March 2009 Issue 17

Exploration:- searching for oil withsupercomputers - a new way to grid thesubsurface

Fracturing:- using tiltmeters andmicroseismics tomonitor your frac

™

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Production:- when your IT department gets in the way- wi-fi in North American oilfields

Vision for Energy

> Strategic consulting

> Seismic imaging

> Velocity analysis

> Structural interpretation

> Stratigraphic delineation

> Formation evaluation

> Reservoir modeling

> Pore pressure prediction

> Well planning and drilling

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Contents

Reducing risk in new exploration through modellingSMT has launched a new software module, called 1D Forward Modelling (1DFM®), which enablesgeoscientists to use data from existing wells when doing seismic interpretation

WesternGeco’s land seismic systemWesternGeco has launched UniQ, a new integrated land seismic system whichcan record up to150,000 live channels at a 2 millisecond sample interval

Big improvements in gravity survey technologyBig improvements in gravity survey technology means that it is being used to determine thebest prospects to drill, not just to get a quick overview of the potential of a region

JewelSuite – high definition modelling of the subsurfaceNetherlands oil and gas software company JOA has developed a tool which, it claims, make itmuch easier to model the subsurface, because (unlike on traditional subsurface modellingtools) there is no need to try to make the grid blocks align with faults

EarthStudy 360™– Detailed Seismic Analysis at Subsurface Image PointsParadigm has created a new method of imaging and analyzing seismic data – with emphasison extracting detailed images and information from geologic targets and their associatedlocal reflecting surfaces

Visualising everything at onceDynamic Graphics has developed a tool which can visualise multiple datasets from an oil fieldsimultaneously in 3D and 4D – from an overall view of the basin to a view of the individual wellsand reservoirs – and you can see how it changed over time as well. It can be used by everyoneassociated with a project

Disk data storage for seismic - $1000 per terabyteLandmark offers incentive for operators to finally give up tape with a new online, disk-basedstorage system for technical data

Making hard drives tough enoughData storage company EScon Ltd was asked to develop a hard drive data storage systemtough enough to use on seismic vessels

March 2009 Issue 17

March 2009 - digital energy journal

Digital Energy Journal is a magazine for oil and

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Monitoring fractures with tiltmeters and microseismicsHalliburton has boosted its well stimulation and optimisation service through its recentacquisition of Pinnacle Technologies, the leading and most experienced provider of real timetiltmeter and microseismic mapping and reservoir monitoring services

Using the best drilling sensorsJames Burks, product line manager with National Oilwell Varco´s M/D Totco division, believesthat his company´s drilling rig sensors are better than others on the market

Fitting digital energy around your IT departmentYour IT department can often be at cross purposes with your digital energy strategy, says DrDutch Holland. Here are some ideas how to resolve the problem 21

Drilling, completions and production

13

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1

Front cover:UsingDynamicGraphicssoftware todisplay wells,productionand reservoirinformationin the sameimage. Seepage 12.

5

LeaderRepsol’s Kaleidoscope Project – finding oil under salt using microchipsSpanish oil and gas company Repsol has developed a supercomputer, using the microchipsoriginally developed for the Sony Playstation, to help look for oil and gas beneath salt in theGulf of Mexico and Brazil

3

12

Exploration data

9

15

7

18

Schlumberger – Wireless and WiMAX communications in North AmericanoilfieldsThrough an exclusive agreement with ERF Wireless, Schlumberger is offering 1.5Mbps wirelessdata communications for oilfields in North America, which will eventually be available forentire basins

Communications

6

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14

Spanish oil and gas company Repsol has put

together a supercomputer – with the help of

microchips developed for the Sony Playsta-

tion – which is looking for oil and gas be-

neath salt domes in the Gulf of Mexico and

Brazil, among other places.

The computer has a processing power

of 120 teraflops - equivalent to 600 Playsta-

tion 3s, or 10,000 Pentium 4 PCs.

The Kaleidoscope supercomputer is

analysing the seismic data using the Reverse

Time Migration (RTM) algorithm, which

needs more than one order of magnitude in

computing power than coeval algorithms,

according to Repsol’s director of geophysics

Francisco Ortigosa.

The results of the data processing have

already been put to good use. “We already

have prospects that will be drilled this year

as a result of the supercomputing,” Mr Or-

tigosa says.

"We hope there will be a lot more oil

discoveries because of the Kaleidoscope

project – this is why we’re making all this

effort," he says. "We are really on the living

edge. We are going very much beyond what

anybody imagined before.”

RTM techniques have been known

about for a long time, but could not be used

due to the cost of the computing power need-

ed to run them. “The chief impediment to the

large-scale, routine deployment of RTM has

been a lack of sufficient computer power,”

he says.

It has always been possible to put to-

gether an enormous computer by linking to-

gether PCs, but (until now) the limitation has

been the enormous electricity consumption

it would have.

"Anyone could get a petaflop by link-

ing lots of computers together, but it would

need so much power, it’s not really feasible,"

he says. "It would need megawatts of pow-

er.”

But Repsol’s supercomputer with the

new microchips covers just 8 racks, cover-

ing 21 square feet of floor space; the power

consumption is 750 watts per square foot

(15.7 Kw in total).

The RTM seismic algorithm is good for

understanding complex fractures from 3D

seismic data, and understanding seismic da-

ta for reservoirs beneath salt. It also provides

data which can be used to make better cal-

culations of other parameters such as pore

pressure. In future, it will also be used to

make a better removal of statics (noise) from

land seismic data.

The algorithms needed to be re-coded

to run on the new chip, also to ensure that

the amount of computing power needed to

run them was minimised. Mr Ortigosa calls

this 'lean computing'.

The Kaleidoscope project began in

2006, following the launch on the market of

both IBM PowerXCell 8i processors and

new Linux PC technology, in 2005.

Full data processing work began in No-

vember 2008; and Repsol already has jobs

lined up for 2009 which will keep the com-

puter occupied for the whole year.

CollaborationThe Kaleidoscope project brings together the

expertise of a number of different companies

and organisations.

The supercomputer itself is operated in

Houston by a company called CyrusOne,

which runs a large data centre and supercom-

puters for other companies.

The project team includes Houston

seismic imaging company FusionGeo

(formed by the Nov 3 2008 merger between

Fusion Geophysical LLC and 3DGeo, a

company founded by Stanford University

professor Biondo Biondi), and the Barcelona

Supercomputer Center (BSC), which also

hosts Europe’s third largest computer,

MareNostrum.

The original research was made with

3D Geo, together with Stanford University’s

Stanford Exploration Project (SEP), an in-

dustry funded academic consortium aiming

to improve the earth structures that can be

constructed from seismic data.

The original development and testing

of the code was carried out on the Mare Nos-

trum supercomputer in Barcelona, the 9th

largest supercomputer in the world, which is

located inside a former chapel and has a peak

performance of 94.21 teraflops.

"The Kaleidoscope project brings to-

gether oil companies, service companies,

and computing companies," Mr Ortigosa

says. "If we want to innovate – first of all we

need diversity.”

It was also important that none of the

companies in the group were competitors in

any way, which would have impeded free

communication between them, he says.

Seismic algorithmsUnderstanding a reservoir beneath salt using

seismic is very complex because you can’t

"We already have projects that will be drilledthis year as a result of supercomputing" -Repsol’s director of geophysics FranciscoOrtigosa

Spanish oil and gas company Repsol has developed a supercomputer, using the microchips originallydeveloped for the Sony Playstation, to help look for oil and gas beneath salt in the Gulf of Mexico andBrazil.

Repsol’s Kaleidoscope Project – findingoil under salt using new microchips

Leader

Repsol's Kaleidoscope Supercomputer atCyrus One (Image courtesy of CyrusOne)

digital energy journal - March 20092

Leadersend a seismic ray through the middle of the

salt – you have to bounce it around the edge

of the salt to get it into the oil reservoir and

out again.

It’s a bit like doing a complex shot in

snooker when you have to bounce the white

ball around a pack of red balls to reach the

black.

Just like for snooker balls, sending seis-

mic rays around complex paths is possible,

but much, much more difficult.

Normal seismic algorithms (the means

of understanding the path a seismic ray has

taken from the ray which emerges at the sur-

face) are fine for a ray which just goes down,

hits a reflector which is roughly horizontal

and bounces up to the surface again.

But these algorithms don’t work well if

they are hitting a reflector which has an an-

gle of more than 60 degrees from the hori-

zontal.

So a new seismic algorithm has been

developed called Reverse Time Migration

(RTM). Simply put, RTM is about modelling

the seismic wave both forwards and back-

wards - you model how you think the seis-

mic wave has travelled from the source into

the subsurface, you model how you think the

seismic wave have travelled from the sub-

surface back to the surface, and then use

computer modelling techniques to work out

what the wave might have done in the sub-

surface.

MicrochipThe processor (microchip) being used is the

same one included in the Playstation 3,

called 'Cell' and designed by IBM, with the

help of Sony and Toshiba. "This chip is ful-

filling all the requirements," Mr Ortigosa

says.

Each cell has 8 synergistic processing

elements (SPEs). For a chip to be able to do

the require amount of processing, it needed

to be a multicore processor, which could do

many calculations at once. “It’s impossible

for any single chip to reach this amount of

power,” he says.

Another chip will be released in 2 years

time with 32 SPEs on it - so it can do four

times the processing, Mr Ortigosa says. "In-

stead of having 120 teraflops we will have

half a petaflop."

The cell chip uses Linux programming,

and all normal Linux tools can be used with

it.

The computer code needed to be rewrit-

ten for the new chips. “It is very difficult to

port codes which are written for Intel or

AND chips and import them into Cell,” he

says. “Although it is easier to port codes

written for Power PC computing.

The Stena Drillmax is the drillship Repsol usesto drill possible oil locations identified withKaleidoscope's imaging technology.

Reducing risk in new explorationthrough modellingSMT has launched a new software module, called 1D Forward Modelling (1DFM®), which enablesgeoscientists to use data from existing wells when doing seismic interpretation.

SMT has launched a new software module,

called 1D Forward Modelling, which enables

geoscientists to use data from existing wells

when doing seismic interpretation.

A major assumption behind 1D Forward

Modelling (1DFM) is that rock properties

generally change only in small ways across

short distances (eg 100m scale).

So, when trying to understand the sub-

surface of a new region, you are probably bet-

ter off starting with the known properties of a

neighbouring region (ie the well you have al-

ready drilled) and making small adjustments

to it, until you have synthetic seismic data that

closely matches the actual seismic data

recorded in the new region you are looking

at.

For example, you might have an idea

that the rock properties in the area of interest

are very similar to the rock in a well that has

already been drilled – but that reservoir is

filled with water instead of oil.

You can create synthetic seismic of the

well you have already drilled, with all prop-

erties the same (except for the reservoir you

Changes in sonic or density porosities are modeled using Wyllie’s time averaging equation anda simple volumetric average of the densities. Users can vary the mineral content and themixture of fluids in the pore spaces

March 2009 - digital energy journal 3

4

Exploration data

digital energy journal - March 2009

paring the synthetic seismic with the actual

seismic, and try to get your model closer to

what is actually observed through a number

of iterations.

It is called ‘1D Forward Modelling’ be-

cause you are starting with one (1) dimension-

al data (log data in one wellbore) and create

other possible geologic models from that data.

The software is being sold as a module

extension to KINGDOM, SMT’s flagship in-

terpretation software.

The first company to recently purchase

1D Forward Modeling is Seismic Ventures, a

Texas based seismic data processing compa-

ny.

Seismic Micro Technology (SMT)

claims to be the global market share leader

for Windows based geoscientific interpreta-

tion tools. The company’s KINGDOM soft-

ware suite can be used for a full range of dif-

ferent geophysical and geological interpreta-

tion tasks, all running from the same database.

are looking at, which is changed from oil

filled to water filled) so you can test this idea.

Or alternatively, you can make small

changes to the rock properties in the well, de-

velop synthetic seismic, and then go through

your seismic data of the whole region to see

if the seismic data for any point matches your

synthetic seismic – which might suggest that

the rock properties at that point match the re-

vised rock properties of your well.

Using SMT’s 1DFM, the process can be

carried out iteratively – make small tweaks to

the model and create new synthetic seismic,

and then build up an idea of the subsurface of

the new region which gets better and better.

The tool is particularly good for trying

to understand seismic AVO (amplitude vs off-

set) responses; you can develop synthetic

seismic based on your model, and compare

that to the actual AVO data recorded in the

field.

Properties which typically might be al-

tered include the Poisson ratio (ratio of rock

strains in different directions); porosities;

pressure and shear wave sound velocity; hy-

drocarbon/water ratio in the rock (based on

Gassmann’s equations).

You can also see what happens if rock

properties from one layer are repeated in an-

other rock layer at another level (by cutting

and pasting log data from one depth to anoth-

er), which reveals if the thickness of a rock

layer changes.

The input data you need from the well

includes compressional (P) and shear (S)

wave sonic data, and rock density data.

The software will draw a synthetic seis-

mogram with a normal offset (what you

would get if the sound wave went vertically

down and up).

“We take the new seismic survey and

match that to the synthetic – and hopefully

there’s a nice perfect match,” says Mike

Paine, lead product manager for 1D Forward

Modelling at SMT.

“Otherwise, I go back and edit the data

values for these three well logs until I can cre-

ate synthetics that match the real seismic field

data.”

“I can say – I have tight sand at the well

– what would porous sand look like? - and

then make synthetic seismic,” he says.

Using 1DFM, geoscientists can also get

a feel of the sensitivity of the geology to the

seismic data (how much the seismic data

would change if the rock properties were to

change) – and hence an idea of how accurate

the estimations of rock property are likely to

be.

Ultimately you can eliminate possibili-

ties, or work out a range, within which the

right answer must lie.

You can keep tweaking the model, com-

Reliable shear velocities are imperative for the calculation of offset traces to be used for AVOmodeling. If a dipole (shear wave sonic) log is not available then the shear velocities must bederived from a normal sonic log or a log that can be converted to a usable sonic log. 1DForward Modeling accomplishes this by a simple workflow as illustrated in the above screenshot.

Fluid substitutions provide a valuable tool for modeling various fluid scenarios that mightexplain an observed amplitude variation with offset. The technique of substitution used here isthrough the application of the low-frequency Gassmann equations. As shown in the dialogboxes, users can vary the mineral composition, fluid mixture, as well as the specific physical andchemical components of the fluid.

accepted in the industry. Most [of our cus-

tomers] are on their 2nd or 3rd survey,” says

Dr. Davies.

High resolution data that can be acquired at

low cost, andwhen mounted in a plane, can

fly over difficult terrain that would hinder oth-

er exploration, means Gravity Gradiometry is

becoming a useful tool for independents and

majors alike.

6

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digital energy journal - March 2009

Big improvements in gravity surveytechnologyBig improvements in gravity survey technology means that it is being used to determine the bestprospects to drill, not just to get a quick overview of the potential of a region.

Gravity surveys are an essential part of explo-

rationist’s tool kit. Being able to measure the

gravitation signal from the earth helps deter-

mine the rock’s density and thereby creating

a picture of the subsurface geology. But con-

ventional airborne gravity surveys have their

limitations, says industry specialist ARKeX.

With low signal bandwidth and a low signal

to noise ratio, conventional gravity surveys

are good at mapping geology on a regional or

basin scale, but not down to prospect (poten-

tial drilling target) level.

ARKeX is utilizing a new technology

called Gravity Gradiometry to obtain ultra

high resolution data with a high bandwidth

and a high signal to noise ratio. The resulting

information is then used to map the geology

down to prospect level and show features that

would be invisible to conventional gravity

surveys.

One of the problems with conventional

airborne gravity surveys is that it is very dif-

ficult to correct for the acceleration of the

aeroplane in the gravity reading. A conven-

tional gravity surveying device (explained

simply) is a weight hanging on a spring – the

greater the gravitational pull, the more the

string stretches. The sensor needs to be very

sensitive to detect the precise changes in grav-

ity, which indicates the density of the rock be-

neath.

Unfortunately, acceleration of the plane

in different directions will also impact how

much the spring is stretching. In order to cor-

rect for that, you need to know how much,

and in which direction, the plane is accelerat-

ing. This is done using GPS (global position-

ing satellite) but it is not a precise correction

so the final data contains a lot of ‘noise’ and a

lot of the detail is lost.

Gravity Gradiometry, by contrast, does-

n’t measure gravity, but the gravity gradient.

That is the rate of change of gravity over a

unit distance. Again, explained simply, it uses

two separate weights on two separate springs,

one above the other. They move in time with

the aeroplane (or ship) so any acceleration ex-

perienced by the weights is common to both.

If however, there is a change in gravity (due

to a rock structure beneath), the distance be-

tween the weights will change and this is what

is measured. This is the gravity gradient. Be-

cause gravity gradiometry can record minute

gravitational changes, it can map structural

rock density in such high resolution, features

that conventional gravity shows as noise can

be seen as distinct features.

Gravity gradiometry technology will

shortly be improved even further, with a new

device called the EGG (Exploration Gravity

Gradiometer), which uses superconductivity.

This will be even more sensitive and be able

to map an even wider range of geologies.

“It’s phenomenally sensitive,” says Dr.

Mark Davies, Chief Scientist with ARKeX,

one of the leading companies in the field.

“The EGG will be able to measure rock struc-

tures with small density contrasts, which

would be impossible with today’s technolo-

gy.”

Gravity Gradiometry has already been

used extensively in North America, Africa

and the Middle East. In these areas it has

proved to be extremely useful across many

exploration settings. In a mountainous Thrust

Belt region of Muskwa Kechikia, British Co-

lumbia (notoriously difficult and expensive to

survey with seismic technology), gravity gra-

diometry successful showed why a Major oil

company drilled a dry well in the region and

where the main structure could have been

found. It has also been used to map salt bod-

ies in West Africa, again extremely difficult

using seismic.

“The technology is starting to become

Gravity gradiometry has become"phenomenally sensitive" - Dr. Mark Davies,Chief Scientist with ARKeX

The mountainous region of Muskwa Kechikia, British Columbia, Canada. It would be very hardto do a normal land seismic survey here - doing a gravity survey from an aeroplane is anattractive option

7

Exploration data

March 2009 - digital energy journal

JewelSuite – high definitionmodelling of the subsurfaceNetherlands oil and gas software company JOA has developed a toolwhich, it claims, make it much easier to model the subsurface,because (unlike on traditional subsurface modelling tools) there is noneed to try to make the grid blocks align with faults.

Most subsurface modelling

techniques divide the subsur-

face up into a number of cells

by aligning pillars with fault

planes. This is known as pil-

lar gridding and has been

around now for some 10

years.

However on the JOA

software, all of the pillars

(vertical lines) can be ab-

solutely vertical. No smooth-

ing or simplifications of

shape are required to be made

to the model, to make it fit to

a grid. The company claims

that it is the most "accurate

geological software tool

available in the market."

With the JOA software,

the grid is orthogonal - it

doesn't matter if the fault or unconformity

surfaces are complexly arranged. “The pil-

lars always remain vertical in the Jewel Suite

model – in effect it is like putting a cookie

cutter though the sub surface,” says Jonathan

Jenkins from JOA.

On the JOA system, there is no need to

fit whole cells around corners; this is differ-

ent to most traditional gridding software,

where users often change diagonal fault lines

into stair steps to fit in cells. “This unneces-

sarily reduces the fidelity of the simulation

model,” he says.

Models can be built much more quickly

with the JOA system, the company claims. In

one case, "we took a model someone took 6

months to build in other software and rebuilt

it in 5 days and we kept the faults geologi-

cally accurate,” says Mr Jenkins.

The JOA models can also be updated

much more easily. “If you decide a fault

should be in a different place, you can update

the model with a single operation,” says Mr

Jenkins.

Normal gridding software can be fine

for relatively simple fields, but the JOA soft-

ware should prove particularly useful in com-

plex faults with many faults, Mr Jenkins says.

The JOA software is available at, the

company promises, half the price of a simi-

larly configured Petrel licence from Schlum-

berger.

The tool can be used on its own or eas-

ily integrated into other software such as

SMT’s Kingdom Suite. “It is completely

scalable: we have built huge comprehensive

models for some of the biggest oil and gas

fields of the world,” he says.

Problems with traditional griddingUsers of traditional pillar gridding tech-

niques can have a lot of problems when try-

ing to create grids around faults, as figure 2

illustrates.

When dealing with complex fault

geometries, you can end up with squashed

cells that are harmful to the stability of sim-

ulator calculations and require extensive

manual clean-up.

“We are often surprised by the ingenu-

ity and tenacity of modellers building rather

complex models with frankly, inferior tools,”

he says. “ It is a very tedious process how-

ever, and once you feel the power of an or-

thogonal grid and the integrated solutions

around it, most never want to go back.”

Often assumptions or fudges are made

to try to make the pillars fit around the faults.

Sometimes, as a remedy, pillars are on-

ly lined up with one fault accepting that pil-

Figure 1 illustrates how the same data looks like with atraditional pillar grid program (above) and with the JOAsoftware Jewel Suite (below).

8

Exploration data

digital energy journal - March 2009

The JewelGrid can connect to a wide

range of subsurface simulation techniques,

for instance finite element models used to

analyse and predict movements as triggered

by the production of oil and gas.

JOA has recently demonstrated at a big

industry exhibition a JewelSuite set-up that

combines high-performance cluster hard-

ware with smart software solutions, reduc-

ing the simulation time for field-wide Geo-

mechanics by orders of magnitude.

lars are ‘travelling” along the other fault

plane - Fig 2. Example (b); this way one suc-

ceeds in capturing geometry in pillar grids

but it becomes nearly impossible to calcu-

late reliable flow properties between cells on

either side of the fault.

These twin issues are responsible for

too many sub surface having faults ‘verti-

calised’ – something done 20 years ago and

nowadays unacceptable to modelling small-

er and more complex reservoirs.

“Modellers are a clever bunch and to

reduce months of mindless editing, they will

sometimes not model the faults interpreted

on seismic,” says Mr Jenkins.

“The other trick is to create ‘pancake’

geocellular models. By making models real-

ly thin one can avoid geometry problems,”

he says.

“This approach barely covers single

reservoir units,” Mr Jenkins continues. “It

ignores stacked reservoirs, deeper layers and

About JOA

JOA is based in Delft, Netherlands, and

provides support from offices in Houston,

Moscow, Jakarta, Aberdeen and Sta-

vanger.

The reservoir engineering solutions

are built in Albuquerque (New Mexico)

where all new code is also exhaustively

tested.

The company was founded in 1999,

originally building bespoke software for

Shell. See www.jewelsuite.com

the overburden. So what about flow of hy-

drocarbons or water between different reser-

voirs? Or what of the potential of modelling

the full field? With so many approximations

accuracy is lost or too roughly measured, this

is unacceptable.”

Connecting to simulatorsSimplifying your finished grid model, so you

can use it in reservoir simulators, is easily

done, as figure 3 (below) indicates.

Figure 3- It is fairly easy to simplify your detailed geological model (left) to a simpler model youcan use for reservoir simulation (right).

Figure 2 - modelling complex fault geometries can lead to squashed cells that need manualclean-up

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9

Exploration data

March 2009 - digital energy journal

EarthStudy 360™– Detailed Seismic Analysisat Subsurface Image Points

Oil and gas software company Paradigm

has launched a new offering to assist geo-

scientists in analyzing the subsurface mak-

ing use of the seismic method. The offering

is being made available to a select group of

oil companies seeking to optimize their re-

turn on investment from a general class of

seismic acquisitions that are characterized

by the richness of their azimuth recordings.

Branded as Paradigm EarthStudy

360™, the collective solution incorporates

software and people with a strategic serv-

ice element designed to allow participating

oil companies to generate and interpret de-

tailed images of the subsurface that reveal

continuous surfaces, small and large-scale

discontinuities, illumination directions, and

subsurface reflectivity data that can be used

to understand reservoir properties and

reservoir heterogeneity.

The new system is designed for appli-

cation to both legacy and modern seismic

acquisitions that sample the subsurface

more fully in azimuth. Legacy acquisitions

include many onshore 3D seismic acquisi-

tions, while modern seismic acquisitions in-

clude the rich and dense onshore seismic

acquisitions and the wide azimuth acquisi-

tions carried out in offshore environments

to illuminate data beneath highly irregular

structures like salt bodies. The new system

is also ideal for application to ocean bottom

recorded seismic data.

What is unique about EarthStudy 360

is that it decomposes and images the seis-

mic data into full and continuous azimuthal

data sampled locally at subsurface reflect-

ing surfaces. This decomposition and

preservation of “in-situ” azimuthal data,

contrasts strongly with traditional seismic

imaging procedures that average (sum) da-

ta over the azimuth component, compro-

mising seismic resolution and often elimi-

nating useful information contained in the

directional data.

“The decomposition of subsurface

seismic data into full azimuth data is car-

ried out with a rich, bottom-up, exploding

diffractor ray tracing procedure that sam-

ples the data in all angles and all directions,

without imposing assumptions about the

orientation of subsurface reflectors,” says

Duane Dopkin, senior vice president of

technology with Paradigm. “Carrying out

this rich ray tracing with billions of rays at

selected image points within oil company

project time frames, is what makes this ex-

citing technology both innovative and prac-

tical.”

EarthStudy 360 was first launched at

the annual SEG exhibition in Las Vegas, in

November of 2008. Like the transition

from 2D to 3D data, the transition from sin-

gle or limited azimuth data to full azimuth

data requires more than one product to take

advantage of the implementation. Earth-

Study 360 is not a point product solution;

rather a “system of technologies that

process, image, characterize, and interpret

full azimuth-data” says Mr. Dopkin.

Benefits of ApplicationEarthStudy 360 has application to a broad

range of exploration and development im-

aging problems that can benefit from full

azimuth decomposition and imaging. It is

engineered for application to full volume

imaging, target-oriented imaging, and even

imaging along planned or actual well paths.

EarthStudy 360 was designed to ad-

dress a broad range of exploration and de-

velopment objectives that can exploit the

full benefit of directional seismic acquisi-

tion and imaging.

It is ideally suited for wide azimuth

acquisitions that seek an improved illumi-

nation beneath complex structures such as

basalt sheets and salt structures that distort

seismic images.

It is also ideally suited for understand-

ing the orientation and density of fractures

that serve as permeability conduits in frac-

tured shales or carbonates. The system has

special AVAA (amplitude versus angle ver-

sus azimuth) methods to specifically en-

hance the signatures of these fractures.

EarthStudy 360 can also be applied to

mature fields where reservoir compartmen-

talization is often subtle and difficult to de-

tect. Here EarthStudy 360’s capacity to de-

tect local differences in seismic amplitude

and waveform can have a significant impact

on the drilling program.

It is also applicable to the exploration

and development of unconventional hydro-

carbons, such as heavy oils, that are con-

fined to the shallow subsurface. Here,

EarthStudy’s capacity to sample the near

subsurface with high angles can have a

huge benefit in these heavy oil plays.

Preserving the Azimuth Attempts to preserve useful information

contained in azimuthal data with traditional

imaging procedures usually involve parti-

tioning of the input acquisition data into a

limited number of “surface” azimuth sec-

tors and then processing, imaging, and in-

terpreting the sectors independently.

Although this procedure has been ap-

Paradigm has created a new method of imaging and analyzing seismic data – with emphasis onextracting detailed images and information from geologic targets and their associated local reflectingsurfaces.

10

Exploration data

plied with limited success, it still averages

azimuth data over the range of the sector

and, more importantly, this sectoring is

based on surface orientation (azimuth)

rather than the in-situ orientation of the lo-

cal geology and the local reflecting surface.

Additionally, the sectoring approach creates

a burden for geoscientists that have to deal

with the practicalities of dealing with mul-

tiple datasets.

EarthStudy 360’s rich ray tracing pro-

cedure enables the decomposition of seis-

mic data into two types of full azimuth data

gathers – directional and reflection. No sec-

toring of the input data is required. By na-

ture of their full azimuth, both types of da-

ta gathers carry full 3D representations of

data, potentially sampled at every grid

point. More importantly, geoscientists not

only have new data types to analyze, but

have fundamentally new ways to interact

with the full seismic wavefield.

View all directionsImagine being able to lower a camera into

the subsurface of the earth and record a

continuous animation that captures the sur-

roundings in all directions and all angles.

By combining (or mapping) a rich bot-

tom-up ray tracing procedure with the fully

recorded seismic wavefield, EarthStudy

360 simulates this procedure and creates a

wealth of seismic reflection (acoustic am-

plitude) and directional (dip and azimuth)

data that can be selectively sampled, cre-

atively combined, dynamically visualized,

and further processed to secure images of

the subsurface that can reveal details re-

garding the presence of micro factures, ori-

entation of faults and fractures, the influ-

ence of anisotropy, the directions of con-

tributing illumination, the elastic properties

of target reservoirs, and the extent (bound-

ary) of those reservoirs.

“We are still on the learning curve

with respect to the application of Earth-

Study 360’s new seismic data “deliver-

ables”, stated Mr. Dopkin. “We believe the

technology and procedure has a huge po-

tential to change the way geoscientists use

and interpret the directional sampling of

seismic data.”

digital energy journal - March 2009

A Division of Phi l ip C. Crouse and Associates Inc.

13 th I N T E R N AT I O N A L C O N F E R E N C E O N

Increasing query rates for the right data and information at the critical time continue to provide challenges to the E&P industry. With all the changes in tools, data, people, processes, the dilemma of “Your Data’s Here Somewhere” is frontline to efficiencies and success, while preventing costly mistakes and failure. Data integration of all those silos within the enterprise is still a daunting problem - yet is low hanging fruit that will continue to greatly improve efficiencies in the E&P enterprise.

Enabling e-discovery can help personnel dig for data. Many approaches can meet the challenge, and while no one approach is the “magic” way, attendees to this conference will hear real-world best practices and implementations from those companies leading the efforts to knock down data and information management barriers that confront our industry – seismic, G&G, well, field, production and reservoir data and information. It’s all about making quality data driven decisions.

:: Integration & Processes :: Quality of Data:: Cost Effective Solutions :: Interoperability:: IM and Knowledge Management :: Quantity Management:: Security and Archival :: Enterprise Architecture :: Cataloging :: Standards

Presentation authors are global. This event has been designed for data and information management practitioners and users.

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PNEC Conferences • Philip C. Crouse and Associates, Inc. • P O Box 181510 • Dallas, Texas USA • 214-841-0044

12

Exploration data

digital energy journal - March 2009

Visualising everything at onceDynamic Graphics has developed a tool which can visualise multiple datasets from an oil field simultaneouslyin 3D and 4D – from an overall view of the basin to a view of the individual wells and reservoirs – and you cansee how it changed over time as well. It can be used by everyone associated with a project.

Dynamic Graphics of Alameda, California

has developed a 4D (3D + time) reservoir vi-

sualisation software module which enables

you to visualise all of your data together for

your production operations, and see how it

has changed over time.

It gathers all of the data from different

departments into a format which everyone in

the company can use – without (for example)

paying for more expensive licenses for reser-

voir modelling software, and having to learn

how to use it.

This means that, for the first time, the

engineering department can work with sub-

surface data from seismic, which had previ-

ously been restricted to people in the geo-

science department.

This means that it can function as a com-

munication tool for both technical staff, from

different disciplines, and non technical staff.

“Geologists don’t have to know how to

run Eclipse. Individual disciplines can access

the output from other groups together with

their own data,” says Jane Wheelwright from

Dynamic Graphics. “It brings together the

different disciplines and the different pack-

ages into a common environment.”

In one company, engineers used time

lapse seismic data with predictive simulation

models to figure out that the water injection

wasn’t working. “They managed to stabilise

a field before the pressure caused problems.

Most engineers aren't familiar with the seis-

mic from their own fields.”

Like Google Earth, you can see entire

oceans or countries at once, and then zoom in

to see the subsurface of specific wells and

fields, with all the data you have.

You can see a 3D view of the informa-

tion, or see cross sections. You can visualise

the flow of oil, gas and water through the sub-

surface.

It is possible to connect other informa-

tion to the visualisation – eg if you click on a

well, the system can show you a photograph

of cores from it. “We have to combine all the

data at our disposal,” she says.

There is no limit to what can be includ-

ed in the image – it can include seismic data

volumes, well and rig locations, well logs, 3D

structural models, information about coast-

lines, field boundaries, satellite images, digi-

tal electronic models of platforms, geologic

maps, LiDAR data.

DGI is still developing new ways to in-

corporate data. “We want to, for example, ex-

tend the number of drilling formats,” she says.

The tool can show what is happening

over time – so you can see both the new wells

which have been drilled, and how the reser-

voir is draining (as worked out from time

lapse seismic data). Time sensitive data can

include reservoir simulations, time lapse seis-

mic, production data (eg from WITSML

feeds) and information about which well was

drilled when.

The company has already used the soft-

ware for carbon capture and storage visuali-

sations, enabling anybody who is interested

to see how the carbon dioxide will be pumped

underground and what will happen to it after

that. “For carbon capture, there will be a real

need to communicate with different people,

both technical and non technical” she says.

“You can show what is happening without re-

sorting to a spreadsheets and lists if figures.”

The tool can also be used to make pre-

sentations to management, rather than use

PowerPoint.

Above and below: Dynamic Graphics has a software tool which can be used to visualisedifferent data sets from an oilfield simultaneously - including reservoir information, wells, welllogs, flowlines and platforms

13

Exploration data

March 2009 - digital energy journal

Landmark, a brand of Halliburton’s

Drilling and Evaluation Division, has

launched PetroStorTM a new data storage so-

lution which promises to finally enable re-

liable data storage for the same price as

tape and provide real-time access to seis-

mic files and archived project data, says

Marc Spieler, director of Technology Op-

erations with Landmark.

The PetroStor technology lowers

archival storage costs to around $1000 per

terabyte by combining fast, high capacity

hard drives with data management software

from NetApp and data compression appli-

ance from Storwize.

Although a terabyte of hard drive stor-

age can be purchased for as little as $140,

many companies still expect to pay $3,000

to $10,000 per terabyte for data storage on

disk, Mr Spieler says.

The PetroStor solution is designed for

oil and gas customers who find themselves

facing an increasing amount of seismic da-

ta, as well as a growing need to access proj-

ect data archives as they explore prospects

in more complex formations and re-exam-

ine mature assets.

A big advantage of storing seismic da-

ta on disk drives is that seismic interpreters

can be given direct access to it, says Mr

Spieler.

“Today, if an interpreter wants to look

at the pre-stack data, a lot of times that’s

on a tape somewhere,” he says. This can

mean days or weeks of waiting while the

tape is located and transported.

Interpreters may choose to just make

do with the information they have rather

than waiting for the tape to be available –

making the resulting analysis less accurate

than it could be.

With PetroStor users can get both

seismic files and archived data from net-

work drives via their computer desktops,

as easily as from their computer hard drive.

Landmark offers a number of services

to complement the PetroStor solution, de-

signed to help companies make their data

more accessible, including support in mi-

grating their existing data from tape to

disk, indexing files and incorporating

metadata.

Tape vs diskUsers have always preferred the accessibil-

ity of disk drive storage, but it has been

cost prohibitive in the past, because it typ-

ically costs 4 to 5 times as much as tape,

Mr Spieler says.

“A lot of customers have tens of thou-

sands of tapes which they store in various

locations,” he says. “When it comes to ac-

cessing the data, it can take days or weeks

because someone has to manually find the

tape and load the data.”

There is a further issue of tapes decay-

ing over time, and often, archived data is

in an outdated format adding the extra step

of transcription to ensure the data is pro-

tected.

Similar issues can also occur with

hard drives, of course, but it is much easier

migrating data from one disk technology to

another when you can do it with buttons on

a keyboard.

Landmark’s solution also gets around

the problem of people wanting to have their

own copy of the data – when data is stored

Disk data storage forseismic - $1000 perterabyteLandmark offers incentive for operators to finally give up tape with anew online, disk-based storage system for technical data.

Landmark's PetroStor - store your data for thesame price as tape

14

Exploration data

digital energy journal - March 2009

Seismic surveys are typically undertaken in

extreme conditions, either on board a sur-

vey vessel at sub zero temperatures or from

the back of a truck in the searing heat of the

dessert.

This places demands on the data stor-

age system for temperature regulation, ro-

bustness and the ability to withstand salt,

sea and sand ingress.

Historically, tape has been used to

move large amounts of information from

field to data centre but this has many inher-

ent problems, not least of which is volume

with collection rates of 20Tb per day not

now being uncommon. Magnetic tape is al-

so very vulnerable to transit damage and

head alignment differences.

Meanwhile, disk storage solutions

have continued to evolve to the single re-

movable drive modules which are prevalent

today. These however have their own prob-

lems including drive handling, transporta-

tion damage and the accidental interchange

of data sets.

With survey costs usually running into

many thousands of dollars and often being

unrepeatable, it is essential that data must

be accurately stored and preserved during

transit.

Escon´s oil and gas industry customer

was looking for a new disk storage solution

for seismic data – and it soon became clear

that an appropriate product was not readily

available. A more robust bespoke design

for the specific requirements of the geolog-

ical surveying industry and their conditions

had therefore to be devised.

The company wanted a system with

the following features:

12 removable disks in a single drive

module weighing less than the 20kg regu-

latory health and safety requirement for

maximum weight of an object one person

can move.

To be able to insert and remove the

disk drive module over 5000 times without

it breaking.

A high performance fibre channel host

interface

An advanced electronic management

system to ensure the correct insertion and

removal of the disks.

Suitable cooling to keep the drives

within their safe operating curve, whilst en-

suring sand and salt are kept out.

A flight case suitable to protect the

module during transit.

The most difficult of the challenges

was the requirement to be able to insert and

remove the drive module over 5000 times

at very high data rates. Conventional SCSI

and SATA connectors achieved no more

than 4% of the requirement (200 inser-

tions).

EScon, together with design partners,

selected a spring probe connector to elimi-

nate the friction suffered by the male/fe-

male pairing whilst maintaining an opera-

tional drive data rate of 3Gbits/s.

This also had the added advantage of

providing a flat surface on the removable

drive, leaving no protruding connections

which may be damaged during transit.

To ensure the integrity of the data,

support for standard and advanced RAID

levels 5 and 6 together with Triple Parity

RAID was provided.

RAID stands for Redundant Array of

Independent Disks and it basically involves

combining two or more drives together to

improve the performance and the fault tol-

erance.

Combining two or more drives togeth-

er also offers improved reliability and larg-

er data volume sizes. A RAID distributes

the data across several disks and the oper-

ating system considers this array as a sin-

gle disk.

Twelve drives have in fact been com-

bined into one single removable drive mod-

ule which also incorporates shock mounts

for safer transportation in the reinforced

flight case.

It could not be assumed that the field

crew operators of the device would be prod-

uct or even computer conversant. To en-

sure correct operation an advanced power

management system has been provided with

a LCD screen directing step by step operat-

ing procedures.

This also utilises a loopback signal

check routine to confirm that all the disks

are correctly inserted before allowing the

system to be fully powered. The inclusion

of a simple recording of the systems usage

provides a warning when the device needs

replacement.

The relatively easy part of the brief

was the provision of a high performance

cooling system, redundant hot-swappable

power supplies and fan modules.

The data storage system developed by Esconfor the oil and gas industry

Making hard drives tough enoughData storage company EScon Ltd was asked to develop a hard drive data storage system tough enoughto use on seismic vessels.

on a networked drive and accessible online,

all users can have convenient access.

Data managementAs with a typical disk solution, data on the

PetroStor solution is protected in the event

of disk failure by the same enterprise-level

data protection used in standard NetApp

filers; maintenance to replace the failed

disk is simple, non-disruptive, and pro-

vides the users seamless access to their da-

ta.

The data is compressed as it is stored

on the disk drive, and decompressed as it is

retrieved – it all happens in real time and is

transparent to the user. In Landmark’s expe-

rience most seismic and petrotechnical data

can be compressed between 30 and 50 per-

cent.

Because PetroStor compresses and de-

compresses data in front of the filer, users

will see read and write times decrease since

there is comparably less data being written

to and read from the disks. This will also

decrease the resource utilization on the fil-

er when being accessed by multiple users.

“What all this means for the users, is

that the PetroStor solution’s functions will

be transparent to them – they’re not going

to know where their data is sitting, they just

will know that they have access to it when

and where they need it.”

Fracturing

15March 2009 - digital energy journal

Monitoring fractures with tiltmeters andmicroseismicsHalliburton has boosted its well stimulation and optimisation service through its recent acquisition ofPinnacle Technologies, the leading and most experienced provider of real time tiltmeter and microseismicmapping and reservoir monitoring services.

This past October, Halliburton closed its ac-

quisition of the assets of Pinnacle Technolo-

gies – an established expert in fracture diag-

nostic and reservoir monitoring technologies

– allowing the company to create a continu-

ous well stimulation monitoring and opti-

mization solution.

The complete offering now combines

comprehensive wireline-based logging and

perforating services, stimulation perform-

ance treatment (fracturing) and a fracture

mapping service in an integrated solution

that is also a flagship workflow of Hallibur-

ton’s Digital Asset, a collaborative Hallibur-

ton offering allowing operators to model,

measure and optimize their asset.

“We’re calling it Integrated Stimulation

Optimisation,” says Jonathan Lewis, vice

president, Halliburton Wireline and Perfo-

rating.

Well stimulation “is our largest single

franchise. It is a market which is becoming

increasingly sophisticated,” says Dr Lewis.

“By combining the experience and expertise

of Halliburton and Pinnacle we are now able

to bring new capabilities to customers world-

wide that will help them optimize their re-

turn on investment.”

FracturingHydraulic fracturing, explained simply,

works by forcing high pressure liquid into a

well to crack the rock around the well bore

in the production zone. This makes it easier

for oil and gas to flow into the well – so you

produce oil and gas more quickly. Fractures

can be thousands of feet long.

Techniques to monitor these fractures

are particularly useful in tight gas and shale

fields, where the efficiency of the fracturing

is very important to the overall success of

the field.

Most ultra-tight gas fields would be un-

able to produce without fracturing - it only

really became possible to produce some of

these reservoirs in 1998, when thinner frac-

turing fluids began to be used. “In most cas-

es tight gas fields will barely deliver a puff

of gas on their own,” says Kevin Fisher,

president of Pinnacle.

Fracturing operations have been car-

ried out since 1949. However, for many

years there has been very little understand-

ing about how and where exactly the well

was being fractured – it was just assumed to

be a long horizontal crack from the well bore

into the reservoir.

Pinnacle takes the credit for first dis-

covering that many fractures were very dif-

ferent and more complex than how they were

thought to be, when it embarked on a proj-

ect in 2000 to try to map fractures in shale

reservoirs.

It discovered that, rather than being a

single straight crack, they were often a large

number of extremely complex cracks grow-

ing in multiple orientations.

This discovery led to the development

of new methods for fracturing shale rocks,

which led to a big increase in production.

TiltmetersA tiltmeter is something like a spirit level

(used to keep pictures hanging straight in

your home) – a tube with a bubble in it. Pin-

nacle’s tiltmeters use electrodes to monitor

the movement of the bubble, which are so

sensitive they can detect a movement of 1

molecule left or right. This is equivalent to a

nanoradian or a change in tilt of 1 part per

billion - the change in tilt you would have if

you had a rod as long as the distance from

the US East to West Coast, and you lifted one

end of it a quarter of an inch.

Pinnacle’s first tiltmeters, developed in

1992, could map fractures at a depth of

around 5,000 feet deep. Now it has tiltmeters

that are more sensitive and can monitor frac-

tures at depths of 16,000 feet. Pinnacle

claims to have a 100 percent market share of

tiltmeters for monitoring oil field fracturing.

Typically, between 15 and 100 tilt-

meters will be placed on the ground around

the well.

At a basic level, tiltmeters can provide

information about the direction in which the

rock has been fractured. According to Mr

Fisher, the readings from tiltmeters can give

an immediate indication of the size, length,

dip, quantity and direction of fractures, with-

out any complex computer processing.

“Just looking at a raw surface tiltmeter

vector map, I can tell you the orientation of

the fracture – it’s very intuitive to get from

raw data to the final answer,” he says.

The data can also be used to make more

complex calculations to determine what kind

of fracture would have caused the change in

tilt which was detected at the surface. “We

can determine how complex the fracture is –

did we just get one long skinny frac – or a

multiplicity of fractures in several orienta-

tions,” he says.

“We want to find out, are we achieving

on site the desired goal – fracture height,

length and direction and is it in the pay

zone,” he says.

MicroseismicsMicroseismics are geophones (think micro-

phones) in the well bore, which can calcu-

late the location of any sound source from

the difference in time taken for the sound to

reach the different microphones, taking into

account the sound velocity of the rock, and

triangulating.

The microphones are located on the

tubing in the well, with 300 to 1000 feet be-

tween the top and the bottom one. They are

3-component geophones meaning that the

sensors point in different directions.

The readings from tiltmeters can give you animmediate indication of the size, length, dip,quantity and direction of fractures, withoutany complex computer processing - KevinFisher, president of Pinnacle

FracturingThere is a lot of noise as the fracturing

fluid breaks the rock up, which is recorded

on the geophones.

The data from microseismics can be vi-

sualised as dots on a map around the well,

showing where rocks have been forced apart.

“Microseismic is more complex [than

tiltmeters] – you have to know the velocity

of sound in each layer that the sound is trav-

elling through,” says Mr Fisher. “You have

to run sonic logs and use other data and serv-

ices to develop a velocity model. In some

cases you must refine the velocity model as

the frac progresses.”

Using the data The data from the fracture mapping can

sometimes lead to immediate changes in

how the fracture is being carried out.

For example operations can be imme-

diately halted if the fracture starts affecting

rock outside the reservoir.

“Many times during a fracturing job

we’re trying to give the operator that real

time look at where the fracture is going to

stay out of undesirable fluid contact,” says

Mr Fisher.

“While they’re watching the pumping

and volumes we can give them a bit of intel-

ligence,” he says. “For instance, we can in-

form the operator if a fracture is going a bit

downwards, and can make recommendations

to stop the downward growth. In this case,

the fracture engineer has a very useful tool

to come up with a better treatment.”

“You may have a fault a few hundred

feet away from the well bore – you might

want to do all you can do to stay out of the

fault.”

Over the longer term, the information

can be used when planning the next stage of

the fracturing job.

“Most of our mapped wells have 3-5

frac stages, often we map 15 or 20 times in

a horizontal well,” he says.

Various tools are available to change

the fracture so that the rock cracks in a dif-

ferent way – including using liquids with dif-

ferent physical properties, different pres-

sures, blocking off the well in different

places, and using more of less proppant

(small balls of solid material sent into the

well bore with the fracturing liquid, which

ideally stays behind and keeps the rock

cracks forced open).

“Knowing where the frac grew in the

previous stage helps you plan what you want

to do on the next stage,” he says. “You might

be able to eliminate a frac stage if the previ-

ous stage already contacted the next inter-

val. If the fractures didn’t grow as tall as ex-

pected – you might have to frac another

stage.”

Over yet longer timescales, the fracture

mapping information can be used when mak-

ing a decision about how far away the next

well will be drilled and what orientation you

want to place that well, taking into consider-

ation how far the fractures from the first well

extend.

Information managementManaging tiltmeter and microseismic data,

and presenting it to the right people at the

right time, can be complex.

Ideally, the new information should be

combined with all available data about the

reservoir, in a continually updated computer

model of what is thought to be happening in

the subsurface (an earth model).

This earth model can include informa-

tion about the rock types and reservoirs, with

data from a range of different sensors and

logs.

The earth model can be used to help

plan the next fracturing operation, working

out the best way to get the desired fractures

and taking into consideration how the rock

is expected to respond to different stresses.

During the fracture, data can be gener-

ated from tiltmeters and microseismics and

plugged back into a frac model, that output

then updates the earth model.

To do all this takes a sophisticated un-

derlying infrastructure for data management

and communications, which Halliburton has

developed through its Landmark software.

Landmark recently launched R5000, a

synchronous release of technologies for the

DecisionSpace® environment, which can be

used to run all oilfield operations, with

everything running from a common database

and data communications architecture.

“We’re leveraging that common back-

bone infrastructure, which makes it much

easier for our customers to get rapid access

to the data as we are acquiring it, and also

integrate it into a common visualization and

database,” says Dr Lewis.

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Well stimulation is Halliburton's "largestsingle franchise" - Jonathan Lewis, vicepresident, Halliburton Wireline andPerforating

Drilling, completions and production

18 digital energy journal - March 2009

Using the best drilling sensorsJames Burks, product line manager with National Oilwell Varco´s M/D Totco division, believes that hiscompany´s drilling rig sensors are better than others on the market. He explains why.

Few drillers would underestimate the impor-

tance of the reliable, consistent information

provided by rig sensors.

They provide measurements ranging

from loads and pressures to distance and ve-

locity.

Determining the best suited sensor for

a particular job is just as important as its ac-

tual performance.

While sensors have been designed and

manufactured for many years in a variety of

industries, the oilfield presents unique chal-

lenges with its often hostile drilling environ-

ments.

Working closely with NASA, NOV

M/D Totco has created sensors that have

flown on the space shuttles. The company

has also supplied sensors to major defense

aerospace companies as well as all of the

U.S. armed forces.

Manufacturing sensors in itself is not

uncommon within the oil and gas industry.

However, constructing ones that meet the en-

vironmental challenges and operational re-

quirements in the increasingly demanding

and difficult drilling business, and doing so

with precision, is difficult.

One of the world’s largest drillship

fleets had been using another manufacturer’s

hookload pins to hold the loads for the

drillpipe. After attempting all possible alter-

natives, company personnel still could not

obtain accurate readings, which fluctuated

continuously, especially with extreme tem-

perature changes.

NOV M/D Totco was approached to de-

sign replacement sensors and, after a 1-1/2

year trial period, the company’s sensors have

been replaced with the new design through-

out its entire drillship fleet.

A Norwegian company was experienc-

ing widespread problems with malfunction-

ing sensors. It also approached NOV M/D

Totco for a new design, which now supplies

the company with pressure and force sensors

at a rate of about 1,000 devices per year.

Practically speaking, when reviewing

existing sensors or designing new types for

first-time applications, it may be helpful to

break them down into four broad sensor

groups: compression cells, tension links,

load pins and rotating pinions.

Compression cellsMost compression cells produced in the in-

dustry are single output cells, with some de-

signs having a second bridge for redundancy

purposes alone, in the event one bridge fails

to ensure continued rig operations.

NOV M/D Totco has developed a triple

bridge compression cell that has three

bridges placed and bonded inside the load

cell, with three separate 4-20 mA outputs uti-

lizing three onboard signal conditioners.

The first two bridges are used for re-

dundancy and the third bridge sends a signal

to a third party instrument or equipment to

provide accurate hookload data.

NOV M/D Totco outfitted rigs having

systems to control the brakes and other

drilling activities are directly tied to these

triple bridge compression cells. By moni-

toring all three bridges simultaneously, a

rig’s software can compare the outputs

among the three signals.

As a result, the automated rig system is

able to monitor the true hookload coming out

of these bridges to enhance the performance

of the overall drilling operation.

Anchors for hookloadGenerally speaking, there are two types of

anchors for managing the hookload on a rig.

One is a pancake-style cell called a

compression anchor and the other is a ten-

sion-link style anchor.

For years, hydraulics have been used to

control both of these anchor types.

The pancake style is a flat hydraulic

cell with a diaphragm inside. When a load

compresses the anchor, a hydraulic output is

created.

The tension link style anchor is used

when the load is being pulled.

NOV M/D Totco manufactures both the

tension and compression types of sensors, so

the company can provide far better resolu-

tion of the hookload to enhance drilling per-

formance.

Moreover, it has gained a competitive

advantage in the marketplace by replacing

the previous hydraulics with electronics for

system control.

Hydraulics can provide operational in-

accuracies when extreme conditions exist,

such as weather, compression of air, hy-

draulic fluid level variations and vibrations

of the hydraulic hose.

In contrast, electronics improve overall

accuracy, which is invaluable to the driller

who is interested in accurate hookload meas-

urements, the variance being the weight on

bit—one of the main parameters used when

drilling a wellbore.

Load pinsA load pin is usually made of soft steel and

is placed between two structures to which a

force is applied.

This type of dummy pin can be instru-

mented and a sensor produced to detect the

load that is being applied to the joint.

NOV M/D Totco has used internal

gauging to greatly improve load pin design

compared to those previously manufactured

within the industry.

Typically, the strain gauge is placed on

the outside of the steel where it is exposed

to the environment.

In contrast, NOV M/D Totco machines

a half-inch hole through the center of the ma-

terial, which can be accomplished by chang-

ing the materials strength (usually 17-4 PH).

Then, concentration grooves are machined

into it to better direct the stress on the gauges

to improve repeatability. Finally, the hole is

seal welded on both ends.

Consequently, few failures have result-

ed because of the environment, particularly

from water. Water is the primary environ-

mental factor impacting most externally

gauged pins.

As an example, two-million pound ca-

pacity load pins have been used in the

Arkansas River navigational system, which

have been holding the gates for more than

fifteen years.

Rotating pinionsNOV M/D Totco also has developed a way

to actually measure the torque placed on

drive pinions in jack up rigs.

While the pinion is rotating, a signal is

National Oilwell Varco´s drilling rig sensors

Drilling, completions and production

20 digital energy journal - March 2009

sent to the control system to alert personnel

regarding the amount of torque being put on

the jacking system.

In the past, companies typically had to

buy devices costing approximately $70,000

to attach to the pinion and measure its

torque. NOV M/D Totco’s pinion actually

measures the force that is twisting it, which

is the true torque that is being applied onto

its gears.

Thus, the process of measuring in itself

actually becomes incorporated into the pin-

ion design. The instrumented pinion is de-

signed and built to fit in the same space and

housing. A connector is then added to which

a cable can be attached.

After the existing pinion is removed,

the NOV M/D Totco pinion is installed and

connected to the cable. As it turns, a unique

micro switch transmits accurate millivolt

signals to a display.

Torque signals are now available to the

operator for better control without the usual

interference that occurs with low level sig-

nal transfer through slip rings. This elimi-

nates the need for having to monitor motor

amps and manually check each pinion for ac-

curacy, which reduces the speed and safety

of the drilling operation.

Moreover, real-time data is provided

with the brakes on or off.

Strain gauge sensorAnother unique aspect of the NOV M/D Tot-

co sensors is the 4-20mA strain gauge sen-

sor applications, which have an onboard sig-

nal conditioner.

This digital board has both a processor

and temperature sensor, which offsets any

unfavorable temperature effects. As the tem-

perature changes, so does the bridge.

The board uses a look-up table and ac-

tually offsets the milliamp signal to remove

any variance caused by temperature—an in-

novation that has been proven effective in

the field.

Quality control

Precise instrumentation incorporated into its

sensors requires NOV M/D Totco to adhere

to stringent quality control in the manufac-

turing process.

As such, NOV M/D Totco has a certi-

fied test facility, with all of its products man-

ufactured to ASTM E-374 (ASTM’s elec-

tronic certification body) standards, all of

which are traceable to NIST. The certifica-

tion system electronically captures all meas-

urement outputs from a sensor and reference

cell, which is calibrated simultaneously to

four decimal places in less than fifteen mil-

liseconds.

This information is fed into the SQL

(Structured Query Language) server data-

base, so if a sensor comes back for re-cali-

bration or re-testing, its specific serial num-

ber can be tracked in the system. Any re-cal-

ibrated sensor will have a running history of

each testing and its respective performance.

Making it easier to share well logsNorwich based UK oil and gas software

company Geologix has developed a new on-

line service. www.wellxp.com, to enable

companies to share well log data with au-

thorized people connected to the project.

Well XP can receive data from Ge-

ologix´s GEO software, which is used by

well site geologists on their laptop comput-

ers, to gather well log information from serv-

ice companies, and provide initial interpre-

tation (eg to describe rock types encountered

at different depths).

For example, a company might have

Schlumberger doing drilling (and capturing

´measurement while drilling´ (MWD) data),

and Baker Hughes doing mud logging. All

of this data can be pulled together at the well

site into the GEO software.

The data communication from GEO to

the well site acquisition systems can be made

using WITSML (Well Information Transfer

Standard Mark-up Language), the data com-

munications protocol developed by stan-

dards body Energistics.

It means that well log reports no longer

have to be faxed or emailed as a pdf; and ge-

ologists don´t need to worry about storing

the data on their laptops or portable hard

drives.

Data can be exported out of Well XP in-

to subsurface data management software

such as Schlumberger´s Petrel.

The company is seeing a lot of growth

in Asia at the moment, says managing direc-

tor Samit Sengupta. It has offices in Jakarta,

Indonesia and Houston, Texas.

It is also building its web tools which

enable companies to share more information

to authorized users online.

Petris develops managed pressure toolwww.petris.comOil and gas software company Petris Tech-

nology has started offering risk management

software for drilling, in partnership with

software company Warrior, which has devel-

oped risk analysis software.

Petris will link its data management

and project engineering tools for drilling to-

gether with Warrior’s software.

The software has functionality to iden-

tify and rank the biggest risk factors when

drilling, and develop a risk management

plan. It can also analyse probabilities.

Users can evaluate what certain

changes will make to the overall risk profile,

time and cost of the drilling project.

The tool should be particularly useful

for customers using Petris´ drilling software,

says Eric Deliac, senior vice president East-

ern Hemisphere, with Petris. “There´s a risk

of drillbits getting stuck, explosions and

things you weren't expecting.”

A lot more underbalanced drilling is

taking place at the moment, and this has a

lot more complex risks attached to it, he

says.

Warrior

Technology

Services is a

specialist in

the oil and gas

industry, set

up by drilling

engineers, and

its software is

already used

by many

drilling com-

panies.

Eric Deliac, senior vicepresident EasternHemisphere, with Petris

Production

21March 2009 - digital energy journal

cluding the asset manager, are not equipped

to absorb R&D risks. So, placing R&D risks

on asset managers will accomplish little

more than killing DE innovation on the

launching pad.

Disconnect from your current ITThe first step in creating a viable DE culture

is to stage a “cultural disconnect” at senior

management levels from the current embed-

ded IT culture.

First, bring “incorrect” IT assumptions

to the surface by writing them down in ex-

plicit language in order to challenge each

and explain how the DE culture will work

differently. Then create the new DE culture

from a blank sheet of paper.

But what about the flip side? What if

the organization has actually been working

in a positive mode toward a DE culture?

If so, the IT assumptions its manage-

ment has are that IT will supply the means

for advancing productivity; business expec-

tations for IT projects will consistently be

met; IT projects will be on-target, on-time

and on-budget; IT Implementations will be

manageable and doable; and communication

between business and IT will be complete

and understandable.

Right direction is criticalProperly creating a new DE culture is criti-

cal not just to get the right puzzle pieces in

the right places. It is also the template for ad-

dressing problems and guiding workers in

performing their jobs within the new organi-

zational culture.

Yet, many organizational cultures are

not necessarily pointed in the right direction

in the first place, which is what often makes

the collision of IT and DE not unlike a train

wreck.

The reason for the wreck is not difficult

to ascertain even for laymen.

DE is typically seen by most workers

as if it were a television commercial for tech-

nology: “Deliver new productivity to your

company and solve all your problems with

our new software. No special work or skills

required.”

The truth is that the DE culture will re-

quire an engineering mindset especially for

implementation and business readiness.

As a result, management typically

looks at DE they want to introduce at any

given time and invariably concludes the

technology will be fully and enthusiastically

utilized, after some good psychology-based

communication of course, beginning at 8 am

the next day.

Imagine the surprise at every company

that thinks this way when they discover this

mindset is simply inaccurate.

In brief, a company’s non-DE culture

may work quite well for all manner of tasks

and business objectives but, at best, may be

an awkward fit for the new DE working en-

vironment.

The solution, as for most business prob-

lems, is to shift into the proactive mode and

proceed forcefully in order to develop and

shape the company’s new DE culture, one

which is a glove-fit for its people and

processes.

This solution – for the company’s DE

future – begins and carries through on a pos-

itive, yet challenging, note.

At the outset, management draws up

expectations to be met at three different lev-

els within the organization: executive, sen-

ior management and technical professional.

Executive levelAt the executive level leadership factors are

the driving force.

To maximize DE’s value in the work-

place, new technology should be deployed

Fitting digital energy around your ITdepartmentYour IT department can often be at cross purposes with your digital energy strategy, says Dr DutchHolland. Here are some ideas how to resolve the problem.

Within any organization a Digital Energy

(DE) culture does not magically appear,

seamlessly integrating people with technolo-

gy. Realistically, the organisational wheel

must first be reshaped to make it roll more

easily.

Why? Every organisation’s culture is

made up of several subcultures based on the

past and ongoing assumptions.

One involves how the people work with

and think about information technology (IT).

The working relationship with IT dates back

many years, or even decades, for most com-

panies. Many assumptions about IT may

have been created and reflexively accepted,

without ever being challenged as wrong.

The cumulative effect of this unchal-

lenged IT thinking might have been general-

ly benign except for its recent collision with

DE.

What happened is that managers have

tended to view DE through the same lens at

they view IT.

This is somewhat akin to watching a

movie with an exciting action hero who un-

expectedly meets an unhappy ending.

But, the oil industry has the opportuni-

ty of a lifetime because it can write a much

more upbeat ending to real-life DE at com-

panies throughout the world.

Overall, the objective is to have DE be-

come more than simply the introduction of

new technology into an oilfield company.

When done properly, the goal is to use the

power of digital technology to transform the

way the company does business into one that

takes the business to a new level of excel-

lence, accomplishment and profitability.

Just as a farmer must prepare his field

for planting, DE advocates must diligently

prepare the organisation’s “IT culture” be-

fore DE’s promise can be realised.

People don't want riskRemember that risks are always associated

with introducing new technology within an

organisation, as is any new way of doing

business.

Typically these risks are absorbed at the

top level of management because they usu-

ally issue the go-ahead on new technology

after the case is made at lower levels.

However, lower level managers, in-

Often the term 'culture' has a negative effecton employees - ‘Digital Energy workingenvironment’ is better - Dutch Holland, CEO,Holland & Davis

by executives communicating explicitly to

workers throughout the company.

In a crystal-clear, non-fuzzy way, exec-

utives should put forth what is coming

through the pipeline – not just floating the

new DE out in the workplace and allowing

employees to adopt or ignore it.

Simultaneously, as with a coach for a

sports team, these same executives must be

offering clear direction, while pushing and

prodding. Remember, DE is engineered into

a company, not sweet talked into it.

And to further help ensure that every-

one gets the point, a system must be put in

place to align objectives with accountability,

stressing that DE’s success or lack thereof

has real consequences. Failure will be penal-

ized and successful implementation leading

to full use of the system will be rewarded.

Senior managementSenior management has its plate full of re-

sponsibilities, too, in creating the new DE

culture.

The senior management level must in-

sist on a systems engineering to approach to

business readiness. In fact, they have to deal

with two different stakeholders: business

units and corporate.

On an everyday basis, this means when

corporate strategy hinges on DE leveraging,

senior management cannot set corporate

aside just to make the highest current profits

for their business units.

They must be on the same track as up-

per management in the respect of keeping

DE implementation momentum alive instead

of resorting to the simplistic “out with the

old and in with the new.”

Technical professionalsTechnical professionals, who comprise the

third level, have to begin living in the pres-

ent and the future at the same time.

On the one hand, they have to continue

being very exacting and professional in their

technically-oriented work.

While this should be expected under

any circumstances, these traits are particu-

larly important when the organisation is

bringing new DE on board because these

qualities validate their input.

On the futuristic side, they must recog-

nize that the days of doing a considerable

amount of manual work and functioning on

relatively slow time cycles are over.

The environment now, hence the future,

is real-time and 24/7 instantaneous decision-

making. And, finally, as if these other re-

sponsibilities were not enough, they must

share knowledge and work collaboratively

in helping ensure successful DE implemen-

tations.

About the authorFor more than a decade Dutch Holland

has been the pioneer in applying a systems

engineering approach to change manage-

ment in the digital oilfield (Engineering

Organizational Change®{patent pending}

and Systems Engineering Approach to

Business Readiness®). Dutch Holland,

PhD, is CEO of Houston, TX-based Hol-

land & Davis LLC (www.hdinc.com)

Specific actions

Now comes what most people look for when

presented with a challenge, in this case, cre-

ating the new DE culture.

Yes, there is a game plan to achieve the

objective, so that guesswork does not have

to be brought into play.

Steps required for changing to a DE

culture are, most importantly, reward-based.

In other words, the new DE culture that is

being created must be clearly communicated

to workers while explaining that successful

implementation will be rewarded in various

ways, ranging from bonuses to promotions.

With that in mind, specific actions re-

quired for DE culture change are:

Identify the culture or new work envi-

ronment that everyone will be expected to

work toward, so that the organization can op-

timally leverage all the attributes that DE of-

fers. This must be communicated at all three

levels, not just on an arbitrary or spot basis.

Establish the opportunities for employ-

ees to best comprehend how they are aligned

within the new DE culture, through means

such as benchmarking and essentially hav-

ing them diagnose their niche within the or-

ganization

Help ensure that the transition to a new

DE culture is guided by a systems engineer-

ing approach. Pinpoint and communicate the

specific changes that must be made in how

the company presently functions and map

the route to implementation of the new DE

culture.

Inform employees that the organiza-

tion’s transition to a DE culture is project-

based (again removing any broad brush

thinking), which will hold managers ac-

countable for how effectively the change is

made.

Inject some “extras” into the reward

system to let everyone know that, just as re-

al consequences are in place to penalize fail-

ure, there are enhanced sweeteners for DE

culture implementation success.

Although this analysis has discussed

DE in terms of “culture,” it’s best to present

the change to workers at the organization by

using words such as “DE working environ-

ment” and “DE workplace.” Often “culture”

has a negative effect on employees.

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PEOPLE: Effectively incorporate change andknowledge management into your integratedoperations for effective collaboration and optimisedoperations

PROCESSES: Improve decision making and boostoperational efficiency by effectively linking eachcomponent of your digital oilfield

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Transforming E&P through integrating People, Processes & Technology

Yesterday it was about the future of

digital oilfields, today it is aboutenhancing their efficiency

Communications

24 digital energy journal - March 2009

Schlumberger – Wireless and WiMAXcommunications in North American oilfields

Schlumberger has made an agreement with

ERF Wireless to be an exclusive reseller of

its wireless data communication services for

the oil and gas industry in North America.

This means that it will be offering the oil

and gas industry 1.5Mbps data communica-

tions using Wireless and WiMAX, in North

American oilfields, thus, enabling real-time

data collaboration between remote and field

operations. Oil operators are aspiring to im-

prove safety, environmental performances

and production while reducing costs. Mind-

sets are therefore changing from a conven-

tional operations mode to that of real-time op-

erations to support those expectations. This

requires a complex combination of people,

processes, and technology to remotely moni-

tor and analyze drilling data, update models

in real time, collaborate among teams, and

provide expert consulting.

ERF Wireless already claims to have the

largest wireless communications network

covering North American oil and gas opera-

tions, and the service is growing quickly, so it

may soon cover entire basins.

The data communications is non-con-

tended, which means that every single indi-

vidual site is guaranteed to get the full

1.5Mbps; there is also no limitation on the

amount of data that can be transferred. This

is something you do not normally get when

using a wireless communications service in

an airport, or from your home or office inter-

net service.

It is also fully encrypted, so there is no

way that anyone unauthorised can change or

read the data. ERF Wireless has set up simi-

lar wireless communications for banks, and

so has expertise with wireless data security.

Many oilfields are located far away from

cellular phone networks, and can only send

high bandwidth data by using satellite com-

munications or microwave, which are expen-

sive, and also suffer from high latency (a de-

lay due to the time to send the data to the

satellite and back). This latency can interrupt

the fluency of voice communications and

make machine to machine communications

very complex and unreliable.

With this wireless data communications

service, Schlumberger is able to help people

communicate in ways they were not able to

do before, like enabling drilling operations to

send data back to the office for collaboration

in real time.

“I believe it’s relatively affordable for

any client,” says Deryl Rice, business manag-

er for global connectivity services in North

America for Schlumberger. “Personnel sta-

tioned at the wellsite still have to routinely

travel offsite to locations that offer more reli-

able connectivity to upload operational data

for review by centralized experts. This new

service allows experts at the wellsite and oth-

er locations to collaborate effectively during

operations and not have to be restricted to pe-

riods between operations”.

The network is being expanded rapidly,

in areas where there is a large amount of oil

and gas activity and demand for the service.

“If a customer wants to go out to the

Rockies somewhere [not already covered by

the service] we can go there and set up a net-

work for them within a relatively short time

frame,” says Mr. Rice.

There are a number of government

grants available to support the roll-out of

wireless communications in local communi-

ties, which the industry might be able to take

advantage of, Mr Rice says.

The service is so reliable and secure that

it might ultimately be used for sending remote

commands to automation equipment, al-

though there are no plans for anyone to do this

so far, Mr Rice says. “The industry is pushing

us for using it to run equipment remotely and

this new service certainly paves the way for

that to happen in the not too distant future.”

ServiceThe service is specifically designed to meet

the oil and gas industry’s environmental, op-

erational and safety requirements in the land-

based oilfield. Schlumberger carried out an

extensive collaborative study that spanned its

technology segments to ensure that the quali-

ty of communications and associated Service

Level Agreements meet the needs of the mod-

ern oilfield.

”Whilst there are a large number of na-

tional service providers that offer commercial

grade communications, we found that oilfield

operations require a far superior level of serv-

ice,” says Mr. Rice.

ERF Wireless will undertake the work

of installing wireless data communications in

the region and connecting it to the internet or

through to private corporate networks. ERF

has a dedicated oil and gas services sub-

sidiary.

The service uses a range of data proto-

cols, including Wi-Fi and WiMAX, which

transports the data of entire networks from the

wellsite to the office. The maximum distance

of an operational site from a wireless commu-

nications base-station can be up to 20km, says

Mr Rice.

The ‘backhaul’ (communications be-

tween the wireless data terminal in the field

and the international communications net-

work) can be made by fibre optic cable, or a

variety of other means.

Using the serviceThere are plenty of ways people and compa-

nies might benefit from the service.

For example, having reliable, fast data

communications is an important component

of all aspects of the ‘digital oilfield’ and one

which has often been missing or underesti-

mated to date. Meeting AFE (Authorization

For Expenditure) commitments, streamlining

productivity to reduce the completion times

and reducing NPT (Non Production Time) is

a common goal for all oilfield operations.

With a service like this, a range of data

could be sent back to the office and engineers

could monitor it from there. For example,

they could see live video feeds of site opera-

tions, and get log data, automation data, and

data from sensors in real-time.

Through an exclusive agreement with ERF Wireless, Schlumberger is offering 1.5Mbps wireless datacommunications for oilfields in North America, which will eventually be available for entire basins.

Installing wifi in oilfields across NorthAmerica - John Nagel, CEO of ERF Wireless' Oiland Gas Services Division (left) with DerylRice, business manager for globalconnectivity services in North America forSchlumberger (right)

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