at-

tached to South East Brazil, you might ex-

pect the geologies, and oil potential, in both

regions to be similar.

Neil McMahon, a senior analyst with

Bernstein Research, a company which serves

Wall Street and the City of London investors

and banks, believes both regions have poten-

tial, but also big differences.One of the reasons for the large discov-

eries on the Brazilian side is the very thick

continuous layer of salt, which has served to

keep a lot of the oil in place. This means that

the potential on the Brazilian side could be

higher. This is not the case on the Angolan

side.

However there is plenty more discov-

ery to be done. All of these areas are rela-

tively unexplored. So little is known about

presalt in the South Atlantic, he said.

Companies are not very keen aboutsharing what the knowledge they have.

People are very nervous about releas-

ing any data whatsoever on the presalt.

Bernstein Research aims to mix togeth-

er a certain level of geological skill with fi-

nancial skill, to try to assess whether com-

panies are likely to meet exploration success

and make a judgment on their progress, to

provide advice to investors, based on pub-

licly available data.

BrazilIn Brazil, there have been some enormously

productive test wells, such as Guara, which

which tested 50,000 barrels of oil per day.

However Bernstein expects most future

wells in Brazil to be more like 15,000 to

25,000 bopd, which is still enough to make

money as the oil price rises.

Bernstein calculates that an oil price of

$70 a barrel will give a return of over $5 a

barrel in the Tupi field, one of the largest

fields in the Santos Basin. Smaller oil fields

will need a higher oil price to be viable.

There could be a lot of gas production,which will be very useful for Brazil, which

is increasing its gas demand, he said.

There will be a new licensing round in

Brazil in 2010, which will lead to further

blocks being allocated to Petrobras and oth-

er companies. It will also help to steady a

price for ownership of oil reserves. The priceis currently around $4 a barrel for reserves

and may increase to $6.

Developing the Brazilian oilfields

could take a lot of time, particularly because

of all the associated infrastructure which is

needed.

The next question is how Petrobras will

raise the money to develop it.

Over the next 5 years, we think Petro-

bras spending plans will call for $194bn to

be spent in Brazil and a bit overseas. Were

talking enormous amounts of money, he

said.We believe that Petrobras could ask

the market for $50bn to buy some of these

reserves.

There have been concerns about the

carbon dioxide content of some of the

Brazilian fields. Companies are not stating

explicitly how much the carbon dioxide con-

tent is, but they are mentioning it as one of

the biggest technical challenges.

This might mean there are concerns

about both whether the carbon dioxide has

changed the reservoir properties, and also ifit might be possible to re-inject it into the

reservoir.

If there is a lot of carbon dioxide it will

need to be either re-injected into the reser-

voir or processed on shore.

Geology

On the Brazilian side, the geology is charac-terized by a very large, thick salt layer, which

has stopped a lot of the oil from running away.

The theory is that there was, for a peri-

od, a large lake from the Santos to the Cam-

pos basins on the Brazilian coast, as it split

apart from what is now West Africa which

means that much of the geology along the

coast is homogenous.

Theres a pretty homogenous set of

well results which indicates that the carbon-

ate reservoir is pretty much the same type

over most of the area, he said.

The reservoir rock is mainly stromato-

lites for hundreds of kilometers.

In pretty much all of the wells drilled

so far in the Brazilian pre-salt you see this

unique reservoir rock. There arent many ana-

logues of this around the world, he said.

There are a number of faults in the rock,

which affects the current location of oil (be-

cause they may have allowed oil to leak away

over time). Many of the rocks have a second-

ary porosity figure (a second porosity system)

due to the fracturing.

Petrobras and seismicDoing seismic surveys under a thick salt lay-

er is very challenging. However it seems that

Petrobras has a reasonable handle on this, he

said.

digital energy journal - January 2010

Exploration

Venezuela

Uruguay

Trinidad & Tobago

Togo

Suriname

South Afric

Sierra

Leone

Senegal

Puerto

Rico

Peru

Paraguay

Panama Nigeria

Niger

Nicaragua

Namibia

Mauritania

Mali

Libya

Liberia

Jamaica

uras

Haiti

Guyana

Guinea-BissauGuinea

Ghana

Gambia

Gabon

French

GuianaEquatorial Guinea

Ecuador

Dom.

Rep.

Cuba

Coted'Ivoire

ica

Congo

Dem. Republ

of Congo

Colombia

Chile

Chad

Central Africa Republic

Cape Verde

Cameroon

BurkinaFaso

B r a z i l

Botswa

Bolivia

Benin

e

Bahamas

Argentina

Angola

Western Sahara(Occupied by Morocco)

Tupi area

South East Brazil and Angola used to be attached to each other. Considering the recent large oilfinds off Brazil, could there be something similar in Angola? Not so fast, says Neil McMahon ofBernstein Research


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Exploration


they think they can apply their understanding

of oilfields offshore Brazil to offshore Ango-

la. It makes you think they are taking their

knowledge base and trying to make the most

of their proprietary knowledge, he said.Bernstein Research does not believe the

potential on the African side is likely to be as

big as the Brazilian side. Weve sort of nar-

rowed it down and said, there is potential on

the African side but its mainly Southern

Angola and a little bit down towards Namibia

but not of the same magnitude as you see in

the Santos and Campos basin, he said.

Mr McMahon believes that there is a

good argument that Petrobras has a much bet-

ter understanding of the seismic than other

companies, because they control a lot of the

production, and can use their data from the

wells to understand the seismic better. It is

so essential to tie the wells to the seismic da-

ta, he said.

Theyre in absolutely every presalt well

that gives them the potential of developing

a really good velocity model all the way along

the margin which is very critical when you

look at some of these structural lineaments,

he says. It helps you understand where the

secondary porosity could be.

I get the sense that because theyve got

the data they know more than anybody else.

I believe a lot of companies are still

playing catch-up with trying to understand all

the seismic bits of pieces in Brazil.

The seismic data is getting good enoughto do attribute analysis (generating a range of

different data about the rock properties, not

just the rock structure), he said. Companies

are also defining three separate layers of car-

bonate rock under the salt.

Companies feel, really only now,

theyve got a good velocity model and a good

handle on that.

TechnologyOne warning is that technology developed to

explore the subsalt of the Gulf of Mexico

might not be so useful offshore Brazil because

the salt structures are different.

In Santos basin youve got miles of

salt. In the Gulf of Mexico the salt is patchy

and has really mashed the rocks around sig-

nificantly.

A lot of companies feel they have real-

ly great seismic technology but frankly Im

not sure if the technology is suitable for pre-

salt in the South Atlantic, he said. I dont

know if thats completely transferrable.

You could be in for quite a shock.

Youre dealing with (a) carbonates and (b) a

huge salt section.

AfricaLooking across the South Atlantic to Angola,

the geology is a bit different there is no thickblanket of salt, which served to hold in the oil

on the Brazilian side.

So far, people have tried to look for oil

by drilling around the salt, but there have not

been many attempts to drill through the salt

and see what is underneath it.

Petrobras has been buying a lot of

acreage offshore Angola, possibly because

Tullow - success in Uganda Tullow Oil and its partners have found oil in the Albert Rift of Western Uganda - but still faces thechallenge of what to do with it - the oil is too thick to pump without heating, and the well is 1200km fromthe coast.

By the end of 2004, three companies, Her-

itage Oil, Hardman Resources and Energy

Africa had spent nearly 5 years exploring for

oil in Blocks 2 and 3 in the Albert Rift in

Uganda without success, and were ready to

think of pulling out of the country, said Paul

Burden, geoscientist with Tullow Oil, speak-

ing at the October 20th Finding Petroleum

forum in London.

However, Hardman and Energy Africa,

partners in Block 2, had further well com-

mitments two wells, Mputa-1 and Waraga-

1 were drilled in the Kaiso-Tonya area in

Block 2 and both were promising oil discov-

eries. Shortly after this Tullow Oil acquired

first Energy Africa and then Hardman Re-

sources.

During the last 2 years (2007 to 2009),

Tullow (50%) and Heritage Oil (50%) inBlocks 3a and Block 1 and Tullow (100%)

in Block 2 have drilled a further 22 wells in

the rift valley, only one of these was a dry

well. Tullow is currently spends over $200m

a year on drilling in this area.

The discoveries are claimed to be po-

tentially Africas largest onshore discoveries

since the discovery of the Rabi-Kounga in

Gabon in 1985.

However, Uganda is not yet an oil pro-

ducing country as ways forward for oil pro-

duction, utilization, export and/or refiningare still being explored by the active compa-

nies namely Heritage and Tullow, and the

Ugandan authorities.

The oil has a pore point of 36 to 39 C

(97-102 Fahrenheit) which means that it

needs to be heated before it will flow. There-

fore, export to a coastal port would require a

very expensive heated 1200km pipeline

through mountainous regions and two differ-

ent countries (Uganda and Kenya), includ-

ing a 200 meter vertical rise to get the out of

the Albert Rift valley.An alternative to heating is to inject

chemicals into the oil to reduce the pore

point, but it appears to be the more expen-

sive option, Mr Burden said.

The Ugandan government is very keen

to keep the crude oil within the country, ei-

ther burning it to make electricity (taking it

to a power station by trucking), or refining it

within the country to make gasoline for ve-

hicles. The in-country refining option is be-

ing considered but this is a long term project

there is no firm plan for a refinery in Ugan-da at this time.

BackgroundEnergy Africa (now Tullow) had originally

decided to look at Uganda after a chat be-

tween Mr Burden and a former colleague

who was then working for Heritage Oil. Mr

Burden said at the time my thoughts were,

we go on Safari in East Africa but we dont

look for oil there. However, when we attend-

ed the Heritage data room, we found that all

the fundamentals of an oil basin were thereand we decided to give it a shot.

The rift area had 52 known oil seeps,

with tales of oil seeping out of the ground in

the folklore of the local people, going back

more than a hundred years.

I believe a lot of companies are still playingcatch-up with trying to understand all theseismic bits of pieces in Brazil. - NeilMcMahon, senior analyst with BernsteinResearch, addressing a packed FindingPetroleum London forum


9/28

Exploration

liable roads into the rift valley, he said.

Drilling on Lake Albert is technically

feasible because the water is shallow enough

(most of the lake is less than 40m deep).

However, drilling on some other western

arm rift lakes, for example, Lake Tanganyi-

ka is far more challenging and a different

story altogether, he said due to water depths

of up to 1200m.

Extended reach drilling (reaching oil-

fields under the lake with horizontal wellsfrom shore) would be challenging because

of the soft, unconsolidated rock formations,

wells tend to collapse if they are anything

other than vertical, he said.

We have had numerous well collaps-

es, he said. Anything above 20 degrees,

has a very good chance of collapsing. The

only way to drill wells reliably in these for-

mations is to drill vertically and even some

of the vertical wells have had enormous

wash-outs.

We have to run our casing strings into

the wells as rapidly as possible before possi-ble collapse, we have even thought about the

option of drilling with casing.

At certain points in the Vic-

toria Nile River, which runs into

the North of Lake Albert, you can

see little droplets of oil that

burst on the surface of the river

where the river crosscuts a major

fault, he said. This is known as

the Paraa Oil Seep. There are al-

so many rock outcrops where you

can see oil impregnated sand-

stones.

Oil seeps alone are not di-

rect evidence of good sized oil

accumulations in the subsurface.

Questions still remained, how

much had been generated and

was the basin totally leaky, he

said. This was later to be inves-

tigated by drilling.

The first serious study of oil

potential in this area was made in1925 by E J Wayland (Geologi-

cal survey of Uganda), who documented all

of the petroleum occurrences and all the pos-

sible reservoir occurrences that occurred at

outcrops around the rift.

RegionalThe Albert Rift is about 250km long by

70km wide. Much of it is covered by Lake

Albert, which is 50km wide by 150km long.

The basin forms part of the western arm

of the East African Rift system which runsfrom the Red Sea in the north to Mozam-

bique in the south.

The Western arm includes a number of

large lakes including Lakes Tanganyika and

Malawi whilst the Eastern arm has many

smaller lakes such as Lake Natron. Compa-

nies formerly active in exploration in the

area include Anglo Persian oil in the 1920s,

Petrofina in the early 1990s.

Exploration challengesExploring for oil and gas in the region was

challenging not least because most of the

basin is largely covered by a lake, and be-

cause the area is remote and surrounded by

a 200m high escarpment with limited road

access.

To acquire seismic over the lake, the

companies initially decided to work with

Syracuse University (New York State) which

had already acquired some seismic in other

rift lakes in East Africa. However, more so-

phisticated recording equipment was needed

for deeper imaging and this proved to be too

heavy for the Syracuse owned vessel. The

boat was launched and it virtually sunk ithad less than a foot of freeboard [distance

between the vessels deck and the water].

They had to turn around and come back to

the shore, he said.

A larger fishing trawler was eventually

found in nearby Lake Victoria and transport-

ed by road to the shores of Lake Albert, a

difficult journey with a mountain range and

200m rift escarpment to cross.

Drilling in the area was a great chal-

lenge. To get the heavy equipment for

drilling down into the valley, the companies

had to arrange for 3 road refurbishments.That took a lot of time and a lot of work

with the government. Now we have three re-

UgandaDRCAlluvialFan

RiftScarpSemiliki

Delta

Oilseeps

3DSeismic

Lowsinuositychannels

Blocks I & II, DRCsecured subject topresidental decree

KaisoTonyaDiscoveries

1

KingfisherDiscovery

2

ButiabaDiscoveries

3

Ngassa

4

Finding oil in Uganda - Lake Albert Rift Basin Viewed from the Southwest

Finding Petroleum London Forums 2010For latest developments, registration and to subscribe to our newslettersee www.findingpetroleum.comLimited free tickets available for each forum - exhibition andsponsorship opportunities

Marginal fields and field re-development- September

Carbon storage - October

Predicting future oil supply - November

Digital energy technology - December

Collaborative technologies - Feb 16

Advances in geophysics and subsurface

description - March 16

Gas and unconventional gas - April 27

Deepwater - May 26

Russia -June


10/28

Exploration


Reservoir software false sense ofconfidence?Reservoir simulation software can easily give people a false sense of confidence while it takes them up a

blind alley, says Luiz Amado, senior reservoir engineer with Petrobras America. It is very important to havereservoir engineering training.

If you are familiar with reservoir engineer-

ing software, you go to these places and see

huge software, with nice screens and you

think you can model anything, says Luiz

Amado, senior reservoir engineer with

Petrobras America. Once you have the da-

ta and you work with that software you see

how important you are.

But the software will suggest several

avenues that may have no connection withreality. It is very important to have reservoir

engineering training, he warns.

Sometimes the software will lead you

in one direction, and if you are not smart

enough to notice what is wrong, you let the

software guide you, he says. Although the

software has nice features, be careful.

There is a risk of letting the software

take too much control, trying to tell the users

what to do, or suggesting what kind of rocks

they are looking at. It will tell you what

you want to hear, he says.It should be the opposite. The software

is the tool to help you with your knowledge.

You guide the software not vice versa.

It is important that the team is in con-

trol and they try to use the software to mod-

el and achieve the results.

The human being is behind all of these

techniques, and even seismic requires a lot

of creative and human interpretation.

I believe good software is important,

but it is important that the human being that

is manipulating the software has a good

knowledge and good training towards thatparticular software, otherwise you will have

mistakes.

Sometimes what you think is good

software is so complicated for the user, and

it may misguide the user.

It is important to have software which

can be used by a number of different people,

not just one individual, he says. With three

or four people using the same software, they

can see things that one person cannot see.

Petrobras is using the standard industry

reservoir simulation software packages, hesays.

Mr Amado has experience with a num-

ber of different software packages. You find

out that they all give about the same results,

he says.

Volumes to valueMr. Amado has been working on improving

Petrobras methods of assessing how much

its reserves are worth or how much it could

earn from them in a process the company

calls volumes to value.

The process includes working out how

many wells would be needed to develop a

field, what kind of production facility would

be required, what production levels are an-ticipated, what the overall capital costs and

operating costs will be, and put that together

with the oil and gas price.

Petrobras uses different uncertainty

analysis tools, such as Montecarlo simula-

tors, to run many different models of what

might happen, and end up with an idea of the

P10 and P90 (level which is 10 per cent like-

ly to be exceeded / level which is 90 per cent

likely to be exceeded).

The next stage is to put together differ-

ent scenarios e.g. a low end, mid range andhigh end and run the economics for each

of them. You can see if your project will be

economic for all the case, or maybe just the

p10 case, he says.

Both the surface and subsurface have a

lot of unknown parameters at the start of the

project but the subsurface is particularly

hard to predict, with big unknowns includ-

ing the size of the reservoir, the quality of

the oil (whether it is light or heavy), produc-

tion rates, whether the reservoir will com-

pact over time and how fluid properties will

change over time.Until you have the first production

everything is an estimate based on geologi-

cal models: simulation models that you ex-

pect to produce at a given rate, but you are

really not sure, he says.

CompactionA major focus is improving the computer

models to predict compaction and find good

ways to reduce it.

Compaction is the compressing of a

reservoir by the rock above it, as the reser-voir is produced.

Reservoirs are under a lot of pressure

from the rock above them, some of which is

held by the fluids within them.

As these fluids are removed, the reser-

voir can get crushed by the rock above

leading to reductions in the permeability and

porosity of the rock. This makes it much

harder for any remaining fluid to find its way

through the reservoir into the wells.

This is something relatively new to

predict. You really dont know how big this

reduction will be with production, what or-

der of magnitude it will be. This will have a big effect on well rates and field produc-

tion, he says.

With good reservoir models, it might be

possible to implement a better reservoir

management strategy, to restrict field pro-

duction rates to get a reduced level of com-

paction, he says.

This may reduce the field economics,

however if the conditions are favorable one

may inject water to keep reservoir pressure

and stimulate the wells regularly to keep up

productivity.We have a good research program in

place with universities and research centres

to help model compaction, he says.

We use geomechanical models, geo-

logical models, characterization studies in

"Sometimes the software will lead you in onedirection, and if you are not smart enough tonotice what is wrong, you let the softwareguide you" - Luiz Amado, senior reservoirengineer with Petrobras America


11/289

Exploration

January 2010 - digital energy journal

order to describe the rock in microscopic

scale and macro scale. So we will improve

the models and consequently the forecasts.

Compaction can be measured directly

if you have sidewall drilling cores from the

reservoir, which can be analysed for com-

pressibility. If the compressibility of rocks

changes, it might indicate that the reservoir

is being compacted.

Alternatively you can test for perme-

ability in well tests. If you do well tests,

with time and during the time this well test

give you an expectation that your permeabil-

ity has deteriorated, or is smaller than it was

a year ago because permeability usually

does not decrease with time you have a

rock that is being compacted, he says.

Fluid propertiesAnother area of focus is getting a better un-

derstanding of how fluid properties canchange during the life of the reservoir.

Sometimes gas fields can gradually

switch to producing more and more conden-

sate. The gas composition will change with

time, he says.

Other wells gradually switch from oil

production to gas production, or oil with

more gas in solution. The fluid will have

completely different properties.

If you have solids precipitating out of a

liquid (e.g. paraffins) it can block flowlines

from a reservoir to the surface. It doesnthelp if you have a good reservoir but your

flow line is obstructed, he says.

Making predictions gets easier if you

have good fluid samples to analyse. It is

something that is really difficult to model if

you dont get enough fluids to model up-

front, he says.

SeismicThe initial building block of any reservoir

model is still seismic + geology. Seismic ba-

sically defines your framework together with

information coming from wells or regional

geology if there are no wells, he says. It

gives you an idea of the horizons that you

need to be modeled and the area and the

thickness of your formations. From the seis-

mic and information provided by the geolo-

gists you build your maps and thats it.

Good seismic is crucial to start off

with, he says. You need a good program

of how you are going to acquire data.

Sometimes it is necessary to reprocess

seismic several times to try to see what you

need. Its very complex, he says.Validating seismic is very important;

from exploratory wells, wells you have al-

ready drilled, or wells drilled by other peo-

ple who are willing to share their well log

data.

Sometimes through a partnership you

get information about wells in the area and

then you can tie your seismic to the well in-

formation, he says.

This is the true key information that

you need: the well and the seismic. You can

start this into your model.

Once you have an exploratory well, it

is important to have a good program of log-

ging and fluid sampling. This additional in-formation is the raw material for building

any kind of model, he says.

It is important that you have a good

monitoring in place once you are on-stream

- good pressure devices and rate devices -

that can give you reliable data once you are

in production, he says.

Reservoir models start basic and im-

prove over time. You always have a mini-

mum amount of information (to begin

with), he says. You have the maps, you

have the analogue fields (comparison) where

you believe will provide some kind of infor-mation to new fields.

Then you create a first pass model and

use this model for initial assessment. As you

go further down the road with exploration

and you get more information, you update

the models accordingly.

Its a good practice to start with some

models upfront although they may not be

so refined models.

When you run these models and they

can help you understand things like com-

paction.As you proceed further down the road,

you will narrow that, you will focus more on

a particular range. Then you can throw away

some of the early models.

Reservoir models: do they make people forget they are looking at a model, not the actual thing?

Dr Amado is a Senior Reservoir Engineer

at Petrobras America in Houston, Texas.

He has over 15 years of experience in

Reservoir Engineering in Exploration and

Development Projects in GOM, Southern

North Sea (UK) and West Africa.

Previously he worked for Shell EP

international and Schlumberger Geoquest

Reservoir Technologies, where he had as-signments in Mexico, UK, Brazil and

USA.

He has participated in several com-

mittees for the SPE, chairing technical

sessions, coordinating conference com-

mittees and working as a Technical Edi-

tor of the SPE Reservoir Engineering and

Evaluation Journal.

Amado holds a PhD from Universi-

ty of Leoben in Austria and MSc from

Unicamp in Brazil, both in

Petroleum/Reservoir Engineering.

Amado has worked as a consultantfor CSIRO in Australia for the Genesis

2000 project and was an associate profes-

sor at State University of North Flumi-

nense, in Macae, Campos Basin, Brazil.

He is also the author of the book

Working Guide to Reservoir Exploration

and Appraisal to be published by Elsevier

next year.

Disclaimer: information and materials

presented are provided to you for infor-mational purposes only. They are solemn-

ly the author's opinion and does not nec-

essarily reflect any position of Petrobras,

its officers, or employees.


12/280

Exploration


Integra Western explorationtechnology in difficult places

Moscow based Integra Group is building up

an interesting business providing Western

oil and gas exploration and production tech-

nology in difficult parts of the world, includ-

ing East and West Siberia and the Yamal

Peninsula (Russia) and Kazakhstan.

The company does not claim today to

be able to match standards with Western oil-

field service companies on issues such ashealth and safety, technology or performance

it aims to provide a good level of perform-

ance and go to parts of the world which are

more difficult to work in.

Chris Einchcomb, executive vice presi-

dent - geophysics of Integra Group, previ-

ously vice president for exploration and seis-

mic at the TNK / BP joint venture, says that

reaching any of Integras operations in West

Siberia can take 2-3 days travel from

Moscow. It is impossible to do much in

Siberia in the summer because most of itturns into a swamp. In the winter, the ground

is frozen.

Another difficulty of doing business in

Russia is the fact that many good contracts

go to government owned companies you

dont necessarily compete on the basis of

your companys performance.

You can find yourself competing

against companies quoting much lower

prices, but which have technology and safe-

ty performance which is nowhere near as

good, he said.

Altogether, the company provides a fullrange of integrated oilfield services, drilling,

manufacturing and seismic. It grew from ac-

quisitions of 17 companies and had a $1.5bn

turnover in 2008.

Integra has its own depth imaging soft-

ware, which is being used by StatoilHydro.

We are working with them to use it as an

R+D project to develop it as their in-house

technology for depth migration, he said.

Its biggest client in 2009 is in Kaza-

khstan, where it covered 900km2 with 3D

seismic in under 6 months, using 19,000channels, with up to 10 vibrators simultane-

ously. 276,000 shot points were acquired in

just over 5 months.

Thats just taking equipment that is

standard in the West, showing a client that if

you increase density rather than try to in-

crease energy in the ground you get the same

result, he said.

Kazakhstan has got 3 supergiant fields

in the infancy so Kazakhstan as a major oil

producer will expand for many years to

come, he says.

Integra is keen to build up business in

Kurdistan, Turkmenistan, Uzbekistan andIndia.

If you look at Turkmenistan and

Uzbekistan especially for gas - theres a lot

of growth and some supergiant fields yet to

be developed.

SafetyThere is no doubt HSE in Russia is poor,

he said.

One of the reasons Mr Einchcomb was

brought into Integra was to try to improve

its safety record. The previous winter seasonthe company had seen 12 fatalities.

Russia policies and procedures in HSE

are better than the West. They are very clear.

The only problem is that no-one ever follows

them, he said.

You find there is not only a lack of

commitment from the industry as a whole,

but also a lack of commitment from manage-

ment to make a change.

There is a big difference in the perform-

ance of the different companies.

You have state run companies with no

HSE, but who get preferential access to the

contracts, he said.Mr Einchcomb introduced a company

policy that meetings should be started with a

discussion of any accidents which have oc-

curred. This has had a dramatic effect, he

said.

Weve had zero fatalities this year

that might not sound like an awful lot but for

me thats a difference of 8 people still work-

ing that would have died last year.

Weve got a long way to go in reduc-

ing the accident frequency rate. But weve

seen that drop by 50 per cent.The big thing in Russia is, we have a

lot of staff turnover. Were very seasonal.

Each time you have to come in and educate

people again, he said.

Most of the people that work on the

Integra specialises in taking Western technology, like these Vibroseis trucks, to difficult parts ofthe world

Moscow based oilfield services company Integra has an interesting business model - applying Westernexploration technology in difficult parts of the world, including Siberia and Kazakhstan.

www.integra.ru/eng


13/28

SPE Intelligent Energy provides the Oil & Gas E&Pindustry with a platform to debate fully integratedoperations and the issues of people, process andchange management in a collaborative conferenceand exhibition environment.

Confirmed Plenary Speakers for 2010

Andy G Inglis, Chief Executive Officer, BP Exploration & Production

Jon Rigby (Moderator), Managing Director, UBS European Oil and Gas Research

Andrew Gould, Chairman and Chief Executive Officer, Schlumberger

Amin H. Nasser, Senior Vice President, Exploration & Producing, Saudi Aramco

Pieter Kapteijn (Moderator), Director Technology and Innovation Maersk Oil and Gas AS

Timothy Probert, President, D&E and Corporate Development, Halliburton

Ashok Belani, Chief Technology Officer, Schlumberger

Margareth vrum, Executive Vice President, Technology and New Energy, StatoilHydro

Samer AlAshgar, Manager EXPEC Advanced, Research Center Saudi Aramco

Melody Meyer, President, Chevron Energy Technology Company

John Brantley, General Manager for Chemicals and Petroleum, IBM

Denis Lemarchal, Director of Block17, Total

Bernard Looney, Managing Director, BP North Sea

Gerbert Schoonman, Asset Manager East (EM), Brunei Shell Petroleum Co Sdn Bhd

THE OPPORTUNITY

Contact us today to discuss how working with SPE Intelligent Energy 2010 can deliver high qualityleads to support your business development plans

E [email protected] T +44 (0)20 8439 8890 F +44 (0)20 8439 8897

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Conference & Exhibition 2325 MarchJaarbeurs Centre, Utrecht, The Netherlands

Registration now open, visitwww.intelligentenergyevent.com/register

Organised by:

HIGHLIGHTS

Record number of submissions 331 from 120 companies

139 technical papers

18 Technical sessions

3 Plenary sessions


14/282

Exploration


lines, laying out geophones and cutting lines,

are all people who just came in off the street.

Most of them are just interested in making

money and sending it back to their families

because thats the way they survive.

Getting them to understand what it

means to have zero accidents is still a big

challenge. But were getting there.

Russian exploration potentialMr Einchcomb is very excited by the poten-

tial for oil and gas exploration in Russia.

Theres no doubt if anyone wants to

be in the oil industry, Russia is a great op-

portunity, with vast areas virtually unex-

plored, he said. If you want to be in the oil

industry as an explorer I think being in the

region is critical.

Some Russian oilfields are still only 60

to 70 per cent covered with seismic.

Russia is now the worlds largest oiland gas producer. But this isnt due to any

recent exploration success - most of the new

oil production is fields which have been

known about for many years.

A number of East Siberian fields dis-

covered in 1960s are only being developed

now, as the Trans Siberian Pacific Pipeline

has been built. Another West Siberian field

had original drilling made in the 1970s, but

is only going into full field production now,

he said.

Seismic as a tool is still not being usedto its full effect in Russia, he says. People

are looking for structural highs but theres

no qualitative or quantitative analysis.

Here is a great opportunity to look in-

to the market and promote seismic in an area

which has an awful lot of growth.

The technology that were using in the

West is still not being used in Russia.

TNK-BPs efforts with seismic paid

off, he said. TNK-BP had success rates of

90 per cent when drilling for small subtle

reefs and closures, after it had done 3D seis-

mic surveys, he said.However getting a rough idea of the en-

tire region using regional seismic is not

something you can do, he said. To shoot

one line will probably take you a whole sea-

son.

The reservoirs in East Siberia are often

very complex with many different types of

rock. The reservoir is only 50ms thick and

its got enormous variability within it, he

said. With 100 wells you cant fully under-

stand the distribution of the reservoir.

Much of the oil and gas business focusin Russia is on drilling, rather than geo-

physics.

This is perhaps not surprising when you

consider that it is rare for an individual well

in Siberia to produce more than 1,000 bar-

rels a day, compared to say 50,000 barrels a

day for a big well in other parts of the world.

Technology in RussiaWhen implementing new technology in Rus-

sia you commonly find that people are open

to the idea of buying new technology but

not so good at working out how to do things.

When I joined Integra they decided

they wanted to do helicopter operations.

They bought 2 helicopters. But no-one told

them how to project plan with helicopters or

move equipment with helicopters.

The people can be stubborn and want

to do things the way they have always done

them. There are real barriers to try to break

down, he said.

The only way to do it is by talking to

people on an intellectual level and explain-

ing that other ideas might be better. You

have to give them space to open up to usingnew technology rather than seeing it as a

threat to their existence.

However education levels can be high.

There are many geophysicists with 40 years

experience. That counts for something, he

said. Its one of the best educated coun-

tries.

Western companies also find that tech-

nologies developed in the West dont always

work in Russia. For example, many new

seismic technologies are designed for getting

detailed information about a small area ofland, and not so suitable for getting an

overview about vast areas, which is what is

required in Siberia.

Wireless seismic technology is very

difficult to use because of the temperatures

involved. Wireless seismic at -40 degrees

C is yet to be proven in terms of battery life,

he said.

The Russian industry is starting to

catch up with the West in terms of channel

technology and density of data.

Weve seen a 40 per cent increase over

the last 4 years in terms of the number ofchannels clients require, he said. We have

deployed up to 19,000 channels on one par-

ticular project. Whereas most projects before

were only employing about 2,000 channels.

There has been a gradual shift from dy-

namite to Vibroseis, as a source for seismic

energy.

West Siberia was all dynamite tech-

nology. As weve moved up to Yamal, its all

Vibroseis. The same thing is happening in

Kazakhstan. Its more efficient, he said.

In terms of being able to cover the vastareas they are talking about, Vibroseis is by

far the most effective.

Short seasonsAn additional problem with seismic acquisi-

tion in Russia is that you can only do sur-

veys during winter in much of the country.

In winter, the Yamal Pensinsula is a

fantastic place to do seismic acquisition, he

said. You can drive the Vibroseis anywhere

you want as long as the lakes are frozen and

the snow cover is really good, he said.

There are flat barren areas with no trees.

But in the summer, it all gets swampy.

To add to the difficulty, In the Uvat re-

gion, 70 to 80 per cent of land is covered by

forest, with trees up to 80cm thick, which all

need to be cut by hand. There are dead trees

everywhere. It is very labour intensive, he

said.

You have to have crews equipped to

cover every kind of condition, he said. A

single crew will have to cover everything

from hard ground to swamp areas where they

can utilize something lighter to on lakes

which are frozen.Operations typically start in December,

but it takes some time to reach a good speed.

Then there is a holiday break. By March-

April theyre functioning at 100 per cent ca-

pacity, he said. They take 4 months to get

themselves organized.

It is possible to speed things up for

example, by doing tree cutting during the

summer but that has been delayed due to

economic difficulties.

We improved productivity by 20 per

cent this year just by getting them really fo-cused and getting topography (tree cutting)

crews integrated with drilling crews, he

said.

One of the failings of previous regimes

was that they thought the same sort of equip-

ment should work everywhere in Russia, in-

cluding the tundra, steppes and swamps.

No-one realized that the ground conditions

take a lot of different technology, he said.

Seismic siloisationA common problem with working with seis-

mic data is the siloisation between differ-

ent departments for acquiring, processing

and interpreting data.

Commonly, seismic acquisition compa-

nies acquire, process and interpret data, giv-

ing it to oil companies with a list of well lo-

cations. Oil companies drill in the marked

locations and then the two groups have a big

row when they dont find oil.

TNK-BP adopted a different strategy -

outsourcing seismic acquisition and process-

ing, but doing its own interpretation to en-

sure that the company really understood it.Integra is keen to be able to offer a

complete service to oil companies where it

starts by asking what are you trying to im-

age on the subsurface, and ends by giving

the client an earth model, he said.


15/2813

Exploration

January 2010 - digital energy journal

Improved marine seismic streamertechnologyPGS has developed a new streamer technology using particle velocity sensors as well as conventional

pressure sensors, which promises to greatly improve seismic image resolution, Tom Ziegler told theFinding Petroleum conference.

Oslo seismic survey company Petroleum

Geo-Services (PGS) has developed a way to

use velocity / motion sensors together with

the conventional pressure sensors (hy-

drophones) in streamers towed behind their

vessels, to generate data which can lead to a

massively improved seismic image, Tom

Ziegler, head of MulticCient, told the Find-

ing Petroleum conference on October 20th.

The company does not claim that theidea is new, but what is new is managing to

implement it - and overcome engineering

challenges. There have been many experi-

ments to date using velocity / motion sensors

towed behind vessels, but they didnt work

because too much noise was generated by

the towing in the water.

Now, after extensive testing and going

through several generations of the device,

PGS has developed a system which works,

as demonstrated on numerous 2D and 3D

surveys acquired and processed for morethan 25 global operators.

Particle velocity and pressure are two

complementary characteristics of the seismic

wavefield. The dual sensor technology over-

comes the bandwidth constraint of conven-

tional seismic data, due to its ability to elim-

inate the ghost reflection from the sea-sur-face.

The towing depth of a seismic streamer

controls the frequency spectrum. Since the

peaks and notches in the frequency spectrum

for the pressure field are exactly opposite to

the peaks and notches for the particle veloc-

ity field, the notches are removed after thecombination of the two measurements.

The resulting spectrum is flat and

broadband and enables the user to optimize

the data quality, not just for one target depth,

but for all depths - shallow to deep. This al-

so means that the streamer can be towed

deep 15 to 25m below sea surface where

there is much less wave noise than at the

conventional 6-10m tow depth.

This means that the acquired data are

significantly cleaner and that the vessel can

continue operations in weather where others

have to shut down.PGS has four 2D seismic survey ves-

sels and two 3D vessels fitted with the new

GeoStreamer technology; it will equip a fur-

ther 3 high capacity Ramform 3D vessels

during 2010 and will continue to invest in

this unique technology going forward.

The company has already collected

more than 90,000 line kilometers of 2D and

9,000 square kilometers of 3D GeoStreamer

data in all major petroleum exploration and

production basins of the world.

All results have shown distinct upliftin data quality, and operational efficiency

has also been improved significantly. In ad-

dition, the image uplift in subsalt areas has

proved particularly encouraging, the com-

pany says.

Analysing GeoStreamer seismic data

PGS seismic vessels - one was recently rigged with 10 GeoStreamers to perform a doubleGeoStreamer undershoot together with vessel Atlantic Explorer in offshore Congo


16/28

Production


PPDM, Energistics and RFID consortium The Oracle oil and gas OpenWorld event brought together representatives of oil and gas standardsbodies PPDM, Energistics and the RFID consortium, to see how the different standards fit together.

Software giant Oracle likes to differentiate

itself internationally on its commitment to

open standards so it is showing strong sup-

port to the oil and gas standards bodies En-

ergistics, PPDM and the RFID Consortium.

It brought together representatives of

the three bodies to Oracle OpenWorld Oil

and Gas day in San Francisco on October 12,

to talk about how the standards fit together.

The idea that oil and gas data standards

organisations PPDM and Energistics are in

competition is a myth, said Jerry Hubbard,

executive vice president of Energistics.

There's no competitive situation be-tween the standards bodies - I need to de-

bunk that perception.

PPDMThe Public Petroleum Data Management As-

sociation (PPDM) has developed a data

model which can be used for the entire oil

company exploration and production. Its a

big data model - its not simple, said Trudy

Curtis, CEO.

It should be possible to use the model

to store all companies data and link it to-gether, so the right information can be deliv-

ered to the right people at the right time.

So far, it hasnt been done. People

have solved bits of it, but no-one has solved

all of it, she said.

Although the industry has had a vision

to share information between all departments

for 20 years, she said.

We're really not yet solving the prob-

lem. We have many barriers between our da-

ta types, she said. How do we get these

data types integrated together?

We want to create an environmentwhere this can all be integrated together.

A common problem is that everybody

has their own way of doing things but they

do it differently to how other people do it.

But they dont want to do things the way that

other people do it.

Ms Curtis compares peoples attitude to

data standards with how they feel about their

toothbrush. Everybody has one and nobody

wants to use anybody else's, she said.

What is needed is for the industry to get

together and decide on standard ways ofdefining things, she said.

Companies are starting to see the bene-

fits though, she said. We're getting to where

companies are recognising the value of in-

dustry standards. The more standards we

use, the better off everybody is going to be.

One of the biggest standards when im-

plementing standards is getting the support

right. You need really skilled people, shesaid.

A second problem is the different defi-

nitions people use. When you look at inte-

gration you run headfirst into problems. Ter-

minology and semantics and how we use

terms. We don't agree what a well is, what a

facility is, what oil is. We have not wrestled

with this, she said.

Some of the challenges with encourag-

ing the use and development of open stan-

dards go right back to our education system,

Ms Curtis said.

Our education system teaches peopleto solve a problem in isolation. So we don't

position ourselves as an industry to adopt

standards very well.

EnergisticsJerry Hubbard, executive vice president and

treasurer for standards body Energistics, said

that it is important that oil companies push

their service companies to use standards.

If energy companies don't commit to

standards - then the oilfield service compa-

nies dont embed them into their products,he said.

For example, a number of oil compa-

nies are now requiring that their drilling

companies supply drilling data in its XML

standard WITSML. As a result it is now em-

bedded in 40 different products.

Energistics followed its success with

WITSML by developing a standard for pro-

duction data called PRODML, starting in

2005, and for exchanging earth model data

in a standard called RESQML.

It also has a project to set up a standard

system for identifying wells together with

IHS Energy, to be used everywhere apart

from North America.

It also facilitates a standard for Govern-

ment oil and gas data repositories, with a re-

cent meeting in Delhi attracting 200 people

from 27 different countries. It will be fol-lowed by a meeting in the first quarter of

2011, probably in Lima, Peru or Rio de

Janeiro, Mr Hubbard said.

Energistics strategy for getting its stan-

dards adopted is well to make sure it hap-

pens. We have a 3 year plan to deal with

challenges to adoption, he said.

A typical problem is that a standard

might lead to small improvements in the

lives of many, but one or two individuals feel

it could lead to a big problem and fight

against it.So you get an uneven fight between

two people actively and strongly opposing

it, and many people passively seeing a bene-

fit to it. It is hard to overcome strong resist-

ance by someone, he said.

The biggest barriers can be when you

have people who feel the standards hurt their

competitive edge.

Energistics tries to overcome this by

getting people involved in the standard. We

overcome it by working on bringing them

in, he said.

Onedelegate of

the audi-

ence

blamed en-

gineers. As

long as en-

gineers are

in charge

we have a

problem.

Engineers

like comingup with

their own

way of do-

ing every-

thing.

"We're really not yet solving the problem" -Trudy Curtis, CEO, Public Petroleum DataManagement Association (PPDM)

"We have a 3 year plan to dealwith challenges to adoption" -

Jerry Hubbard, executive vicepresident, Energistics


17/28

Embedding Energistics open standards into

our E&P products allows Landmark to reduce

R&D costs and enhance connectivity with our

global customers.

Paul Koeller

President Landmark Software & Services, Halliburton


18/28

Production


Weatherford minimizing inventory costsOil services giant Weatherford recently embarked on a project to try to reduce the amount of capital ithas tied up in inventory (storage).

The main driver for the project was the fact

that capital is becoming harder to come by

so the company CFO wanted to find ways to

better utilize the capital the company alreadyhas, says Weatherfords vice president of IT

Michael Dove, who was given the task of

finding a way to do it.

The company was benchmarking the

amount of working capital it has compared

to other companies in the field and was not

satisfied with the results.

Inventory at Weatherford is large and

very complex. At the time the project was

initiated, the company had about $2.5bn

worth of goods in inventory. And it operates

from around 1,000 different locations, withinventory stored in nearly all of them.

The company is also growing very fast

from $1bn revenues in 2003, to around

$8.5bn in 2009, and expecting $22bn in 2013

and all of this growth creates management

challenges.

Inventories have been allowed to build

up over time, partly because there has been

too much emphasis on profit and loss, rather

than the balance sheet, Mr Dove says.

The company also did not hold anyone

accountable for inventories as they contin-

ued to grow.The first step to improve inventory cap-

ital was to implement a system which would

enable company executives to be able to eas-

ily see where the inventory actually was.

The next step would be to work out

where the capital was providing most bene-

fit, and which areas the inventory could be

cut and then make sure the cuts were actu-

ally implemented.

The companys CFO asked Weather-

fords vice president of IT Mike Dove to try

to find a way to improve use of inventorycapital, with the available data. Youre al-

ways giving me a hard time that we're not

leveraging the data enough, he told him.

Mr Dove thought that it could be

achieved with Oracle Business software.

I went to Oracle and said, lets put to-

gether a proof of concept to prove this can

be done, he says.

All of the data about inventory was al-ready available, Mr Dove says. The chal-

lenge was coming up with a better way to

view it, which would help the right decisions

to be put in place to reduce it and also un-

derstand better which parts of the company

were doing the best and worst job at manag-

ing their inventory.

All we had to worry about was the da-

ta and we know our data very well.

The company was very keen to have

something installed quickly.

Implementing the new software tooltook 60 days, with the software implement-

ed and data transferred in under 30 days, he

said.

By comparison, the company has had

an ERP (enterprise resource planning) soft-

ware implementation going on for a number

of years, he said.

The systemThe inventory management system Mr Dove

implemented enabled the CFO to see how

much inventory there is in the company by

branch, by region, by product line, and by

person responsible for it. The CFO can also

set targets and measure progress against

them.

The CFO can put together a top level

view, for example to see how the inventory

of Weatherfords 10 major product lines,

such as artificial lift, is changing.

It was important to measure inventory

turns per year (the number of times per year

a certain item is brought into inventory and

then used). A low turn rate indicates goods

being in inventory a long time.Keeping items in storage for long

lengths of time can be justified in certain sit-

uations (where you might urgently need

something quickly, and it can be difficult to

get hold of). The important thing is to make

sure you are only keeping high value items

in long term storage when it is important to

do so.

The system can provide comparativedata for example, you can view the

amount of money tied up in inventory for

different items next to their their sales, and

identify items which have far too much in-

ventory capital for the amount of sales they

generate.

The system can also manage the differ-

ent ways different departments do their cal-

culations, and present the numbers to differ-

ent people calculated in different ways for

example, in the way inventory which is

transferred from one place to another is ac-counted for.

This way, it can present data to people

in different departments according to how

they want it calculated, but the CFOs top

level view has everything calculated in the

same way.

Weatherfords softwareWeatherford made a decision to standardise

on the software applications it was using in

2003.

It uses JD Edwards software to manage

the supply chain and revenues (this has 6,500

users); Hyperion software for SEC report-

ing; and PeopleSoft for human resources and

competency management.

On a company wide level, it emphasis-

es the importance of staff working with soft-

ware as it is supplied off the shelf, not ask-

ing for customizations to the software to suit

the specific needs of one department.

As the company grew, it took steps to

ensure that it had the same part number for

the same item (such as a length of 20 foot

drill pipe of certain specifications), despitethe fact that some of the companies it ac-

quired had their own part numbering sys-

tems. This meant that the overall corporate

system wouldnt have duplicate entries for

the same item.

RFID

Dr Ben Zoghi, of the RFID Oil and Gas So-

lution Consortium, said his organisation

based in Texas A&M University, said that

the organisation really isnt a standards body,

but exists to try to find opportunities for us-

ing RFID in oil and gas and encourage adop-

tion, using RFID standards.

Founding members include Texas

A&M University, Motorola, Merlin Con-

cepts & Technology, Shipcom Wireless, Av-

ery Dennison, Dow Chemical, BP, Universi-

ty of Houston, and EPC Global.

Installing RFID is harder than it looks.

WalMart wanted every item to have RFID -

it didn't manage yet, he said.

The oil industry doesnt yet fully trust

the technology. We have to explain what

can and can't be done, he said. Our group

is a support platform.


19/28

Production

January 2010 - digital energy journal 17

Optimising gas wells with remotemonitoringCalgary oil and gas data management company Zedi helped a oil and gas operator in Southeast Alberta(Canada) to get a much better understanding of how to optimise production on its 2,500 shallow gaswells using a fleet of portable flow measurement systems.

The Western Canadian Sedimentary Basin has

around 50,000 shallow gas wells all with

low flow rates.

Operators have a big challenge working

out the best strategy to optimise them. Should

you have continuous artificial lift on them, to

keep the water out of the wells? Should you

just do periodic dewatering operations (Eg

with coiled tubing)? How often should youdo fracturing?

Previously, the oil and gas operator had

done monthly tests on all of its wells, by driv-

ing out to them with testing equipment, but

this wasnt generating enough data to put to-

gether an optimisation strategy.

So the company asked Zedi to build a

fleet of 35 skid mounted portable flow

measurement systems, which could be driven

out to the different wells and left to take con-

tinuous measurements of gas flow.

Each skid contains a metering comput-er, which can measure and store data about

gas flow, and a communications system (cel-

lular or satellite) which can send the data back

home. (Zedi also makes the data immediately

available to customers on its portal ZediAc-

cess.com).

By building up data over time, and

watching how flowrates changed after differ-

ent techniques were tried to improve produc-

tion, it was possible to get a better idea of the

right optimisation strategy for each group of

wells.

The wells are normally drilled in groups

very close together (see photo). The testingequipment is run on a group of wells.

The computer is connected to proving

taps at the well head, which enable all of the

flow from the well to be diverted through the

flowmeter by opening a valve, without build-

ing any new piping.

The operator just connects the system at

a group of wells, runs the test, communicates

data about the location and moves to the next

group of wells.

OptimisingThe system was used to work out the opti-

mum time to clean the wells

Most of the wells do not generate

enough gas to warrant using artificial lift, so

they are cleaned out periodically using coil

tubing rigs or swabbing (taking fluids out of

the well using cups on a wireline).

By gathering data on a group of wells

over a 3 to 6 month period, you can get a

much better idea of how often it is worth

cleaning out different wells. Some wells

showed an immediate boost in production fol-

lowing a cleanout, and others indicate thatlonger times between cleanouts was possible.

Many wells, despite going into the same

reservoir, have very different characteristics.

The system was used to compare hy-

draulic fracturing techniques.

The oil company thought that the higher

cost fracturing technique was the most effec-tive, but wanted to test this theory.

He originally came to this view by look-

ing at well test results from the different tech-

niques.

The Smart Skids were used to test this

in more depth.

6 pairs of new wells, both with the same

dewatering procedure used, with each frac-

tured differently, were monitored closely for

their performance

The test showed that the lower cost frac-

turing technology actually had a better per-

formance.It would have been impossible to do this

with just monthly data because the dewater-

ing has a short term impact on production.

A number of wells were also tested to

see if very frequent water cleanouts would

help.

The test showed that some wells with

continuous liquid removal performed as well

as a new well drilled, so the costs of continu-

ous artificial lift would be justified.

Theres a preconceived notion in the

industry that shallow gas wells arent worththe time of day. But an asset is an asset, and

through some inventive ideas, weve proved

that there is a better, more effective way to

manage your operational budgets. Who can

argue with that, the operator said.

The Zedi skid mounted portable flowmeasurement systems, which were used togather detailed information about

production on 2,500 shallow gas wells

Shallow gas wells in Southeast Alberta


20/28

Production


GE Oil and Gas - new UK support centres

GE Oil & Gas has opened two new facili-

ties in the UK a 3m facility upgrade in

Montrose, Scotland, for refurbishing sub-

sea trees and production control equip-

ment, and a 3m facility in Bristol, Eng-

land, for providing remote monitoring &

diagnostic services for subsea equipment.

ScotlandIn Montrose, Scotland, it has opened a

3m, 13 acre equipment refurbishment, re-

pair, warehousing and upgrading facility,

looking after subsea trees and their controlsystems, and surface production control

equipment, among other pieces of equip-

ment.

The centre can take subsea trees that

have been operating for a number of years,

and refurbish them.

It will provide services for customers

across Europe. 164 staff are employed

there.

Previously, GE services operated from

two different sites, on opposite sides of Ab-

erdeen.Weve combined a number of differ-

ent sites into one, says Nick Dunn, region-

al services leader, UK & Continental Eu-

rope, GE Oil & Gas. That allows us to

have one business thats completely fo-

cused on providing all the services associ-

ated with installation and maintenance.

The facility has a 20,000 square foot

production control systems building for

testing and flushing production controls

equipment, with a clean room for hydraulic

component testing and diagnostics, with

aerospace standards of cleanliness.It is very important that hydraulic oil

is very clean, otherwise it will cause a lot

of problems to the equipment over time.

To illustrate this, Mr Dunn says that

the dust you have on your finger, after plac-

ing it on your desk, is enough to contami-

nate a whole barrel of hydraulic oil.

The site also has facilities for welding

and machining.

GE anticipates that there will be a big

growth in its brownfield market, helping

customers to keep their older fields runninglonger by refurbishing the equipment.

Theres obviously a huge drive on

operators looking for more effective meth-

ods of extending the life of their fields. We

can take the equipment back to a new stan-

trees, tree tooling systems and seafloor

well head systems, well head tubing, and

associated connectors.

You can also upgrade the control

modules, or pods on many pieces of sub-

sea equipment, to install newer computer

systems.

The facility also has a data link to

GEs new SmartCenter in Bristol (see be-

low) where it provides remote monitoringand diagnostic services. So it can ask the

engineers at its Bristol centre to take a look

at any equipment, remotely, in real time

and 24/7.

Once the refurbishment has been com-

pleted, and up to date data about the status

of the equipment has been generated, it

should be possible to manage the mainte-

nance program much more efficiently in

future, he says.

BristolGE has also opened a new $5m centre in

Nailsea, Bristol, offering remote monitor-

ing & diagnostics for subsea oil and gas

drilling around the world. The new centre

will add 30 engineering and managerial

dard, he says.

A focus has been on finding ways to

speed up the refurbishment process be-

cause while it is being refurbished, the well

is out of production.

If they pull a subsea tree, that well

isnt producing. You can start the clock

ticking. The sooner the operator gets back

online, the better its going to be.

GE can work 6 months in advance

planning a refurbishment, looking at what

jobs are required and what spare parts are

needed. It also has technicians who can go

offshore and try to find out as much as pos-

sible about the equipment before it is taken

out of service.

Each subsea tree has around 4,000 dif-

ferent components, which makes the refur-

bishment very complex.

When it comes into our facility we

have a line to refurbish something very

quickly, he says. We have the capabilityhere we can respond very quickly. We do

a subsea tree turnaround in less than 5

weeks.

The facility services production con-

trol equipment, hydraulic parts and subsea

GE Oil and Gas has opened new facilities in the UK for refurbishing control systems and remote monitoringand diagnostics of subsea equipment.

Monitoring subsea equipment remotely: GE Oil and Gas' new subsea monitoring and remotetechnology centre (or SmartCenter), located at the VetcoGray subsea control manufacturing site

in Nailsea, near Bristol, UK


21/28

Production

January 2010 - digital energy journal 19

jobs to the area. It is located at GE Oil &

Gas existing subsea controls manufactur-

ing site.

The centre was opened on October

15th 2009 by Ove Magne Kallestad, vice

president of subsea t

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