June 2011 Issue 31

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June 2011 Issue 31

Apr 2011 - digital energy journal

Digital Energy Journal - keeping you up to datewith developments with digital technology inthe oil and gas industry.

Subscriptions: Apply for your free print or elec-tronic subscription to Digital Energy Journal onour website www.d-e-j.com

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Digital Energy Journal2nd Floor, 8 Baltic Street East, London EC1Y 0UP, UKDigital Energy Journal is part of Finding Petroleumwww.findingpetroleum.com www.digitalenergyjournal.comTel +44 (0)207 017 3405Fax +44 (0)207 251 9179

Editor Karl Jefferyjeffery@d-e-j.com

Consultant editorDavid Bamford

Technical editorKeith Forwardforward@d-e-j.com

Finding Petroleum ForumsFocus on unconventionals - Sept 20Exploring in the Arctic - Oct 11People and the digital oilfield - Oct 20Building the optimum supply chain - Oct 25Onshore 3D seismic - Nov 93rd collaboration and the digital oilfield - Dec 1Getting control of your subsurface data - Mar 15

Social networknetwork.findingpetroleum.com

Advertising and sponsorshipJohn FinderTel +44 (0)207 017 3413jfinder@onlymedia.co.uk

Cover image: seismic streamer vessel Geo Caspian,on charter to Fugro Geoteam and operated byVolstad Maritime. Satcom company Marlink hassigned a 5 year contract to provide 512 kbps ofsatellite communications bandwidth and 10-15lines for the vessel

David BamfordConsultant Editor, Digital Energy Journal

‘Breakthrough’technologies – that

reduce costs

I have commented before that small companies that have new technology to

offer seem to find it very difficult to attract funding from investment banks,

private equity houses etc, as compared say to exploration companies that want

to drill a dry hole in some exotic, previously unregarded, ‘moose pasture’, lo-

cation! If we wait for the financial industry to support fledgling oil & gas tech-

nology companies, with one or two honourable exceptions – Energy Ventures

of Norway would be one - we will wait a very long time.

We are using Finding Petroleum – our Digital Energy Journal and our Fo-

rums and Conferences - to try to identify some new technologies with real po-

tential, and to allow others the opportunity to do this too. Also I do this with

articles I write for OilEdge and GeoExpro.

We try hard but we cannot spot everything that’s promising – please get in

touch via the Finding Petroleum web-site if you have something to tell us.

I thought that this time I would focus on technologies that seem to me to

offer a ‘breakthrough’ on costs, specifically on Finding, Developing or Operat-

ing Costs per boe.

There are indeed technologies ‘out there’ which would dramatically re-

duce oil companies’ costs, typically in entrepreneurial companies rather than

the oil field service company ‘behemoths’.

Some examples are:

• Reducing the cost of exploration reconnaissance: ArkeX and Bell Geo-

space offer Full Tensor Gravity Gradiometry that allows the screening of sig-

nificant ‘new’ basins.

• Reducing the cost of exploration wells: Geoprober Drilling for exam-

ple has an approach that might halve the cost of drilling deep water exploration

wells.

• Reducing the cost of onshore 3D seismic: Wireless Seismic, iSeis and

others are at the forefront of bringing to market a new cable-less technology

which can dramatically reduce the cost of acquiring onshore 3D seismic. Also

Hewlett Packard is working with Shell to bring a brand new sensor idea to

fruition.

• Reducing the costs of well work/interventions: Welltec’s ‘robots’ work

on wireline, dramatically reducing costs because a rig or coiled tubing unit is

not needed.

• Reducing non-productive time in drilling infill wells thereby giving rise

to significant savings in time and total well costs: Downhole Fluid Solutions

offer a novel technology.

I emphasise that this is a only a list of promising technologies that I have

seen recently; it is not intended to be definitive and I have focussed here on

‘breakthroughs’ that could reduce the cost/boe base of our industry…unlike the

costly ‘incrementalism’ offered by the big oil field service companies. Nor do I

mean to suggest that all these companies are without financial backing: some

are well funded and/or generating significant revenues.

Clearly, there other technologies ‘out there’ that offer exploration risk re-

duction, improved reserves recovery, automation, collaborative working envi-

ronments and so on – maybe next time!

David Bamford is non-executive director of Tullow Oil, and a past head of explo-ration, West Africa and geophysics with BP

1

Calendar of Events 2011Unconventionals: exploration, technology and business Tuesday, September 20, 2011 The Geological Society, London, Free Exploring in the Arctic Tuesday, October 11, 2011 The Geological Society, London, Free

People and the digital oilfield Thursday, October 20, 2011 Norwegian Petroleum Museum, Stavanger 2700 NOK (£300)

Building the optimal supply chain in the mature province Tuesday, October 25, 2011 Aberdeen Marriott Hotel, Aberdeen, Free

Onshore 3D seismic Wednesday, November 09, 2011 The Geological Society, London, Free

3rd collaboration and the digital oilfield Thursday, December 01, 2011 Hallam Conference Centre, London, £300

Getting control of your subsurface data Thursday, March 15, 2012 Aberdeen Marriott Hotel, Aberdeen, £250

See the latest programs, register to receive conference updates and join our social network atFindingPetroleum.com

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Energistics demonstration – linking 5 companiesPetrolink, Halliburton, Geologix, Kongsberg, IDS and Schlumberger managed to integrate all of their systems together using WITSML, at theEnergistics exhibition stand at IADC

We’re all working for the government nowIt is probably fair to say that governments now control the worldwide drilling business, says Kevin C Robert, senior vice president –marketing and business development with Pride International Drilling

Verdande Technology – advising you on drilling based on past experienceVerdande Technology has launched commercial operations with Shell for its technology that helps operators predict and identify drillingproblems in advance - based on similar wells drilled before

SafeKick develops drilling simulatorSafeKick, a new company based in Reading, UK, has developed a drilling simulator PC software package, to support training, planning andreal time operations

eDrilling develops downhole training simulatoreDrilling Solutions of Stavanger has with partners SINTEF and Oiltec developed a 3D drilling simulator, which can be used to train all of thepeople who will be involved in a drilling project. Statoil commissioned it to be built and has committed to use it for 100 days a year

APS – high-res drilling pressure sensorAPS Technology of Wallingford, Connecticut has developed a high resolution, real-time pressure-while-drilling (PWD) sensors to be installedbehind a drill bit

VAM Drilling – developing bespoke drillpipeVAM Drilling believes that in the future oil and gas companies will want drillpipes made bespoke for different drilling projects – and the com-pany is ready to provide it

Strengthening wellbores in depleted reservoirsIt is not easy drilling through a reservoir which is partly depleted, something you might have to do when drilling infill wells on mature fields.Downhole Fluid Solutions of Aberdeen has developed a solution

X Drilling – open your valve infinite timesX Drilling Tools, a company based in Adelaide, Australia, has developed a special valve to let fluid flow into the well bore but above thedrillbit, which can open and close infinite times

3

Contents

DHL – helping you manage supply chainsDHL, one of the world’s leading logistics providers, is aiming to grow its business in the oil and gas industry managing supply chains formaintenance, repair, operations and overhaul materials

Vendors and the soft stuffTechnology vendors need to be good at the ‘soft stuff’ – making sure people are comfortable using their software – or risk finding out in ayear’s time that their software is not being used, writes Dutch Holland

Fibre optics to listen to your wellsStandard fibre optic cables that can be used as acoustic sensors without any discreet components along the fibre can be useful in oil and gaswells if you want to know at which point oil, gas, water or sand is entering your well, says Doug Gibson, CEO of Fotech Solutions

16

Drilling

Exploration

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9

8

4RESQML – ready for Sept 2011 releaseThe industry ready version of Energistics’ RESQML, the exchange standard for subsurface data, will be released by September 1

Adrok develops third set of survey equipmentAdrok of Edinburgh, a company developing a new atomic dielectric resonance (ADR) scanner subsurface survey technique, reports that it hasdeveloped its third set of survey equipment, and is also providing its services in North America

Increasing productivity by taking away softwareMany oil and gas companies have a complex array of software tools used to work with subsurface data to build models and makecalculations on which key decisions are made. Can it be simplified?

Autoseis – simple wireless seismic recordingAutoseis of Carrolton, Texas has gone for a simple approach with its wireless land seismic recorders; the data is stored on the field units (HighDefinition Recorders – HDR) and gathered later

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June 2011 - digital energy journal

Production

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Harris acquires Schlumberger’s satcom divisionHarris Corporation has acquired Schlumberger’s “GCS” satcom division. Along with its acquisition of CapRock Communications last year, itprobably becomes the oil and gas industry’s largest satcom provider

Fibre installations – build a subsea connection pointBy building a subsea connection point, installing fibre optics to offshore platforms might be easier – because very few companies have bothtelecoms and oil and gas expertise, writes Stephen Lentz of WFN Strategies

Communications

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Exploration

digital energy journal - June 2011

If you regularly spend time trying to get sub-

surface data from one software application to

another, or regularly encounter problems after

transferring data (such as wells moving to the

other side of the reservoir), you’ll be looking

forward to the release of RESQML 1.1, an in-

dustry-ready data exchange standard for sub-

surface data, with development managed by

Energistics. It will be released by September 1

this year.

“This RESQML initiative makes my life

a lot easier for doing data interchange demand-

ed by our customers,” said Dr Tony Fitzpatrick,

simulation gridding architect with Schlum-

berger, speaking at the Finding Petroleum Lon-

don conference on April 20, “business oppor-

tunities with subsurface data”.

Many people have experienced data cor-

ruption when transferring data from one sys-

tem to another, such as well trajectories losing

datums, 3D grids getting changed from time to

depth, horizon data being damaged in the data

transfer.

“When you find that your wells are on the

other side of the reservoir it is particularly an-

noying,” Dr Fitzpatrick said. “It is entirely due

to lossy exchange of information.”

Version 1.1 of RESQML will be released

in September 2011, and vendors are expected

to start supporting it around then (although the

vendors are not following any specific time

schedule).

Version 1.0 of RESQML has already

been published (in January 2011), but was in-

tended to be used for development purposes,

not general industrial use, to provide an oppor-

tunity to remove any bugs in version 1.1.

RESQML can be used for all stages of

subsurface work, from structural modelling to

simulation and well planning.

RESQML is being integrated with other

Energistics standards (WITSML, for drilling

data, and PRODML, for production data), so

(for example) you can add WITSML drilling

data to update your RESQML reservoir mod-

el.

There are additional benefits to being

able to move data easily from one software

package to another.

It gives users more freedom to pick the

software package which work best for them,

rather than being restricted to using software

supplied by one company.

“We recognise there are multiple applica-

tions, and you want to cherrypick,” Dr Fitz-

patrick said. “Best in class applications are sup-

plied all the time by vendors.”

Also, if users are less restricted to using

subsurface software from a single manufactur-

er, there is more incentive for smaller software

companies to develop software applications.

From the oil company’s point of view, if

data can be moved from one package to anoth-

er more easily and consistently, it is able to

manage quality and consistency of the work-

flows and record exactly what was done, with

metadata showing how the data came to be in

its current format.

TestingIn April 2011, Energistics held a week long

“ILAB” meeting, validating the exchange of

reservoir models written using RESQML be-

tween different software applications owned

by vendors and oil companies.

The RESQML development team have

committed to running 2-3 “ILABS” every year,

to move data files from one software applica-

tion to another, testing everything. The team

also uses this time to work through more com-

plex development issues and plan future releas-

es.

Oil companies are being encouraged to

submit subsurface data files to the RESQML

developers so they can use them for testing.

What RESQML includesData in RESQML format can include a grid-

ded volume, data about horizons, static infor-

mation, time data (for a simulation), units be-

ing used.

The system can record data about con-

nections, not just the geometry of the reservoir

model. For example, it can describe which

cells specific wells intersect, and where the

faults are.

If a gridded volume is imported into an-

other piece of reservoir simulation software

which doesn’t know that a fault exists, the

software will create a simulation on the basis

that fluid can flow freely from one cell to an

adjacent one, without knowing that it would

be blocked by a fault.

RESQML can handle faults modelled in

both pillars and stair steps. It can include data

about flows and temperatures.

RESQML can also manage data about

multiple reservoirs which are connected by the

same well.

“8 corners of the cell are insufficient to

describe the geology,” Dr Fitzpatrick said.

“We have to handle much more complex

geometry

and we’ve

stepped up

to that in a

much more

complex

way.”

It can

track where

multiple

grids have

been devel-

oped for the

same part of

the subsur-

face. “You

need to

know which

set was used

in which

particular simulation,” he said.

There have been attempts at building a

standard format for reservoir data before,

called “RESCUE”, but work on this stopped

in 2009. This initiative which oil and service

companies alike supported, supplied a C++ li-

brary to store and retrieve the data. “Like all

software it rusted over time, and the underly-

ing technology became obsolete” he said.

RESQML provides the data interchange

schema in XML format leaving companies

free to create readers and writers inside their

own applications.

To change data from RESCUE to

RESQML, you load the RESCUE data into

your normal software and export it in

RESQML format.

RESQML also records which units are

being used, something which RESCUE was

not so rigorous in insisting upon. This could

lead to mistakes when numbers were associat-

ed with the wrong unit.

“RESCUE wasn’t terribly good at han-

dling units, it was just a string that was passed

around,” Dr Fitzpatrick said. “Now it’s much

tighter and there’s a schema for describing the

units. For engineers you know how important

it is to get units correct.”

Exchange vs storageIt is important to note the difference between

data exchange and data storage, because data

might not be in the same format for both.

The data is originally developed and

stored in a software application, and is stored

in whichever system that software application

RESQML – ready for Sept 2011 releaseThe industry ready version of Energistics’ RESQML, the exchange standard for subsurface data (reservoirsand earth models), will be released by September 1

Helping you move subsurfacedata between applications: DrTony Fitzpatrick, simulationgridding architect withSchlumberger

5

Exploration

June 2011 - digital energy journal

uses.

It is converted to RESQML when it needs

to be exchanged (moved) to other software

packages. There it will be converted into what-

ever data storage system that software uses.

In practise there is likely to be conver-

gence over time between the ways that differ-

ent software packages store the data, and with

RESQML, particularly as many of the people

building RESQML are also involved in build-

ing subsurface data packages. “Over time there

will be considerable overlap between internal

and external exchange model. The boundaries

will be ironed out,” he said.

RESQML has been designed to honour

the fidelity of these internal models as far as

possible, to ensure that every detail developed

in one software package can be carried across

to another one within the RESQML data.

This won’t work if the first software

package has functionality which the second

one doesn’t, such as hierarchical zonation. This

will mean that functions of the data created and

viewable in one package can’t be accessed in

another one.

Big data filesBecause the reservoir data files are so large,

users are recommended to compress the

RESQML da-

ta before ex-

changing it,

into Hierarchi-

cal Data For-

mat (HDF5), a

set of file for-

mats for large

amounts of

numerical da-

ta, developed

by a non profit

organisation,

HDF Group,

and used in a

variety of in-

dustries.

You can compress data by factors of ten,

but do not lose any of the detail.

With data stored in HDF, it is easy to

look at the reservoir model in specific regions

– eg slabs or smaller zones, generated from

the bulk data.

“It’s an efficient way to store multidi-

mensional data across platforms,” Dr Fitz-

patrick said. “It’s being adopted by some oil

reservoir simulation people to store their out-

put results. We encourage people to store bulk

data in this format.”

“1.5m cells isn’t big in today’s world;

we’ve been playing with 100m cells,” he said.

“This is why we need to step up to this HDF 5

technology.”

Watch a full video and download slides of

Tony Fitzpatrick's talk at:

www.findingpetroleum.com/video/224.aspx

6

Exploration

digital energy journal - June 2011

Many oil and gas companies have a complex

array of software tools used to work with

subsurface data to build models and make

calculations on which key decisions are

made.

Bringing in new software is often justi-

fied by calculating productivity gains from

using the individual new software applica-

tion; however the introduction of yet anoth-

er tool may reduce productivity.

The company may gain more by taking

away software or rationalising. “If you want

to make productivity gains it might be worth

looking at whether you can simplify things,”

said Ed Evans, cofounder and Managing Di-

rector of New Digital Business(NDB), a

consultancy to the upstream oil and gas in-

dustry, and a past manager of technical sys-

tems with BG Group, speaking at the April

20th Finding Petroleum London conference

“business opportunities with subsurface da-

ta”.

“Subsurface software functions within

a complex environment of infrastructure, da-

ta and operating systems. This complexity

often negatively impacts end user productiv-

ity.”

Looking at a particular workflow, like

planning a well path for example, it is not

unusual for a company to have say 3 or 4

tools for visualising and modelling the reser-

voir, a range of tools for plotting well paths,

and then the drillers want to use their own

tools for well paths, bottom hole assembly

and drilling and sampling operations design.

This leads to multiple internal data

transfers, data dead ends for calculated risk

or multiple realisations and extended

timescales for work and rework.

When it comes to managing the portfo-

lio of software tools, some companies do it

very well, some companies do it on occasion

and results deteriorate, other companies

don’t do it at all, he said.

Productivity can decrease if there are

too many (or not enough) choices of soft-

ware tools; if people don’t know how to use

them; if there is a lot of searching for data,

or reformatting it; if it is difficult to move

data between different tools; if there is a lot

of system downtime or the network is slow;

if people spend too much time having to re-

do work to fit into the wider business

process; if there is no support or help if

things go wrong; if people aren’t confident

in the system.

Productivity can be increased where the

software tools mirror or enhance the exist-

ing business processes; if people know how

to use the software; if information is avail-

able in the right format to load into the soft-

ware; if people trust the tools and trust the

data; if the systems are available and respon-

sive when required; if people understand

how this particular business process fits into

the broader business; if support is available;

if there is confidence in the system.

So you can see how people can be

much more productive overall if the compa-

ny’s technical systems environment is well

managed and delivers the data and applica-

tions effectively to a well trained workforce.

A well-managed application portfolio is a

critical element of that.

“We have fewer and fewer resources.

We need to know that when we ask people

to do a task they can do that with confidence

using the software tools available,” he said.

There are many reasons for over-com-

plex application toolsets: due to preferences

of individual staff members for what tools

they want to use, due to inheritance, due to a

lack of pruning or simply due to a lack of

control or planning in this area.

Individual users are often adept at jus-

tifying the need for new technology or re-

taining the status quo according to their pref-

erence. For example, a reservoir modeller in

Egypt might say that the reservoir is very

complex so it requires a special tool to mod-

el it, rather than the one the company usual-

ly uses.

But then the team doing reservoir sim-

ulation might want to use a certain tool be-

cause that’s what they’ve always done, and

that one doesn’t integrate well with the reser-

voir modelling tool.

There are other examples of geologists

being sent to remote sites and being expect-

ed to use software applications they have

never used before. Is it better to build up the

users’ skill set or to rebuild the model in the

more familiar package? “You can get differ-

ent results with different tools,” he said.

Who should lead the process of control-

ling applications? The company IT depart-

ment are often concerned about the range of

applications and the cost of support and

maintenance but are not in a position to de-

cide or dictate which software applications

the company should use. “Where a CIO may

be confident in questions of infrastructure or

data and information management, they are

often much less confident with the applica-

tion software. They feel that it’s more of a

user domain,” he said.

So where is the business case for reduc-

ing complexity in the applications portfolio

and who should lead this work and own the

results?

“Every time you add a new application,

you’ve got to integrate it with the others. So

managing the applications suite is not just

about the purchase cost of new applications

but the net impact of new tools on user pro-

ductivity.”

“The person who is responsible for how

a function is carried out in the business

should be responsible for the tools used in

carrying out that function.”

Depending on the organisation structure

this person may be a Chief Geologist or Head

of Reservoir Engineering. The process can be

facilitated by IT or a project manager.

Making a choiceIf you have several software tools which all

do the same thing, and you want to simplify

things, then a decision needs to be made as

to which tools the company is going to use

as a standard.

It is much easier if there is a “discipline

head” in the company who will make deci-

sions about which tools that people in the

discipline is going to use.

One of the barriers to controlling appli-

cations can be the difficulty in in understand-

Take away software - increase productivityMany oil and gas companies have a complex array of software tools used to work with subsurface data tobuild models and make calculations on which key decisions are made. Can it be simplified?

Thinking of the productivity gains you canmake by being more organised aboutsubsurface applications - Ed Evans,cofounder, New Digital Business

7

Exploration

June 2011 - digital energy journal

ing the value of each tool to the business and

clarity around “who uses it to do what?” Ide-

ally you would start with the business

process and match the application to the

function, but subsurface business processes

are difficult to map and defy conventional

process modelling.

Process modellingConventional process modelling defines the

tasks which need to be carried out, the order

in which they should be carried out and

which tasks need to happen before others

(dependencies). When each part of the

process is completed the ‘dependent’ tasks

can go ahead.

In modelling the subsurface it is quick-

ly apparent that the tasks undertaken, the or-

der in which they happen and the amount of

effort or value placed on each task all depend

upon the geological context, the amount of

data and the ‘size’ of the envisaged invest-

ment, so the process if different each time.

Also the ‘products’ of the processes are nev-

er finished, the seismic structural model can

always be refined and updated based on new

data, for example.

To break this problem and ascribe the

software to the business process, New Digi-

tal Business (NDB) suggests that you define

the specific tasks as components of the busi-

ness process but don’t try to combine them

or work out the schedule or dependencies.

The existing software tools can be listed

against the components as in NDB’s ‘Dog-

Tag’ model.

The ‘Dog-Tag’ model can be used to

classify the existing software tools accord-

ing to the stage of the subsurface data

process they are used in.

For example at the “play evaluation”

stage, you can have tools to analyse wells,

do basin dynamics, hydrocarbon charge,

framework and reservoir at the appropriate

level of detail. At the “prospect evaluation”

stage you can have tools to analyse different

aspects of the prospect. You have other sub-

surface tools for developing the reservoir;

and tools used during production.

This mapping exercise makes it is easi-

er for a discipline head to make a decision

about which software tool the company is

going to standardise on to do each specific

task.

You can develop lists of software tools

which every asset should have available, and

specialist tools which need to be available to

certain individuals for tasks they do every

now and again perhaps as a service to the as-

set teams.

Don’t set targets for how many soft-

ware applications you want to ultimately be

using – because users might actually need all

of the software tools on their computers. “It

is more important to try to work out exactly

what people need,” he said.

Once you have developed this clear

model, everybody in the company can use it,

even if they are not subsurface specialists.

“It is something even IT managers can un-

derstand,” he said.

The ‘Dog-Tag’ model can be used to fill

in gaps or remove duplicates in functionality

as determined and agreed by the function.

By aiming for a tool per task it is much eas-

ier for users to make choices about their

training and technical development and for

the support organisation to develop their da-

ta management processes and infrastructure

plans. Controlling the applications portfolio

is an essential cornerstone of an effective

technical systems environment.

Watch a full video and download slides of

Ed Evans' talk at:

www.findingpetroleum.com/video/216.aspx

Exploration

digital energy journal - June 2011

For land wireless seismic recording devices,

you’re much better off storing the data on the

unit itself rather than sending it back to a cen-

tral unit in real time, according to Ralph

Muse. Ralph is the President of Autoseis, a

Global Geophysical Company, that develops

seismic recording equipment.

“Everything must be as simple and reli-

able as possible,” he says. “We don’t have

complex radio systems. You put the units out

and they stay there for weeks, and then bring

them back to camp. By keeping the units sim-

ple and low cost, it is easy to provide redun-

dant units and over sample the survey.”

Mr Muse is an expert on radio data com-

munication. He was CEO of NextNet Wire-

less which was acquired by Motorola in 2006;

he was also was COO of the wireless internet

company Metricom Inc, and Senior Vice

President of land seismic imaging at Input

Output (since renamed ION), a company also

specialising in wireless land seismic record-

ing.

Given his background in wireless data

communications, it is ironic that he has chosen

not to include radio data links in the High Def-

inition Recorder (HDR). Mr Muse attributes

this decision to his experience with other wire-

less systems. “Out in the field, there are always

problems, and places you can’t communicate,”

he says. “It complicates operations for no real

reason. I would hate to be the field operators

tasked with maintaining a complex communi-

cation infrastructure in difficult terrain.”

“When you start trying to connect thou-

sands of units, it is very complicated, and

takes up a lot of bandwidth. It’s a problem in

scaling. I don’t know what happens when you

try to do mesh networks for tens of thousands

of units, and I don’t want to find out.”

For example, Mr Muse said he worked

with a wireless seismic system which required

a radio contact to be made with every unit be-

fore shooting began. “Some of them are in

ditches, some of them are behind a hill. It’s

hard to get a connection to every one, so you

end up having a lot of problems, and have to

set up relay

transmitters

to make sure

you have all

the connec-

tions.

You’ve trad-

ed cable

maintenance

for communication system maintenance; so

what have you gained?”

Companies often have radio licensing

problems, discovering that a technology they

can use legally in one country at a certain fre-

quency can’t be used in another part of the

world.

AutoseisRDSeismic LLC was founded in late 2008

by Ralph Muse, Initial product launch and

field testing were completed in spring 2010.

RDSeismic was acquired by seismic service

provider Global Geophysical Services Inc.

of Houston, in Nov. 2010. The company was

then renamed AutoSeis Inc.

“Global Geophysical used three other

wireless seismic systems,” Mr Muse says.

“They realised it made sense to own their

own supplier. They can have their own tech-

nology and customise it the way they want.”

The company is currently building its

first 10,000 HDR units, with a further order

for 28,000 units, to be exclusively used by

Global Geophysical to provide seismic sur-

veys for its customers.

The company is also developing an

ocean bottom seismic recording system us-

ing the same HDR technology.

The systemThe core of the Autoseis system is the HDR

unit, which is “about the size of an iPhone,”

Mr Muse says. It weighs just 3/10th of a

pound (136g). The unit usually has a 20amp

hour lithium battery, which weighs about

2.9lb (1.3kg).

To set up a survey, you decide which

specific times you would like the units to

record in advance (eg weekdays 6am to

8pm) and program that into the unit, along

with the sample rate and tell it what type of

geophone you will use. Then you drive out

to the field, place the units in position, record

their locations and start shooting.

To download the data afterwards, you

plug the units into a special rack which can

take about 20 units at once. The software au-

tomatically downloads the data, uploads pro-

gramming for the next survey, and checks if

the software needs updating. All of this takes

about 2 minutes, so by the time you have in-

serted 20 units into the downloading rack,

the first one is ready to be removed.

The unit contains a custom microchip,

GPS, clock, motion sensor, infrared commu-

nications device and 8 gigabytes of data stor-

age.

The system has one circuit board, and

is fitted in a plastic case completely filled

with resin. “You don’t have to worry about

water getting in because it is full of resin,”

he says. “These units are tough, you can run

over them without damage.”

The system records in 32 bits, with 26-

27 of those bits actually available for seis-

mic processing, which means it can get a dy-

namic range of around 160dB, Mr Muse

says. This compares to 120-140 dB range for

24 bit recording systems. “Our noise floor is

a lot lower,” he says. “You can see data you

clearly could not see otherwise.”

The 8gB of memory storage onboard is

enough to store 85 (12 hour) days of data at

a 2 millisecond sample rate, so data storage

capacity is not an issue.

The unit also contains an accelerome-

ter (similar to the iPhone). When the unit is

moved to another location, the accelerome-

ters detect that it has been moved, and that it

needs to start a new record for the new loca-

tion.

The HDR units can also communicate

by infrared, so you can interrogate them with

a laptop in the field without cabling them up.

All the units have barcodes. When they

are being laid out in the field, the surveyor

has a hand held device also containing a GPS

which can scan the barcode, so the computer

system knows which device it is and where

it is.

While in the field, the units can be con-

nected to radio communications if desired,

for example if you check if there is back-

ground noise (for example from a train or

farm equipment) close to receivers which are

out of your line of sight, which might make

the recording useless. But you don’t need to

monitor each individual unit.

Land wireless seismic will only work if it issimple, says Ralph Muse of Autoseis

Autoseis – simple wireless seismic recordingAutoseis of Carrolton, Texas has gone for a simple approach with its wireless land seismic recorders; thedata is stored on the field units and gathered later

The Autoseis wirelessrecording unit

8

Drilling

June 2011 - digital energy journal 9

Energistics demonstration – linking 5companiesPetrolink, Halliburton, Geologix, Kongsberg, IDS and Schlumberger managed to integrate all of theirsystems together using WITSML, at the Energistics exhibition stand at IADC

In the future, many different companies will

be able to get involved in handling drilling

data, including gathering it from rigs, send-

ing it to shore, doing different processing

tasks on it, packaging it, transmitting it and

displaying it in the most useful possible

manner, with every company involved pro-

viding different expertise, and customers

free to switch between different data service

providers at any time.

This is the vision for Energistics’

WITSML, a standard for exchange of well

site data.

A demonstration was put together of

how future data systems could be structured

at Energistics’ exhibition stand at the recent

IADC (International Association of Drilling

Contractors) annual meeting in Amsterdam

on March 1-3.

The demonstration involved Petrolink,

Halliburton, Geologix, Kongsberg, IDS and

Schlumberger.

WITSML data was sourced from three

independent WITSML servers, one supplied

by Kongsberg and the other two by

Petrolink; from there, it was sent to client so-

lutions supplied by Kongsberg, Geologix,

Halliburton, IDS and Schlumberger for fur-

ther processing and visualisation.

WITSML has been around for several

years but there have been interoperability

problems caused by small differences in the

way the standard was implemented in differ-

ent companies (called ‘dialects’) which

made it hard for the systems to be all

plugged together. This has been addressed

and the next WITSML release, 1.4.1, which

will be published later in 2011, has had a

number of revisions to promote interoper-

ability.

The IADC demonstration was based on

WITSML version 1.3.1 and even with that

release the systems really can be plugged to-

gether and work straight away. “We all came

here on our own time, sat down yesterday

and got this working in a few minutes,” said

Jim Brannigan, real time data champion of

Schlumberger.

Companies in the demonstrationIn the demonstration, Petrolink provided a

data acquisition box, or “PetroDaq” rig serv-

er which would be used onboard the offshore

platform, collecting data from all of the rig

sensors. The server sends the WITSML data

to a “Petrovault” WITSML server onshore.

For WITSML communications from the rig

to the shore, a 500 kbps continuous data

communication is adequate.

The Petrovault server can then store the

data and serve it to wherever it is needed, for

further processing or for visualisation (en-

abling people to work with it).

UK company Geologix is collecting

operations data from a WITSML server, and

processing real-time geological information

in it (to provide information about litholo-

gies) and sending it back to the server.

Oil and gas software company IDS (a

company based in Aberdeen, Malaysia,

Canada and Indonesia), has developed tools

which interrogate the WITSML real time da-

ta stores, and gather the data, to make its

DataNet2 reports. 85 per cent of the data the

company needs for its geological reports can

be gathered from the system, the company

says.

Halliburton Drilling Services can pro-

vide data from its drilling operations in

WITSML. The data can be aggregated and

re-sent to wherever it is needed. Halliburton

also acts on the receiving end of WITSML

data, to populate its Engineers’ Data Model

(EDM) platform.

Kongsberg Oil and Gas Technologies

(KOGT) has services to distribute WITSML

data to clients onshore, where it is used in its

Kongsberg Intellifield operations rooms.

Schlumberger also works with the

WITSML data. “The more we can get this

into our clients’ workflows, the more the val-

ue of the information,” said Jim Brenningan,

real time data champion of Schlumberger.

Petrolink has developed a number of

visualisation systems, including one which

enables WITSML data to be viewed on an

iPad, in a special HTML5 format which is

designed for tablets.

There are currently 110 companies in

Energistics, although you do not have to be

a member of Energistics to use the standard.

“These companies are all competitors, but

you see how quickly they can work togeth-

er,” says Randy Clark, CEO.

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How you can connect a rig, onshore data store, office store, visualisation systems, reportingsystems and geological tool kits together, with systems from different companies, usingWITSML. It was demonstrated on the Energistics exhibition stand at IADC in March

10

Drilling

digital energy journal - June 2011

We’re all working for the government nowIt is probably fair to say that governments now control the worldwide drilling business, says Kevin CRobert, senior vice president – marketing and business development with Pride International Drilling

National oil companies, and sovereign wealth

funds, are having an increasing control on the

international oil and gas industry, to the point

where it is fair to say “governments control our

business,” said Kevin C Robert, senior vice

president for marketing and business develop-

ment with Pride International Drilling, one of

the world’s largest offshore oil companies.

Mr Robert was speaking at the Society of

Petroleum Engineers (SPE) / International As-

sociation of Drilling Contractors (IADC)

drilling conference and exhibition in Amster-

dam on March 2nd, in the plenary session “The

Challenges of New Frontiers – What Frontiers,

What Challenges?”

“National oil companies (NOCs) are no

longer content to let foreign oil companies

come in and control everything. NOCs now

dictate the pace.”

The percentage of all rigs owned by na-

tional oil companies has grown from 15 per

cent to 50 per cent.

“The vast majority of sovereign wealth

funds are heavily influenced by the objectives

of the government,” he said.

Sovereign wealth funds do not necessari-

ly hold maximising profitability as their top ob-

jective. “Many governments use sovereign

wealth funds to modernise the economy,” he

said.

For example, in Brazil, the drilling com-

panies are asked to sign contracts saying that

20 per cent of drilling personnel must be Brazil-

ian nationals within 6 months of starting work,

rising to 66 per cent in 2 years – so drillers are

being asked to train locals as well as drill.

“The people do not exist. You can’t find

Brazilians. But that is not changing the require-

ment. We have to train like crazy. You train 3

people to get one that you keep.”

The US government is also exerting con-

trol on the industry. Mr Robert believes that

there is a “strong desire in Washington to di-

minish the E&P business,” he said. “The co-op-

eration is not there.”

[The Deepwater Horizon disaster] was a

huge event in the industry, but to completely

shut down an industry is one of the most unrea-

sonable actions I’ve ever seen by a government.

We’ll get through it –but it’s very tough and

painful right now.”

Other business changesThe business dynamics of the oil and gas in-

dustry are also changing in many other ways.

Drilling rigs are not traded as a straight

commodity any more; there is a preference for

newer equipment, and this is showing up in

lease rates and utilisations. Pride calculates that

72 per cent of the jack up rigs in operations are

older than 1991.

Brand new rigs are 97 per cent utilised,

whereas category 4 rigs, built before 1981, are

66 per cent utilised. “They are struggling to find

work,” he said. “Is a third of the mobile off-

shore drilling unit (MODU) rig obsolete?

Maybe there’s some reality here.”

Many of the older rigs can only drill up to

3,000 feet, and there aren’t much wells under

this amount of water, he said.

Meanwhile “there’s an increasing demand

for high spec and multi function mobile off-

shore drilling units,” he said. “The performance

capability is becoming a bigger selection factor

than the price of the rig.”

“There’s a lot of drilling engineers in their

20s, 30s , when they get a new drilling rig and

see how nice it is, it is hard to go back to a 30

year old rig.”

When oil prices fell recently, daily rig

rates did not fall a similar amount, he said.

It is not just the equipment. Oil compa-

nies are making increasing demands on person-

nel, including demanding minimum levels of

competency.

“We have program for drillers with mini-

mum 5 years of rig time,” he said. “It's a new

frontier for us – trying to provide competency.”

Companies are also asking for preventa-

tive maintenance programs, and asking compa-

nies what succession plan they have if a driller

on the rig is ill.

There is also the question of whether

prices will ever drop again, if OPEC has said it

believes a fair price for oil is $90 to $100.

The new ‘floor price’, or the lowest price

oil is likely to go to, is $60, Mr Robert esti-

mates, if Saudi Arabia cuts production if there

is a surplus of oil.

Some companies put their floor even

higher than that - many new developments are

uneconomic at $80, he estimates.

Something else new is that 75 per cent of

crude oil futures are bought and sold by finan-

cial players.

The Macondo disaster could also prove to

increase the costs of drilling by 10 to 15 per

cent, he said.

IDS, an oil and gas software company headquartered in Malaysia, has launched version 2.0 of its Visnettool to help you see what is happening on all your wellsYou can get quick answers to questions such

as, how much did you spend over a certain

time period, what depth did I start the 9 5/8

inch casing on my last 10 wells, and in which

rock formation was I in at the time.

The system also works over a geograph-

ic interface - you hover over a well on a map

using your mouse, and see information about

it, such as water depth, spud date, total cost.

The data can be put into dashboards, re-

ports, word documents. It can automatically

gather data and put reports in a format as re-

quired by regulators, including the Norwegian

Petroleum Directorate (NPD).

VisNet will replace older systems that

worked with fixed queries. "We're trying to

give the customer a tool they can manage

themselves and configure it however they

want to," says Douwe Franssens, General

Manager- IDS Group at Independent Data

Services.

The source of the data is another IDS

product, "DataNet2" and its associated appli-

cations

Data and documents are entered directly

into DataNet at the rigsite by operator person-

nel; or data can be entered automatically us-

ing WITSML.

By using WITSML, data entry time can

be reduced; IDS estimates that the system can

free up 30 mins of time everyday for the peo-

ple responsible for completing morning re-

ports.

IDS started in business in 1995 with a

PC-based 'drilling data package', to gather da-

ta related to drilling; it was subsequently re-

written as an online system called "DataNet".

In 2008, DataNet2" was released, around the

WITSML data structure.

Getting answers about your wells - IDS

Free videos on the Finding Petroleum website

Overview of RESQMLWatch Tony Fitzpatrick, simulation gridding architect with Schlumberger, giving an overview of Energistics' new standard for exchange of subsurface data RESQML(tm), with commercial launch scheduled for September 2011.http://www.findingpetroleum.com/video/224.aspx

Statistical analysis on subsurface dataWatch Keith R Holdaway, from upstream domain, SAS Global Oil and Gas, talking using statistical analysis to determine more efficient and accurate exploitation strategies for your reservoirs, as used by Shell,Total and ConocoPhillipshttp://www.findingpetroleum.com/video/217.aspx

Making subsurface data storage and computing fit for purposeWatch Duncan Irving, senior analyst, Oil and Gas with Teradata, talking about how to make sure your subsurface data management infrastructure is fit for purpose, and able to handle data volumes over 10 petabytes and data samples every millisecondhttp://www.findingpetroleum.com/video/221.aspx

Integrating seismic, well and CSEM dataWatch Richard Cooper, CEO of Rock Solid Images, talking about how to integrate seismic, well and controlled source electromagnetic (CSEM) data, to help you get much more value out of CSEM data.http://www.findingpetroleum.com/video/219.aspx

Integrating subsurface data in different packagesWatch Jane Wheelwright, Technical Application Specialist with Dynamic Graphics, talking about how you can integrate data from different subsurface applications, to help with reservoir management and optimised decision makinghttp://www.findingpetroleum.com/video/218.aspx

Controlling your subsurface applications portfolioWatch Ed Evans, Co-Founder and Managing Director of New DigitalBusiness, give his tips on how to manage your subsurface applications portfolio - not arbitrarily slash the number of software applications, but make sure your company has the minimum number of applications it needs to minimise complexity, and applications use is standardisedhttp://www.findingpetroleum.com/video/216.aspx

Position standards in seismic surveysWatch Jill Lewis, Managing director of Troika International, talk aboutnew developments with position data on seismic survey records - and how it helps make the data much easier to manage with less positioning errorshttp://www.findingpetroleum.com/video/214.aspx

Drill cuttings under the microscopeWatch Alex Mock, senior geologist with Numerical Rocks, talking about how drill cuttings and cores can be put under the microscope to get a better subsurface understanding, and how this can be integrated with other subsurface datahttp://www.findingpetroleum.com/video/210.aspx

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12

Drilling

digital energy journal - June 2011

real-time systems using artificial intelligence

capability will play a key role in future inter-

pretation of drilling parameters that could lead

to catastrophic events.

ShellShell is using the technology to identify drilling

problems in difficult Middle Eastern wells.

Eric van Oort, Wells Performance Im-

provement Manager at Shell said, “Our test-

ing with DrillEdge technology produced com-

pelling results and demonstrated that unsched-

uled events don’t happen immediately.”

“We learned that there are predictable

and repeatable symptoms in advance of each

event on the order of hours, or sometimes even

days.”

“By applying DrillEdge technology, we

hope to recognize these symptoms much soon-

er, allowing corrective action to be taken by

leveraging Shell best practices to reduce their

occurrence”.

Now, Shell plans to deploy DrillEdge

technology at its Real-Time Operating Cen-

ters (RTOC) around the world which support

drilling operations.

Database of experienceVerdande Technology is increasing its library

of past cases which is available for operators

to use and comes standard with each DrillEdge

installation.

Development is continuing with addi-

tional datasets to increase the types of prob-

lems that can be diagnosed and number of ex-

amples of each that can be recalled.

When a new event is recognized, such as

symptoms leading to twist-off, stuck pipe or

lost circulation, the DrillEdge technology re-

trieves past cases that are most relevant to the

current situation and displays them on a

“radar” screen. This information allows an en-

gineering team to better interpret the new situ-

ation, and provide mitigation advice based on

company best practices and lessons learned in

previous cases.

Cases in the generic library are used with

customer approval and are “genericised” to re-

move any information that may be relevant to

a specific well. Some operators prefer to trade

cases with others, and some prefer to use only

proprietary cases that are not released for gen-

eral use.

Verdande Technology of Trondheim, Norway,

has announced a commercial rollout with

Shell Upstream Americas for its DrillEdge

technology, which is used to inform drilling

team about upcoming problems, such as stuck

pipe.

Experiencing stuck pipe can be a sudden

event. But the testing that Verdande Technolo-

gy completed with Shell demonstrates that da-

ta from hours or even days prior can be used

to predict that a stuck pipe event is forthcom-

ing. The difficult part is understanding that da-

ta, and then taking action to mitigate the fac-

tors that are leading up to the event.

The DrillEdge technology does it by

comparing real time data with information

from other wells where similar problems have

occurred.

“In our testing on historical well data we

have seen stuck pipe up to 6 hours in ad-

vance,” says Kevin Brady, VP sales and mar-

keting with Verdande Technology.

The system can also provide advance

warning that other problems may be about to

occur, such as the drill pipe parting (twist off),

downhole vibrations (stick slip), or losing

drilling fluid to the formation (lost circulation).

It is known as “case-based reasoning” –

where experiences are recalled and used to in-

terpret and solve current problems, using a

store of information about past cases.

The technology doesn’t only tell you

what might be going wrong; it provides rec-

ommendations on what to do about it based

on a company’s best practices. The software

recalls case studies of previous wells which

similar problems, and how the problems were

resolved.

The DrillEdge technology’s user inter-

face is a radar-style display which shows the

current drilling situation. Past “cases” are

shown on the display as a series of dots when

a similarity match of over 50% is calculated

based on a comparison of the real-time param-

eters to cases in the case base. Clicking on

each case reveals specific information about

the incident and provides recommendations

and advice on how to mitigate each situation.

The software automatically performs

pattern recognition by using a library of event

agents. For example the solution that predicts

twist-off event uses a combination of algo-

rithms that look for erratic drillstring torque,

maximum torque, string stall (when the drill

pipe suddenly stops rotating, and stick-slip (a

type of jerking motion in the drill bit). The

pattern of occurrence of the parameters over

time represents a condition that can be com-

pared to similar cases – and a level of similar-

ity can be determined.

The system works with live data from the

drilling rig, sent by WITSML, with high fre-

quency data transmitted at a minimum every

5 seconds.

Verdande Technology was founded in

2004 by a group of professors and students at

Norwegian University of Science and Tech-

nology (NTNU) in Trondheim.

The company is headquartered in Trond-

heim, with an office in Houston. It is financed

by Statoil Venture / Energy Capital Manage-

ment, Proventure Seed AS, Investinor,

founders and employees.

Different regions of the worldA critical question here is, if you know the

conditions that led to a stuck pipe situation

when drilling in (for example) the North Sea,

is that any use in (for example) Qatar?

Verdande Technology believes that it can

be – so long as you remove information about

the drilling parameters that are critical to that

part of the world.

“We’ve been able to genericise the cases

in our library – take out things that are well

specific - and have proven that they can be

used to predict problems in other parts of the

world,” says Mr Brady. “You can make each

case less dependent on parameters about that

specific area – for instance formation or lithol-

ogy.”

Using itVerdande Technology envisages that the soft-

ware could be used by drilling managers who

are (for example) managing a number of wells

simultaneously at an operations centre. “The

user interface is very intuitive, meaning with a

quick glance an engineer monitoring

DrillEdge can tell which wells to focus on,”

he said.

It can also be installed on the rig itself.

Significant regulatory changes have

emerged in the US in the wake of the last

year’s Macondo disaster in the deepwater Gulf

of Mexico. Verdande Technology expects that

Verdande Technology – advising you ondrilling based on past experienceVerdande Technology has launched commercial operations with Shell for its technology that helpsoperators predict and identify drilling problems in advance - based on similar wells drilled before

Drilling

June 2011 - digital energy journal 13

eDrilling develops downhole trainingsimulatoreDrilling Solutions of Stavanger has with partners SINTEF and Oiltec developed a 3D drilling simulator,which can be used to train all of the people who will be involved in a drilling project for their next well.SStatoil commissioned it to be built and has committed to use it for several years ahead

The company was founded in 2009 by Dr.

Helio Santos, a drilling engineer with Petro-

bras in Brazil for 18 years. In 2001 Dr. San-

tos joined a company called Impact Solu-

tions Group, which developed a “Managed

Pressure Drilling” system which was subse-

quently sold to Weatherford.

The idea of SafeKick is to let drillers

get a much clearer idea of what is going on

below the rig floor – to help them keep

drilling, and the well, out of trouble and un-

der control.

People can see a computer image,

which shows a visualisation of the bit

drilling through the rock, and what is going

to drill through next, together with all rele-

vant information needed by the driller for a

complete assessment of the well condition at

all times. You can see all of the casing struc-

tures, the blow out preventer, and surface

piping.

“We are trying to show the driller what

the condition of the well is,” he said. “We

provide high quality information rather than

high quantity data.”

Hydraulics, mechanical, thermal and

solids transport models are already imple-

mented. It can also integrate with other mod-

els such as pressure models and geomechan-

ics models. “Everything is integrated,” he

said.

When working with real time data, the

system can get a live feed of what is happen-

ing from the well using WITSML, OPC and

other protocols.

By comparing actual data with what the

simulator calculates the data should be un-

der an ideal and trouble-free situation, you

can see if something is going awry, and look

at it in more detail. It might be just a sensor

unplugged; but it might be a major problem

developing. And it is this latest condition the

software intends to help identify in the very

beginning.

When used to support real time drilling,

the tool can do functions such as recommend

the maximum speed you can put drill pipe in

or out of the hole (surge / swab estimates);

indicate the tool joint location inside the

blow out preventer; visualise different fluids

inside the drill string and annulus (useful

when displacing pills); and automatically

generating drilling reports.

The system can also be used in design-

ing and planning wells. You can use the tool

to check your planned flow rate and mud

properties will keep you within the safe mud

weight window and maintain adequate well

bore cleaning.

“One engineer with a major oil compa-

ny said, ‘I can design a well in an hour with

this, compared to a week before,’” Dr San-

tos said.

The company is working together with

a number of drilling contractors and opera-

tors to develop the tool.

There are various different packages of-

fered: a Standalone Package, where you can

simulate a well; a Well Data package, which

can gather data from the well (so the simu-

lation shows what is actually happening); a

Rig Package, where all of this is put on a rig;

and an Anywhere Package, where it is all

posted on the internet.

SafeKick develops drilling simulatorSafeKick, a new company based in Reading, UK, has developed a drilling simulator PC software package,to support training, planning and real time operations

eDrilling Solutions of Sandnes (near Sta-

vanger) together with partners has developed

a full size immersive drilling simulator,

which Statoil will use it for most of the year

to train all of the people who will be in-

volved in its drilling projects.

Statoil has signed a frame agreement to

use the centre for training for several years

ahead.

Although Statoil does not directly em-

ploy drillers (it contracts its drilling to

drilling companies), it will take the drilling

personnel from its drilling companies to the

training centre.

Entire drilling teams can train at once.

People in different roles, even at different

companies, can practise how they will work

together and drill (rehearse) their response

in specific disaster scenarios. Roles can in-

clude the driller, assistant driller, toolpusher,

company man, drilling supervisor and sub-

contractors.

You can train using a simulation of the

actual well to be drilled, including a simula-

Helping drillers get a better understanding ofwhat is happening below the rig - HelioSantos, founder of SafeKick

Drilling

digital energy journal - June 2011

tion of the topside equipment to be used,

drilling through the subsurface, using the oil

companies’ existing subsurface model.

An instructor can set up scenarios for

people to train on, where different things go

wrong, and people have to work out what to

do. For example, the instructor can introduce

a ‘weak zone’ for the drillers to drill through,

or a kick (rush of hydrocarbons into the

well).

The centre has so many bookings, the

company is planning to build another one in

Bergen.

Statoil tendered for a company to build

the system in early 2010 – before the Deep-

water Horizon disaster happened. Statoil

chose the system because it had the best

downhole model of all drilling systems eval-

uated, says Rolv Rommetveit, managing di-

rector of eDrilling Solutions.

The simulator can also be used to sup-

port real time drilling, comparing what is ac-

tually happening with the model of what

ought to be happening, to see if anything is

going wrong.

The company eDrilling Solutions was

formed 2 years ago, commercialising re-

search and development work from SINTEF

with the Integrated Drilling Simulator IDS

as the core technology.

SINTEF first started developing a

downhole drilling simulation model in 2004

working with ConocoPhillips and others.

eDrilling is 40 per cent owned by Nor-

wegian research organisation SINTEF, 40

per cent owned by Axon Energy Products,

and 20 per cent by others.

Before being managing director of

eDrilling Solutions, Rolv Rommetveit was

research director of SINTEF Petroleum Re-

search.

Downhole and topsidesThe simulator brings together separate sim-

ulator software components for downhole

and topsides.

The “Intellectus” downhole model can

model the downhole drilling process includ-

ing dynamic effects. It takes into account

factors such as temperature and pressure

changes downhole, drillbit and drillstring in-

ertia, acceleration and retardation.

You can see what the weight on bit and

rate of penetration is likely to be; and get an

idea about other things, including tripping

operations (analysing surge and swab); con-

nections; operations with different fluids;

how well your apparatus (mud, rig, choke,

well) can control wells; through tubing ro-

tary drilling; managed pressure drilling. “In-

tellectus” can be used by itself as a down-

hole well training simulator.

The “hiDRILL” software supplied by

Oiltec is a model of the topside – you can

model the drillers’ chair (with touch machine

interface); a 3D projection of the drill floor;

drill pipe handling, tripping operations; drill

floor operations; operating the BOP and

choke; mud handling; top drive; operating

the draw works; CCTV; alarm management.

“eDrilling” is a real time decision sup-

port system built over the simulators. It mod-

els the drilling processes in real time, so it

can diagnose the actual drilling state.

The real time data has an initial quality

check, then is fed into diagnostic model,

which can inform the user things like “you

have a problem with cuttings build up in the

annulus.”

It can gather data using any kind of da-

ta interface – including OPC and WITSML.

SINTEFSINTEF, which owns 40 per cent of

eDrilling, is Norway’s largest independent

R&D Institute with around 2100 employees

with international top level expertise in sci-

ence and technology.

SINTEF has developed the Integrated

Drilling Simulator IDS through JIP’s with

leading O&G operators. IDS forms the main

technological basis for eDrilling and is uti-

lized in the Intellectus training simulator.

Axon Energy ProductsAxon Energy Products, which owns 40 per

cent of eDrilling, is a company formed in

mid 2010, previously called Hitec Products

Drilling. It is majority owned by HitecVi-

sion, the largest venture capital company in

Norway.

It provides a range of oilfield equip-

ment, including coiled tubing units, control

systems, rig packages, drilling cabins, pump

units, as well as also selling simulator soft-

ware developed by Oiltec Solutions. Oiltec

has developed the “hiDRILL” software for

the topside rig equipment.

Axon offers rig design services and

well intervention products. The company has

around 200 people spread between Sta-

vanger and Houston.

"Looks real? No, it's a simulator!"

14

Drilling

June 2011 - digital energy journal 15

Do you think a piece of drillpipe is a stan-

dard item? It may have been in the past, but

in future we are more likely to see drillpipes

made specially for a drill project – with the

right balance of weight, resistance to sour

gas, and torque transfer, reckons Dirk Bis-

sel, managing director of VAM Drilling, the

drilling products division of Vallourec.

Drilling is getting increasingly chal-

lenging, Mr Bissel says, with projects such

as ultra deep wells, Arctic drilling, and devi-

ated wells. “Jobs are becoming more and

more difficult,” he says. “It all asks for more

and more complex drillpipes. That is basi-

cally the future.”

The idea of developing special steels

for a specific project “is the beginning of a

trend,” he said.

“We can really develop what the cus-

tomers want,” he says. “If they want some-

thing with higher torque and less weight, we

can do that”.

The torque is the amount of turning en-

ergy which is transformed from one piece of

suspended drillpipe to the one below it.

It helps that VAM Drilling is part of the

Vallourec Group, a century-old steel and tub-

ing company, which originated from the

merger of the French Vallourec and the Ger-

man Mannesmannröhren-Werke, where the

rolling process for seamless steel tubes was

invented.

Most suppliers of drillpipes purchase

their tubes from someone else, he says; VAM

Drilling is unique in that it makes the tubes

itself.

VAM Drilling has developed a range of

grades of steel which can be used for

drilling, including steel which is extra-resist-

ant to corrosion from sour gas.

BrazilThe company is opening a service office in

Brazil to serve its Brazilian clients, with the

first tubes to be manufactured mid 2011.

Parent company Vallourec has been mak-

ing tubes in Brazil since 1954. In Brazil, “We

have our own iron ore, steel furnaces, rolling

mills, heat treatment for tubes,” he says.

The plant has been opened there to bet-

ter serve local customers. “That’s our philos-

ophy, be close to our customer,” he says. “If

you are on a difficult job, you want your

toolmaker next to you.”

43,000 feet

A VAM drillpipe was recently used an off-

shore project in Brazil. The field featured

horizontal wells with short reach and extend-

ed reach wells with deviation spans of 3°-7°

DLS (Dogleg Severity) at angles of 30°-92°.

One wellbore in particular was drilled to

6489m MD (2429m TVD) with a vertical

section step-out of 5615m.

The drillpipe used connections which

maximise the amount of torque (turning

power) which is transferred from one length

of drillpipe to the length beneath it.

The company has developed a double

shoulder drillpipe connection, where the en-

ergy from the tube above is transferred to the

one below by 2 shoulders, which reduces the

amount of torque lost on each connection.

If you just use standard drillpipes, or

“API Connections,” so much torque is lost

with each connection, you reach a certain

length of drill pipe where using standard

connections is “nearly impossible,” he said.

“It was quite extensive research and de-

velopment work upfront [to develop the

drillpipe],” he said.

VAM Drilling – developing bespokedrillpipeVAM Drilling believes that in the future oil and gas companies will want drillpipes made bespoke fordifferent drilling projects – and the company is ready to provide it

Many drilling service companies are offer-

ing so-called PWD (“pressure while

drilling”) tools – but APS believes that its

pressure sensor has a much higher resolution

than others on the market, up to 0.1 per cent

accuracy – so +/- 20 psi when drilling at

20,000 psi pressure.

High resolution pressure information is

particularly useful when drilling through

narrow windows (eg narrow gap between

pressure which will cause a kick and pres-

sure which will damage a formation).

Also, if there is a change in pressure

downhole (for example because the drillbit

has penetrated a high pressure reservoir), the

driller gets immediate notification of it.

“You can make sure you don’t over-

pressure or under pressure,” says Brian

Stroehlein, marketing director / program

manager with APS Technology.

It can help you manage the ‘equivalent

circulation density’ (the density of the mud

combined with the cuttings being carried in

it).

PWD is different to logging while

drilling (LWD) and measuring while drilling

(MWD) in that it tells you about the health

and behaviour of our well – LWD and MWD

are more about measuring the rock forma-

tion around it.

The company is increasing the resolu-

tion further. “With the next generation of

tools we’ll get 0.02 per cent,” Mr Stroehlein

says.

The data can be sent to the surface in

real time by mud pulse or electromagnetic

telemetry, and it can also be written to local

memory for later analysis.

APS – high-res drilling pressure sensorAPS Technology of Wallingford, Connecticut has developed a high resolution, real-time pressure-while-drilling (PWD) sensors to be installed behind a drill bit

16

Drilling

digital energy journal - June 2011

malleable, which means it will slowly alter its

shape when downhole when under pressure,

thus maintaining a tight seal with the forma-

tion.

The material is supplied as a dry power

blend.

It includes a synthetic organic compound

which acts as a binder when it is in the pres-

ence of high temperature, high pressure, and

an activator chemical. It also contains xantham

gum suspension polymer.

The dry powder is mixed in either salty

water (brine) or drillwater.

Strengthening wellbores in depletedreservoirsIt is not easy drilling through a reservoir which is partly depleted, something you might have to do whendrilling infill wells on mature fields. Downhole Fluid Solutions of Aberdeen has developed a solution

It is not easy drilling through a depleted reser-

voir. Because the reservoir is at a lower pres-

sure, the rock fractures much more easily, and

you can lose drilling mud into the fractures –

and if you lose drilling mud, you can lose con-

trol of the well.

Downhole Fluid Solutions of Aberdeen

has developed a chemical solution to the prob-

lem called “Rockweld”- a fluid with solid ma-

terials in suspension which can be pumped

down the drill string, and then turn into a

strong solid material downhole.

The material is a little like tarmac in that

it is applied as a mixture of liquid and solid,

and ends up as a solid.

It works like this. When you start to en-

counter problems drilling (because you are

drilling through a low pressure reservoir and

getting lots of induced fractures), you pump

the Rockweld down the drillpipe and out of

the drill bit. 50 barrels of liquid Rockweld will

make 16.5 barrels of solid material.

You follow it by pumping 5-10 barrels

of a “hi-viscosity” pill – xanthan gum mixed

with water based drilling mud. No activator is

needed.

Then you increase pressure in the well,

which slowly forces the liquid out of the mix-

ture, leaving the solid behind, squeezed

against the reservoir rock as an aggregated,

compressed, fused together mass.

After an hour, the Rockweld will have

set hard enough to seal the fractures, and you

can test this by pressure testing the well. Then

you can continue drilling it. Next time you en-

counter fluid losses, you can repeat the

process.

When the reservoir is put into production

later, the production fluids will dissolve the

Rockweld as they flow from the

reservoir into the well, so long as

the production fluids contain

both oil and water (this is usually

the case for mature reservoirs).

Some components of Rock-

weld are soluble in water, some

components are soluble in oil, so

you need an oil / water mixture

to dissolve everything.

By using Rockweld in this

way, it fixes the problem (of dif-

ficulty drilling through fractured

rock) without damaging the for-

mation (blocking flow of produc-

tion fluids into the well).

Angus Lewis Smith, direc-

tor of Downhole Fluid Solutions,

spent 4 years developing Rock-

weld, starting in 2004. It was

patented in 2008.

The company has tested it

with 4 big companies, but has not

yet found a company agreeing to

test it in an actual well. “That’s

the big stumbling block,” he said.

“Nobody wants to be the first to

use it in a well.”

There have been companies

in the Middle East and China

showing interest in the material.

“They might be the first to use

it,” he said. “I’ve talked to many

oil companies and operators all around the

world who have expressed serious interest –

Europe, Africa, the Middle East, India,” he

said.

Rockweld materialWhen he started, oil companies told him that

the material would need to be non hazardous,

set very hard, work in a wide range of temper-

atures, be easily mixed and user friendly, be

mixable in normal mud pits. It must be able to

be stored pre-mixed at the surface indefinite-

ly, not have any risk of setting at the wrong

time (ie when it is in the drillpipe), and not

need specially trained personnel.

The “Rockweld” material Mr Lewis-

Smith developed can set in between 40 de-

grees C to 160 degrees C, and meets all these

requirements, he says.

Also, once set, it continues to be slightly

Watch a video talk about Downhole Fluid

Solutions at:

www.findingpetroleum.com/video/248.aspxRockweld as it ends up downhole: an

aggregated, compressed, fused together mass

Drilling

June 2011 - digital energy journal

X Drilling – open your valve infinite timesX Drilling Tools, a company based in Adelaide, Australia, has developed a special valve to let fluid flow intothe well bore but above the drillbit, which can open and close infinite times

The full technical name is “TAZ Multiple

Activation Circulation Sub”.

The valve can be used when drillers

want to increase drilling fluid flow over a

short term period, for example to wash a

build up of cuttings out of the well.

The valve is activated by dropping balls

down the drillpipe.

Where it is different from other valves

of this type is that it can be opened and

closed infinite times, because the ball is de-

signed to disintegrate after opening or clos-

ing the valve.

The ball has a hard outside and soft in-

side. The hard outside is designed to be

quickly eroded by fluid flowing past it (after

it has been activated) and the inner com-

pletely crumbles.

With normal ball activated valves, there

is a limit to the number of times it can be

opened and closed, due to a limited amount

of space inside the valve for used balls.

“You can only cycle 4 or 5 times then

you have to pull the whole drill string out of

the hole (18+ hours) or retrieve the ball with

a wireline (2 hours) ‘if’ everything goes

smoothly; which it seldom does,” says Mal-

colm Greener, managing director of X

Drilling Tools.

Even if you think you will only need to

open a valve 4 or 5 times, it still might be

worthwhile using the X Drilling valve, as

you often end up needing to open and close

it more times than that.

“It is insurance in a lot of cases,” Mr

Greener says; “but insurance that you can-

not afford to be without”.

Also, the system can make it feasible

to go for more challenging well designs,

which companies might otherwise be dis-

suaded from choosing because of the risk of

needing more changes to mud flow than a

conventional ball activated valve would al-

low.

The tool might also be used during cor-

ing operation, if you want to flush out the

well around the drillbit, but don’t want

drilling fluids to get into the core and con-

taminate it.

Extra additions of drilling fluid are

more likely to be required as the gradient of

the well becomes less vertical (ie horizontal

wells are more likely to need extra bursts of

drilling fluid).

The technology was developed at re-

search centres in Belgium and Australia.

Why you need ballsThe system is used when drillers want to

suddenly increase the flow of mud in the

well, for example if they want to bring up a

backlog of cuttings to the surface.

You can’t just simply pump mud into

the well at a higher flowrate, because a high-

er mud flow rate can damage components of

the drill string - so you have to find a way to

release the fluid through another outlet

above them.

To allow the fluid to flow out of the

nozzles, the valve must be opened. The most

effective means of communicating to the

valve is achieved by dropping balls down the

drill pipe, carried down by gravity and the

flow of drilling fluids.

When the ball reaches the X Drilling

Tools device, it activates a pressure switch

which opens three ports, which allow fluid

to flow out to the annulus. The size of the

nozzles is adjustable.

To stop the flow of drilling fluids, you

drop another identical ball down the drill

pipe, which de-activates the pressure switch.

Malcolm Greener, managing director of XDrilling Solutions

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Oct 20• Building the optimum supply

chain - Oct 25

17

Production

18 digital energy journal - June 2011

DHL – helping you manage supply chainsDHL, one of the world’s leading logistics providers, is aiming to grow its business in the oil and gasindustry managing supply chains for maintenance, repair, operations and overhaul materials

Logistics giant DHL believes that by having

a better supply chain for maintenance, repair

and operations (MRO), oil and gas compa-

nies can reduce their overall MRO costs by

20-25 per cent - partly by making engineer-

ing staff 15-20 per cent more productive.

This is a big deal when you estimate,

as DHL does, that 16 per cent of the final

cost of goods supplied by the energy indus-

try is spent on MRO.

DHL is currently working with a num-

ber of major oil companies to help them im-

prove their maintenance, repair and operations

supply chain. “It is showing exactly those lev-

els of improvement,” says Jonathan Shortis,

Vice President, Global Energy Development

for DHL Supply Chain, a chemical engineer

who previously worked at BP and ICI.

There are many more benefits to a bet-

ter managed supply chain, such as less con-

gestion of delivery traffic; ability to aggre-

gate procurement and negotiate better deals;

and reduced warehousing costs. Overall,

however, the greatest benefits come from re-

duced maintenance costs and increased pro-

duction.

With a better supply chain, you should

find that you are keeping less items in stock

from day to day (inventory) – but you’re ac-

tually more likely to have the items you need

in the stocks that you keep.

MRO has, let’s say, maybe not had too

much attention in the past from oil and gas

senior executives, who were more focussed

on the next new oil field.

But this is starting to change, as finan-

cial pressures force the industry to look hard-

er at all costs – and operations become more

complex, which means that inefficiencies in

the supply chain are more expensive.

Many maintenance, repair and opera-

tions (MRO) supply chains have a lot of

“firefighting”, ie people who suddenly find

they need a certain part and have to obtain it

as quickly as they can, usually at much in-

creased cost, Mr Shortis says.

Another indication of a poor supply

chain is when workers are spending a lot of

time hanging around waiting for parts to ar-

rive, or finding that they can’t do their in-

tended tasks because of the wrong parts,

while the building has several years supply

of other items. A problem many of us have

experienced when we try to have work done

on our house.

“I think there’s an opportunity for a

fundamental change in how maintenance is

undertaken,” he says. “It’s easy when you

know how. The problem is that there aren’t

many people who do know how.”

The solution, in short, is to be proac-

tive, to plan all maintenance tasks well in ad-

vance, to order materials against each job

and make sure they are there when the job

needs to be done. “That is a fundamental

change in the way you do business,” he says.

You won’t get rid of emergency (“hot-

shot”) deliveries entirely, but they will re-

duce to 5-7 per cent of all deliveries, not 50

per cent.

What DHL doesDHL will frequently undertake an initial sup-

ply chain assessment and quantify the value

which can be generated from supply chain

improvement and optimisation. This ap-

proach encourages businesses to move for-

ward to improve their supply chains because

they can see the real benefits which can be

delivered before any changes are made.

These benefits will typically come from re-

duced procurement cost, lower inventory

levels, increased material availability which

drive improved engineering team productiv-

ity and hence increased production and plant

‘up time’.

“We want to work with clients where

we can deliver value. If we do so, the client

is happy and we can work with that client

over a longer time-frame, driving even more

value,” Mr Shortis says.

For deliveries offshore, DHL does not

operate supply vessels, but it has related

services, including consolidation and ware-

housing operations, yard management oper-

ations. It also has supply chain services re-

lated to on-shore upstream exploration and

production, including managing rig moves.

DHL’s service go beyond freight for-

warding activity, and involve managing en-

tire, integrated end-to-end supply chains,

warehouses, inventory and consolidation fa-

cilities, managing customs for items sourced

internationally as well as international and

domestic transportation.

“DHL can say, we’ll take that problem

off your hands; we’ll improve cost to the

supply chain, and improve the way you

work. We do an initial assessment of the

client’s supply chain to get a real indication

of the value that we can create,” he says.

DHL founded a special energy division

in Autumn 2009 and has more than a billion

Euros of revenue from the energy industry

every year. “We are looking at [the energy

industry] as an area of real focus for us,” he

says.

DHL was founded in 1969 as the

world’s first air express company, taking

customs documents for sea freight by air be-

tween San Francisco and Hawaii (the letters

stand for the founders’ initials). Now it is

part of Deutsche Post (German post), the

world’s largest logistics group, which was

previously the German state owned mail

company privatised in 1995.

TrustAn important component of a good supply

chain is that people trust it, which means that

the information must be reliable. For exam-

ple engineers need to feel comfortable rely-

ing on the information the computer pro-

vides them about what is in the warehouse,

without having to go to the warehouse them-

selves to check.

Conversely, the lack of trust people

have in their current supply chains can lead

to people keeping ‘squirrel stores’ – secret

stashes of goods they often need.

Squirrel stores cause inefficiency for

the company in many ways. There is inven-

tory tied up in them, the corporate systems

do not know they exist, and there can be

Jonathan Shortis, Vice President, GlobalEnergy Development for DHL Supply Chain

Productionsafety issues associated with the use of un-

controlled materials in a safety critical envi-

ronment .

DHL recommends that the initial em-

phasis should be placed on working to put

better overall supply chain structures in

place rather than tackling the squirrel stores

head on.

“In my experience, chain, once you’ve

got a supply chain up and running, and once

the engineers see that it works, the require-

ment for squirrel store disappears,” he says.

You can tackle squirrel stores by trying

to encourage people to make their squirrel

stores visible. “You can have an amnesty,

and say, if you’ve got material, bring it out,

we’ll re-credit it into stock and use it for the

greater good - it becomes visible.”

“Frequently that might take 12 months,

it might take 18 months, for an engineer to

say, I don’t need those stores anymore.”

“It’s more of a partnership approach –

members of our team sitting down with the

engineers and going through this list of stock

and asking which of this material is re-

quired,” he says.

“On day one you’re not going to go in

there and rip out 40 per cent of someone’s

stock. It’s a matter of them reducing over

time, working together using a simple risk-

benefits analysis.”

“If someone has say 124 4-inch gaskets

[stored locally], and the system says you on-

ly need 5, you don’t just make the change in

one go, you reduce it over time. This grad-

ual reduction is done in partnership with the

plant team.”

SoftwareYou need to have a good software solution

to manage a supply chain, but above all you

need management systems to back it up.

“Companies look at Enterprise Re-

source Planning (ERP) systems as a panacea,

thinking it will solve every problem that they

have,” he says. “But as with all things, sys-

tems solutions are only as good as the

processes and procedures that come before

them.”

“You need visibility and traceability to

make this work and work well. It’s more

about getting the systems right and using the

IT tools to deliver that.”

You should also integrate IT systems

with your logistics service provider, so both

groups can see what material is needed and

where it currently is in the supply chain.

The ERP software needs to fully under-

stand which spare parts and supplies will be

needed to perform specific maintenance

tasks, so supply chain managers can make

sure that those parts are available when the

job is about to be done.

Consolidation centreOne recommendation DHL makes is that

companies should set up a goods consolida-

tion centre away from the main plant, where

all deliveries should initially be made to.

Then you have very simple deliveries

from the consolidation centre to the plant, in

smaller vehicles, perhaps only a few ‘milk

round’ deliveries per day at a regular time.

In other words you just have one supply

chain managing all of the material move-

ments to the plant itself.

If you have many different suppliers

delivering directly to the plant, you can have

lots of congestion. The site is probably not

so convenient for many large trucks all ar-

riving at the same time, and you never know

exactly when they will arrive. “It’s really dif-

ficult to co-ordinate the movement of tools,

engineers and materials,” he says.

Vendors and the soft stuffTechnology vendors need to be good at the ‘soft stuff’ – making sure people are comfortable using theirsoftware – or risk finding out in a year’s time that their software is not being used, writes Dutch Holland

Many digital oilfield technical vendors seem

to describe the world in which they work as

“the hard stuff” and “the soft stuff.”

To them, hard stuff seems to mean con-

crete elements, numbers, equations, code -

real stuff to sink one’s teeth into.

Soft stuff seems to mean all the people-

related stuff, messy, fuzzy stuff such as per-

sonality, motivations, training - as in psy-

chology.

Technology vendors say they special-

ize in the hard stuff and frequently want

nothing to do with any soft stuff.

But the DOF reality is that “getting the

hard stuff right” is not enough to get busi-

ness value for the customer.

Somebody has to “get the soft stuff

right” or the customer will have nothing

more than unused technology that works

great … technical success but business fail-

ure.

The technologist’s dilemma is whether

to sell good technical stuff and hope the cus-

tomer puts it to good use for business value,

or to jump in (into the soft stuff) and help

ensure the customer gets that value.

If the vendor leaves good technical

product by the door and the customer cannot

get the technology into play, the vendor faces

an almost certain “no” when he shows up a

year later to sell the next version of technol-

ogy.

If the vendor has pitched in and helped

the customer “take it all the way to the

bank,” the vendor can expect more business

over the long haul from a satisfied customer.

Unfortunately, most technical vendors

seem to have made up their minds; they are

going to sell good technical stuff and hope

the customer can put it to good use.

For the few vendors willing to throw

their lot in with customers and to help take

the technology “all the way to the bank,”

there will be great business opportunities

with their customers.

Knowledgeable vendorsDespite a vendor’s level of digital expertise,

an industry threshold must be crossed before

vendors can have “real conversations” with

Technology vendors often fail to focus onpeople aspects of things - they win the sale byconcentrating on the 'hard stuff', but if youdon't help people to use it then good luckrenewing your contract next year, says DutchHolland of Holland Management Consulting

19June 2011 - digital energy journal

Production

20 digital energy journal - June 2011

their operating customers.

While the customer may spend some

time talking to a vendor, there will be no re-

al business conversation unless technical

vendors have boots on the ground who know

and have experience with the physics of the

oil patch; know, have experience, and be

able to perform modeling and simulation on

upstream assets; and know and understand

the customer’s comprehensive map of core

processes.

Few technical vendors seem to have

understood this message since they continue

to approach customers with marketing, sales,

and services representatives who do not even

come close to meeting industry threshold re-

quirements for true conversation and part-

nership.

Clarifying client requirementsImagine the lead technologist in a customer

oil and gas company making the statement

below.

“My [internal technical] organization

thoroughly understands the leverage points

in our operations’ work processes where dig-

ital technology can add business value.

“We’ve worked both inside our shop

and outside with our vendor community to

nail down the technologies and tools that

we’ll need to bring to operations to meet

their specific business goals.

Let me read a letter I just received from

our primary DOF technical vendor. ‘Thank

you for selecting our company to be your

lead DOF technology provider. Your specif-

ic explanation of your needs and goals will

allow us to meet your technical needs now

and in the future.’”

Simple, right? Those are indeed the

magic words for DOF maximization.

But, it’s easier said than done … since

many customer operating organizations con-

tinue to have trouble articulating their com-

pany’s specific technology needs.

Failure to specify needed technologies

is but one of many challenges a technical

vendor must overcome to be of real service

to an operating company.

Mirroring organization structuresThe vendor’s organisation should “mirror

and mesh” with the business value architec-

ture of its customer.

While the obvious “touch point” be-

tween the technical vendor’s organization

and its customer is “Vendor operations” to

“Customer technical processes,” the vendor

organization must be able to mirror the cus-

tomer at the strategic and customers’ opera-

tions level as well.

The Customer Technical Processes

needed to maximize DOF business value are:

Business Needs Discernment that ac-

curately comprehends the range of opera-

tional transactions and decisions that could

be made by the business.

Technology Architecture Design that

optimizes the company’s technical capabili-

ty to support all types of work processes

needed by the business to meet its goals

Technology Acquisition that both

drives vendor innovation and secures need-

ed technologies to support architecture de-

sign.

Systems Readiness process in place

that can produce apps and systems that meet

Business Improvement Opportunity require-

ments.

Proven and secure implementation

Process is in place that does not put opera-

tions at risk during technology implementa-

tion and test.

For there to be an effective mirroring

or matching between customer and vendor,

vendor architecture must directly support

(i.e., assist, inform, lead) each of the cus-

tomer’s technical Processes.

Vendor Business and Technical Needs

Discernment that accurately comprehends

the range of operational transactions and de-

cisions that could be made by the business.

And the level of understanding of those

needs by the customer’s technical organiza-

tion (i.e., the vendor’s technical customer).

The vendor must be able to converse with

the customer’s operational organization and

“backstop” the customer’s technical organi-

zation to ensure there is good understanding

and translation of Business Improvement

Opportunities.

Vendor Technology Architecture De-

sign Support to lead/assist customer to an ar-

chitecture that optimizes the company’s

technical capability to support all types of

work processes. Assistance in technology ar-

chitecture design is no longer an option but

a requirement for DOF vendors.

Vendor Technology Preparation and/or

Innovation of vendor offerings that accurate-

ly responds to the customer's requests for

technology functionality. It is critical for cus-

tomer and vendor alike that the vendor’s ca-

pability for technical innovation be har-

nessed to support the customer. While some

existing vendor products may “fit” the cus-

tomer’s need, the ultimate value of DOF may

be driven by innovation to meet specific cus-

tomer needs.

Vendor Alignment with the customer’s

Systems Readiness Process enabling the cus-

tomer to produce apps and systems that meet

Business Improvement Opportunity require-

ments. Vendors who can help the customer

use their own internal readiness processes to

get products ready are both value and in

short supply.

Vendor Alignment with and support of

the customer’s implementation process, a

planned bullet-proof implementation that

does not put operations at risk. Technical

communities have for decades had the repu-

tation of being highly focused on the attrib-

utes of their products while being “missing

in action” during technical implementation.

This can no longer be the case.

Innovative technical vendors are essen-

tial to the health and vitality of the DOF

movement. But, those vendors who can mir-

ror their customers’ organizations and pro-

vide leadership to the customer to take tech-

nical DOF innovations “all the way to the

bank” will be prized as future partners of the

more successful operating companies.

More informationThis is the fifth article in a five-part series

that defines and explores the ways an up-

stream organization would need to be re-

configured to fully adopt the use of digi-

tal technology to improve the business.

This last article in the series “goes outside

of an operating organization” that wants

to maximize DOF technologies for busi-

ness value to the vendor community that

supplies digital technology and services.

This article speaks to the way a technical

DOF vendor might need to position its

own architecture so that it can better serve

its DOF customers.

Contact Dutch Holland:

dutch@hollandmanagementcoaching.com

Tel: +1 281-657-3366

www.hollandmanagementcoaching.com/digitaloilfield

To get your technology used, you'll need toget good at the soft stuff

Production

22 digital energy journal - June 2011

Fibre optics to listen to your wellsStandard fibre optic cables can be used as an acoustic sensor without any discreet components along thelength of the fibre. This can be useful in oil and gas wells, for example if you want to know at which pointoil, gas, water or sand is entering your well, says Doug Gibson, CEO of Fotech Solutions

Fibre optic cable is very clever stuff. If a ca-

ble is excited by a sound wave, some of the

light travelling through the fibre experiences a

phase change which when analysed in real-

time by Fotech’s Helios system outputs

acoustic information reproducing the original

sound wave. This information is available for

every metre along a fibre optic cable for dis-

tances greater than 50Km.

“If I were to lay a fibre between central

London and Heathrow airport, and you walked

to Heathrow airport, I could follow you to the

airport and position you to 1 metre accuracy,”

said Fotech CEO Doug Gibson, speaking at

the March 16 Finding Petroleum London fo-

rum. “You can have the equivalent of micro-

phones every metre along the fibre.”

So if you have fibre installed inside your

wells, you can find out a lot of useful infor-

mation and enhance your understanding of

your well’s performance. This is the only tool

that will give you a top to toe real-time view

of your well’s dynamics.

For example, one client installed fibre in

a tight gas well with 9 fractured zones. The

client thought that the rock was homogenous

and production would come from all 9 zones.

But the fibre optics could only hear noise from

two of the zones and from the bend in the

pipeline (caused by vibration in the tubing) –

suggesting that production was only coming

from 2 of the 9 zones. Although the fibre was

not all the way into the well, careful analysis

of the acoustic data helped us interpret that

statement (See illustration top right.)

“A well which the oil company thought

would produce all the way along the wellbore,

is actually only producing from this one area

here in zone 7 and potentially a small amount

in zone 9,” says Doug Gibson, CEO of Fotech

Solutions, a company developing the technol-

ogy.

“This is just by listening to the fibre that

has been installed either temporarily or per-

manently in the well.”

You can also get a much better under-

standing of what happens when a well is shut

in.

In one example, after shutting a well in,

a client could see the water column in the well

gradually falling down the well, but mean-

while still see gas continuing to rise up

through the well.

When the well was brought up to pro-

duction again, you could see water coming out

of one of the zones, and

faster gas starting to slug out

of the zone It takes a while

for production he zones to

come back but meanwhile

you can pinpoint the produc-

ing layer within the zone.

Another client had a

problem with sand produc-

tion in a well, but didn’t

know which point in the well

the sand was entering. The

fibre optics can be used to

show where the sand was en-

tering. Although unable to

show the data publicly,

Fotech were able to show to

a metre accuracy, where the sand was break-

ing through the sand screen, allowing the oil

company to rework the well and shut off the

sand.

In another example, with a well with un-

cemented casing above a certain point, you

can see leaks of fluid coming into the well at

the casing interface. “We’re showing them

there’s a leak in their casing system,” he said.

“You can see movement which has nev-

er been seen as far as I know by any other tech-

nology,” he said.

“I think you’ll see that here is a technol-

ogy that allows you to do an awful lot more to

understand the dynamics within the wellbore

and in real-time.”

“You can listen to different things going

on in the well, you can listen to leaks, flow,

moving sleeves, valves, pumps, microfractur-

ing, microseismic, etc.”

The system could help make fracturing

much more efficient. If people know which

fractured zones are producing and which ones

aren’t, they can see which zones to focus on

in future. “The cost of fraccing is tremendous-

ly high,” he said. “We can tell the client in his

quest to understand what’s worth producing

and what’s not.”

The system could also be used in carbon

dioxide storage, if you want to see which

zones of your reservoir the gas is going into.

You can also track the flow of gas through the

rest of the pipeline for leaks, turbulence and

friction.

It is possible that in the future the system

could be used to analyse 3 phase flow but this

will take time and a lot of research I suspect.

“It’s in its early days – we hope to come

back soon with a lot more case histories to

show you.”

The system can also be used for other ap-

plications, including security, or following

things (you could have fibre laid along a road,

and follow a car along a road from the noise it

made).

The system uses standard fibre optic ca-

ble, but some very clever processing at the sur-

face. It can provide data to 1m accuracy, along

a distance of 50km.

All of the electronics are at the surface.

Fibre is installed in production wells us-

ing wireline, or with a hard carbon rod or per-

manently on tubing or outside casing. “The fi-

bre is just simple fibre – it costs nothing when

compared to current downhole sensors,” he

says. “The cost you’ll come up against is the

cost of installing this into the well.”

The technology was originally devel-

oped by researchers at Imperial College and

later Surrey Technology, who started a spin-

off company in 2008. Fotech shareholders in-

clude Scottish Energy Partners, Energy Ven-

tures and Shoaibi Group (Saudi Arabia).

In the market, “I think the general opin-

ion is bemusement at the moment, nobody can

quite believe what it can do,” Mr Gibson said.

The reality is this is the first technology that

can produce a real time continuous view of the

entire well allowing a ”video” of the well per-

formance and the ability to change production

parameters and watch the effect.

The fibre optic in the well shows that a lot of the noise is comingfrom zones 7 and 9 - which suggests that most of theproduction fluids are entering via these zones

See Doug Gibson's talk on video at

www.findingpetroleum.com/video/245.aspx

Production

June 2011 - digital energy journal 23

Robotic tools for effective well interventions

Welltec develops small robotic devices that

can perform a variety of well intervention

and maintenance tasks on wireline. They are

lowered into the well through the production

tubing to the required location in the well.

This is a much easier, cheaper and safer

way to do well interventions than other

methods, such as running intervention tools

on coiled tubing, or doing workovers.

Mr Hallundbæk founded the company

in 1994, after completing his masters’ thesis

on equipment for horizontal well drilling.

The company won a sponsorship from Sta-

toil to find ways to help the company im-

prove recovery rates in the early 1990s.

But when he first introduced the tech-

nology, there was a lot of industry resistance

to it, and “nothing has actually changed

since,” he said, speaking at the March 16

Finding Petroleum London forum, “New

technologies for mature fields.”

Statoil was using heavy equipment to

do interventions at the time, and was keen to

reduce the number of people working in dan-

gerous situations. Now Statoil is mainly us-

ing Welltec’s robotic technology for inter-

ventions, he says.

The company estimates that 90-95 per

cent of all well workover work can be done

on a wireline like this, with big savings in

both safety and cost.

“You don’t compromise on safety, you

have triple safety barriers in place and you

have the ability to abandon at any point in

time,” he says.

“All the heavy equipment has disap-

peared and you’re left with a lean, effective

and comprehensive package.”

The wireline cable is about as thick as

someone’s little finger and the robot con-

sumes the same amount of electricity as a

hairdryer.

“But with this power we compete with

a semisubmersible,” he said.

Benefits of interventionsRegular interventions can do a lot to keep a

well running smoothly. “If you produce an

oil well for more than 3 years, you end up

with having scale, sand, water problems, gas

and corrosion,” Mr Hallundbæk says. “These

are issues that have to do with the conduit to

the surface, not the reservoir as such.”

With wireline interventions being so

much less expensive, they are much easier

to commission. Statoil has ended up doing 3

times more in-

terventions in

total than was

done before.

“That’s a dra-

matic change

within the last

10 years,” he

said.

Mr Hal-

lundbæk sug-

gests that an in-

tervention can

be carried out

every 18

months on all

wells. “The

idea is that the

process is fine-

tuned over the

lifespan of the

reservoir,” he

said.

By keep-

ing the well bet-

ter managed,

you reduce the

amount of water being produced, and there

are many further advantages to this – such

as scale in the production facilities.

You don’t have problems with hydro-

gen sulphide carried up in the produced wa-

ter. “A lot of oil companies have redesigned

all of their piping to surface because they

had H2S issues because of produced water,”

he said.

“Here the idea is to keep the water in

the reservoir.”

If there is no water, then it is much eas-

ier for oil to flow to surface – you need less

pumping / artificial lift.

“If you have a solid water production

of 90 per cent you’re consuming a lot of en-

ergy in your system just to pump it around,”

he said. “So of course there’s a lot of energy

savings in this philosophy.”

“When you look at subsea wells, a lot

of them have been a major disappointment,

they produce for 2 years then they die out,”

he said.

If you have to “sit there with your cal-

culator and say, should we bring in a semi-

submersible (and do an intervention) or drill

a new well (requiring 6 x return on capital),”

you can find that you need $200m of addi-

tional revenue to justify it. “So of course

you’ll stay away from intervening.”

“But here, we change the cost picture

completely. You remove the guys on deck of

the semisubmersible, the riser system, you

don’t need helicopter support, it’s just a ves-

sel. In the Gulf of Mexico it is just a supply

boat”, he said.

What you can doMost of the work is actually removing scale

from downhole safety valves. “Downhole

safety valves have to work so of course scale

issues have to be fixed,” he said.

The tools have also been used to mill

away scale on a live reservoir and open and

close valves.

Welltec’s suit of robotic tools are also

used for doing routine well jobs, such as

reperforating (moving the production zone),

setting plugs and straddle packers to men-

tion but a few.

They can also be used in shale gas to

do cement assurance, to make sure the gas

and fracturing fluids are not able to contam-

inate ground water.

An important development is the abili-

ty to do an intervention on subsea wells,

without needing a riser going from the well

to the surface.

Welltec’s robotic wireline tools compete with technology which requires rigs such as semisubmersibles or jackups to do well interventions – but the industry is not yet completely convinced, says CEO Jørgen Hallundbæk

Which would you rather use for well interventions, a semisubmersible (top)or a robotic tool (bottom)?

Production

24 digital energy journal - June 2011

Tools can be lowered from a dynami-

cally positioned vessel onto the subsea

Christmas tree, and is able to enter the well

and go down the production tubing without

even stopping production.

This has been done at depths of 900m,

just dropping the tool through the ocean on

a wireline. It is known as “Riserless light-

weight well intervention.”

“It’s a bit like a keyhole operation,” Mr

Hallundbæk says. “You are not changing any

pressures in the system; you are utilising nat-

ural flow in the wells.”

“This is all possible on wireline,” he

said. “These are the type of issues we solve.”

Forget “smart” wellsWelltec suggests that the tools enable a com-

pletely different philosophy in how wells are

designed and completed.

Instead of completing a well with as

many valves and equipment and associated

electronics as you think you might need over

the well’s lifetime, you can complete it very

simply, and make changes later using robot-

ic tools like these.

To not have to plan things in advance

is very helpful, because at the outset, you

don’t know what is going to happen. “As

time progresses, the knowledge base will in-

crease,” Mr Hallundbæk explained. “You

can make a facts based decision if you have

enough facts in place. You have a better

chance to pull out the last drops of the reser-

voir.”

“Our philosophy is to put the smartness

in the robots, instead of putting the smart-

ness in the hardware,” he said.

“When the hardware first is in the

ground then it’s difficult to change or replace

it.”

“You can start with a single well de-

sign, and add multilaterals later. You can

change it from being a producer to an injec-

tor.”

“If you have a lower capital expendi-

ture upfront, your return on investment be-

comes much higher,” he said.

One way to reduce the risk of lightning strikes on helicopters is to try to keep them away from air at zerodegrees, reckons Duncan Trapp of CHC Helicopter Services

Research has shown that lightning strikes on

helicopters are more likely when the outside

temperature is exactly zero degrees, says

Duncan Trapp, vice president of safety and

quality at CHC Helicopter Services, the

largest operator of offshore helicopters in the

North Sea.

Helicopter lightning strikes are caused

when a helicopter generates a negative

charge while airborne, and flies through an

area of positively charged cloud. Melting ice

is believed to contribute to the separation of

positive and negative charges.

“Lightning strikes are still a rare oc-

currence but it is a threat faced by all of those

who operate helicopters in the North Sea

where the atmospheric conditions create ide-

al circumstances for strikes to occur, partic-

ularly in the winter months,” says Mr Trapp.

“Almost every winter, between Octo-

ber and May, North Sea helicopter operators

experience an increased number of incidents

thought to be triggered by the presence of

their aircraft in certain climatic conditions.”

“Before the helicopter gets to that par-

ticular point in space there is no lightning ac-

tivity and therefore even the most advanced

detection systems currently available cannot

warn us to avoid it,” he says.

CHC tries to work out which altitude

band air temperatures are likely to be within

-2°C and +2°C and avoiding that band, he

says.

Helicopter fuel systems are designed to

prevent potential electrical arcing and spark-

ing brought on by direct or swept lightning

strikes. The effects of lightning strikes

against indirect ignition sources, such as fu-

el tank wiring, are also covered in the design

phase.

The regulations require that flight-criti-

cal and essential systems, equipment and

functions be designed and installed in such a

way that they can continue to perform their

intended functions under any foreseeable op-

erating condition.

If there is ever a suspected strike, the

helicopter is subject to a comprehensive in-

spection to check everything is working as it

should be. “The default position is that any

component that is believed to have been af-

fected by a lightning strike, no matter how

minor, gets replaced,” he says.

“At the moment trials are even being

carried out on fixed-wing aircraft looking at

a special type of paint which minimises the

effect of a strike.”

Helicopter lightning: avoid zero degrees

Reducing the risk of helicopter lightning strikes: Duncan Trapp, VP safety and quality, CHCHelicopter Services

Watch Jørgen Hallundbæk's talk on video

at:

www.findingpetroleum.com/video/244.aspx

Production

June 2011 - digital energy journal 25

Amrtur Corporation Sdn Bhd (for Brunei)

and Special Oilfield Services Co LLC (SOS)

for Oman.

It is looking for distributors for

Malaysia, Thailand, India, and the US and is

prioritising territories where Gas Lift is an

established production method.

Camcon: control gas injection downhole

UK company Camcon Oil has developed a

gas lift tool called “Apollo” which can regu-

late the flow of injection gas downhole and

enables changes without intervention, the

first time this has been possible, the compa-

ny believes.

Gas injection is regularly used to help

oil production – gas is injected into the pro-

duction fluid as it enters the well, because an

oil / gas mixture is less dense than just oil.

This makes it easier for the surrounding for-

mation fluid pressure to push the production

fluid up to the surface.

The injection gas is pumped from the

surface to the bottom of the well through the

annulus (gap) between the inner production

tubing (where fluids go up) and the outer

casing.

Usually the downhole gas valves

(where fluid passes from the annulus into the

production tubing) are passive – ie they can-

not be opened and closed and are set before

being fitted. They can only be adjusted us-

ing wireline tools, an expensive and complex

process.

But with Camcon’s gas lift tool, the

flow of gas into the production tubing can

be adjusted electronically, with controls

from the surface.

It is useful to be able to adjust the flow

of gas downhole, so you can make much

more precise and faster adjustments, as you

try to optimise the production rate using the

minimum amount of injection gas.

The Camcon gas lift tool has six sepa-

rate valves(ports) of different sizes, which

can be opened and closed, to regulate the

flow of gas into the well.

To open and close the ports, Camcon

has developed a special low powered actua-

tor, with a gate which can flip from one po-

sition to another, using springs and changes

in a magnetic field.

Moving the gate between positions this

way takes much less energy than doing it

with an electric motor. It is like with two bal-

anced children on a see-saw – moving the

see-saw up and down does not take a lot of

energy.

The gas lift tool has sensors at the point

of gas injection, and temperature and pres-

sure readings are re-

layed to the surface in

real time.

An undisclosed

oil major is already

using the solution ex-

tensively, the compa-

ny says, and the sys-

tem will be trialled in

Brunei. The company

is also doing trials in

Oman with Petroleum

Development Oman

(PDO) starting June

2011.

All of the de-

ployments so far have

been onshore, but

there are plans to de-

ploy it offshore short-

ly.

The power sup-

ply and control sys-

tems are sent down a

single 3 core cable

clamped to the pro-

duction tubing.

It can operate at

up to 125 degrees C,

or 85 degrees C con-

tinuous temperature.

The product has a de-

sign life of 6 years.

The gas lift tool

is being supplied to

the market place on

an “OEM” (original

equipment manufac-

turer) basis, which

means that other com-

panies can sell it as

their own.

The company

has distribution

agreements with Al

Mansouri Group (for

most of the Gulf

States, Oman, Abu

Dhabi and Kuwait);

Camcon is helping oil and gas companies regulate gas lift downhole

Camcon’s APOLLO digital artificial liftsolution

Production

26 digital energy journal - June 2011

Modelling flow through blow outpreventersSince the Macondo disaster, more companies have been turning to SPT’s Olga flow simulator, to helpmodel flow through blow out preventers

After the Macondo disaster, oil

companies have started using

flow modelling software to

model flow through blow out

preventers – to work out what

would happen in the worst case

scenario (open flow from the

reservoir to the earth’s surface)

and what kind of flows would be

required in the other direction to

stop it (the famous ‘kill’).

Trondheim flow simulation

software company SPT reports

that many companies have asked

to use its Olga software for this.

SPT has developed a “blow

out control module” which engi-

neers can use to model the worst

that might happen. “You can see

how bad would it be,” says

Agnes Scott, senior account

manager Americas, with SPT

Group.

The Olga Advanced

Blowout Control module can be

used to analyse possible blowout

rates, kill rates in different sce-

narios (ie through the drillstring,

through relief wells), required

pumping duration and volumes,

and pressure loads at all well po-

sitions.

It can be used in planning,

training, supporting actual operations, post

analysis, reporting, comparing different op-

tions.

So you can work out, that in the event

you have to do a kill, what you will need in

terms of casing design, mud flowrates /

densities / volumes, operational sequences,

using relief wells, equipment, pump rating,

temperature conditions.

In training you can use it to assist in

workshops where you discuss different sce-

narios, show people what might happen in

different scenarios.

Fluids aren’t meant to flow through

blow out preventers (except through a

drillpipe or production casing), and until

Macondo happened people did not expect

that they ever would. Now of course things

have changed.

Normally, flow simulation software is

used for modelling flow through pipes – for

example to predict if hydrates / waxes and

slugs are likely to occur on a certain design,

predicting corrosion levels, and planning

chemical inhibitors.

The Olga software has been under de-

velopment for 30 years, and there are 50 de-

velopers in Norway working full time to de-

velop it, mainly educated to Phd level in

multiphase flow or thermodynamics. SPT

claims it is the best multiphase flow simu-

lator in the world. It can be used both for

planning / design and to support real time

operations.

CO2 modelling is another area where

there is a growing interest in flow assurance

software. SPT Group has just started a

"joint industry project" for CO2 modeling

together with 6 industry partners to provide

anchor sponsorship for the research.Agnes Scott, senior account managerAmericas, with SPT Group

Comparing the kill rates with a bit on the bottom and a drillstring partly out of the hole, using SPT's Olgablow out control module flow simulator

Communications

June 2011 - digital energy journal

Harris acquires Schlumberger’s satcomdivisionHarris Corporation has acquired Schlumberger’s “GCS” satcom division. Along with its acquisition ofCapRock Communications last year, it probably becomes the oil and gas industry’s largest satcom provider

Harris Corporation of Florida has acquired

the “Global Connectivity Services” (GCS)

VSAT satellite communications business of

Schlumberger Information Solutions for

$397.5 million in cash.

Schlumberger GCS has 400 employees

in over 25 countries, and 12 teleports, as well

as Very Small Aperture Terminal (VSAT)

manufacturing capabilities in the U.K. and

Singapore. It has customers in over 50 coun-

tries.

The deal follows Harris’ acquisition of

oil and gas satcom company CapRock Com-

munications in May 2010 for $525m, and a

March 2011 acquisition of “infrastructure as-

sets” of telecom network integrator Core180.

The combined company will go under the

name “Harris CapRock Communications”.

By putting the three companies togeth-

er, Harris CapRock Communications is

probably the world’s largest oil and gas sat-

com provider, with over 1,400 employees,

teleports on 6 continents and 6 x 24/7 net-

work operations centres. The company owns

the majority of teleports which it uses.

Following the acquisition, Harris

claims to be the largest buyer of satellite

bandwidth in the world, outside the US gov-

ernment. This gives it more purchasing pow-

er to invest in satellite bandwidth.

“We have the largest global infrastruc-

ture serving the oil and gas market in terms

of the number of teleports we operate, the

number of global service centres that are out

there,” says Ron Wagnon, VP and General

Manager, North America, Harris CapRock.

“We’re within the top 5 providers globally.”

The company operates 5 gigahertz of

satellite capacity over 60 different satellites.

The company has reached the point

where it could provide all satellite connec-

tivity for an oil major under a single global

contract.

To smoothen the acquisition, Harris has

a “dedication team” to set up best practises

when integrating the companies. The team

aims to determine what an ideal company

would look like and what processes it would

have, and then works out the best way to

achieve it. “They are not taking two compa-

nies and slashing them together. We have the

luxury of designing a brand new company

from the ground up,” he said.

About Harris

Harris is a communications equipment com-

pany based in Florida, which supplies wire-

less equipment, electronic systems and satel-

lite antennas for government (including de-

fence) and commercial sectors.

It has over 16,000 employees and rev-

enues of over $6bn. The company is listed

in the U.S. General Services Administration

top 100 contractors report as the 32nd largest

contractor to the US government, with

$2.1bn annual business.

The company is listed in the U.S. Gen-

eral Services Administration top 100 con-

tractors report as the 32nd largest contractor

to the US government, with $2.1bn annual

business.

Harris has a range of services it has de-

veloped for the US government, including

satellite communications services, antennas,

radio units, IT security services, IT services,

data hosting, broadcast.

Bigger is betterIn the satcom industry, bigger is better, if it

makes it easier to provide a global service

and support, says Mr Wagnon.

“It gives us more assets and more peo-

ple spread around globally,to provide better

services.”

Many oil and gas companies do busi-

ness with regional VSAT companies, or a

company which has satellite transponder

covering the specific region they are operat-

ing in – so they have to renegotiate their

satellite service and maybe install new

equipment to communicate with different

satellites if they need to move a rig.

“Every area we go there’s a small re-

gional player that provides the same type of

service but they’re limited to the region,” he

says.

But by going to a global provider like

Harris CapRock it is easier for oil companies

can move a rig from one region to the next

without having to set up a new contract and

terminate the previous one.

“Some of these large drilling compa-

nies, large service companies, want a one

stop shop.”

Companies are moving rigs more fre-

quently than they used to, he says, and this

means the ability to easily switch to a differ-

ent satellite becomes more important. “We

absolutely see a trend with rigs moving into

remote areas, and rigs bouncing from region

to region,” he says.

Complex satcom demandsCompanies’ demands for satcom are getting

much more complex all the time.

“If you go back 18 years – the person-

nel on the rig were self sufficient. They

looked for a voice capability to talk to some-

Harris CapRock: probably the world's largest satcom provider, following its acquisition ofSchlumberger's GCS satcom division

27

Communications

28 digital energy journal - June 2011

one on the beach,” he says.

“Today there’s a much bigger depend-

ency on remote collaboration.

That connectivity is becoming more

important.”

“Companies are increasingly keen to

spend money on providing crew communi-

cations to improve crew morale.”

Demand for data is continuing to grow.

“With rigs moving into deepwater, the deep-

water complicates the drilling process, re-

quires them to run more advanced applica-

tions, and causes them to put more people

onboard those vessels,” he says.

There is a growing interest in splitting

up bandwidth – for example, if a company

wants to reserve part of it for business com-

munications and part of it for crew commu-

nications, or sell a segment of it to visiting

service providers.

Portable VSATThere is an increasing demand for portable

VSAT satellite communications. “If a serv-

ice company shows up on a rig, they some-

times want to bring their own satcom system

onboard, and get it running very quickly,” he

says.

Companies also want portable VSAT

services to install on vessels, where they

don’t need a permanent VSAT installation.

“They might not be able to afford providing

satellite communication on all their vessels,

but they need a few units to move around.”

There is also a trend for some oil com-

panies to require that the supply vessels they

charter have satellite connectivity, so com-

panies want a portable VSAT communica-

tions device when they work with those oil

companies.

Companies are increasingly shifting

from Inmarsat communications to VSAT for

communications from smaller vessels, he

says.

“I think today, the advantage of VSAT

over Inmarsat is that it’s a bulk rate type

price. You pay one rate and you get a fixed

amount of connectivity,” he says. “For com-

panies that have high usage needs – it can

pay off.”

“These companies have got multiple

people on the boat, they need to send real

time data from the vessel. The usage patterns

get to where to they can cost justify VSAT.”

“We do sell Inmarsat – kind of as a

back-up service,” he says.

Making portable VSAT is not easy, he

said. “The challenge is getting a package

that’s small and portable enough to be able

to do that. It can’t be a laptop type.”

Typical packagesTypical communications packages which

drilling companies contract for are always

on 0.5 kbps over a 0.6m antenna, and always

on 1 to 1.5mbps over a 1m antenna.

“A lot of drilling companies out there

have less than 512kbps, on the low end its

256kbps,” he says.

However many operators have in-

creased their data speeds from around 1.5

mbps to 2-3 mbps over the past 2 years.

Existing satcom systems can handle

much more data but it gets expensive. “You

can do 10 mbps if a company wants to pay

for it. We’re not seeing links like that,” he

says.

Ron Wagnon, VP and general manager NorthAmerica, Harris CapRock

Since operating procedures of the two

industries are not always compatible, this has

the effect of reducing the perceived risk on

both sides.

It has a secondary benefit of increasing

the number of potential suppliers for the fi-

bre communications service. Without the

subsea connection point, only those few com-

mercial installers willing to address the risks

and complications of installing a riser cable

can be considered as potential suppliers.

With the subsea connection point, a

communication services provider such as a

regional telecom operator or a specialized

oilfield communications services provider

can more easily provide services.

Connect to subseaIn many cases, a long distance communica-

tions cable can be connected to a subsea um-

bilical (an existing sheath of cables running

down to subsea equipment).

This means that the need for a new riser

cable and cable ship operations close to the

platform are avoided.

The umbilical can be installed using

proven techniques by installers experienced

in oil and gas field work.

The hardest part of an offshore fibre optic in-

stallation comes with the final connection on-

to a platform.

Only a small handful of firms have

demonstrated the combination of capabilities

needed to work with the telecommunications

technology while satisfying the needs of the

oil and gas industry.

But if you have a subsea fibre connec-

tor, the system is separated into two parts –

the long distance fibre cable, which can be

installed by the communications industry,

and the connection up to the platform, which

can be installed by the oil and gas industry.

Fibre installations – build a subseaconnection pointBy building a subsea connection point, installing fibre optics to offshore platforms might be easier –because very few companies have both telecoms and oil and gas expertise, writes Stephen Lentz of WFNStrategies

Communications

June 2011 - digital energy journal 29

The disadvantage of this approach is

that the signal attenuation associated with the

subsea connector may complicate the overall

communications system design and the con-

nector represents a potential failure point.

New offshore installationsFor offshore installations still in the

planning stages, the opportunity exists to pro-

vision and install a communications fibre as

part of the platform commissioning.

Similar to a gas export platform, the

communications fibres are installed and ter-

minated a few kilometres from the platform.

A cable termination module with sub-

sea connectors can be installed on the plat-

form, or a permanent end-seal left on the

seabed for later recovery.

If subsea connectors are used, the cable-

laying vessel will deploy a connectorized as-

sembly and perform the ROV operations to

connect the fibres.

Alternatively, the cable-laying vessel

can recover the cable end and perform a

jointing (splicing) operation.

All work is performed at a safe distance

from the platform so that the connection to

shore can be completed without impacting

platform operations.

The availability of a pre-installed riser

greatly simplifies the job of the cable in-

staller.

Deepsea cablesThe fibre cable and transmission technology

are readily available from multiple suppliers.

Subsea fibre optic cable installation is a

well-established industry that traces its roots

to the first telegraph cables installed over 150

years ago. Much of the technology used to

install a cable across the Atlantic or Pacific

Ocean can be readily adapted for connection

to offshore oil and gas platforms.

Specialized cable installation vessels

outfitted with cable tanks, cable engines,

clean rooms for fibre optic splicing, power

feed equipment, test gear, bow thrusters, and

dynamic positioning capabilities are owned

and operated both by major suppliers and

systems integrators.

CostThe costs to bring optical fibre to an offshore

platform can quickly run to tens of millions

of dollars. Installing a deep-water riser can

cost three million dollars or more.

At the lower end of the scale, platforms

in less than 300m of water can often be

quickly connected using standard cable. Ca-

ble and installation range from $30K to

$100K per kilometre depending on depth and

seabed conditions.

Mobilization, shore stations, landings,

transmission electronics, project manage-

ment costs, and permits add to the cost.

Pipeline and cable crossings also incur addi-

tional cost. Terrestrial data links are needed

to connect the landing site to operations cen-

tres or corporate offices.

A communications system built for sev-

eral platforms will share the cost of the back-

bone cable, landings, and mobilization

among those platforms.

Fibre trendsIn just the last few years, some significant

milestones have been achieved with offshore

fibre.

BP’s Gulf of Mexico system was com-

pleted, connecting seven deep-water plat-

forms to a 1200km backbone cable. This sys-

tem now provides direct communications

from each platform to BP’s Houston offices

with less than 20ms latency.

Fibre has become essential for North

Sea operators. The combination of CNSFTC,

North Sea Com and Tampnet have covered

the North Sea with fibre, with over a dozen

major platforms connected by fibre and many

more supported by radio links which connect

to the fibre network.

Planning for fibre communications to

West Africa’s offshore industry has moved

past the concept stage, and fibre is showing

up in a few other locations around the world.

Many further fibre projects remain confiden-

tial.

Offshore expectationsPeople working offshore are beginning to ex-

pect the same network performance and ca-

pabilities that are available onshore. Support

personnel onshore expect their offshore

counterparts to access the same network and

data resources.

A host of applications and needs are

driving an increasing demand for offshore

bandwidth. Not only is raw bandwidth a re-

quirement, but also low and predictable la-

tency as well as high availability are needed

to support these applications.

Video collaboration can operate with as

little as 2Mb/s, but performs best with low

latency links; some video services become

difficult or impossible to use over satellite.

The performance of office LAN func-

tions including e-mail, software updates, re-

mote access and workflow management is

greatly improved when bandwidth of 20Mb/s

or more is available.

Streaming video for entertainment and

crew welfare will use as much bandwidth as

can be delivered.

High definition video collaboration re-

quires 6Mb/s or more.

Control data and production moni-

toring can utilize 10Mb/s or more

Reservoir Management and Simula-

tion can utilize 30 Mb/s or more

Permanent Seismic Systems utilize 30

to 100Mb/s

Taken together, the desirable bandwidth

for an offshore installation can quickly reach

50Mb/s, 100Mb/s or more. Planning for fu-

ture needs has led some operators to equip

1Gb/s and establish a growth path to 10Gb/s

per platform.

Yet operators are often content with 1-

2Mb/s satellite links or microwave systems

offering 50Mb/s or less.

Stephen Lentz of WFN Strategies

Stephen Lentz has over twenty years ex-

perience in the construction and operation

of optical communications networks in-

cluding metropolitan area networks, na-

tional networks, and international subma-

rine cable networks.

He has served as VP Network Engi-

neering and Deployment for 360networks'

submarine division where he developed

the network architecture, functional re-

quirements, and performance specifica-

tions for international submarine cable

networks and supervised testing, commis-

sioning, and verification of compliance

with contractual requirements.

He was Manager of Transmission

Engineering for Time Telekom, Sdn. Bhd.

located in Kuala Lumpur Malaysia, and

Director of Systems Engineering for

Lightwave Spectrum, Inc. He joined

WFN Strategies in 2005 as Network De-

sign Manager, and has supported telecom

projects in Antarctica, Oklahoma, Gulf of

Mexico and West Africa. In 2011, he was

promoted to Director of Engineering.

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