Modeling NTG Pitfalls

August 2008
The Geomodeling Network Newsletter

A very happy summer to all of our Geomodeling Network members.
I hope you all enjoyed the first newsletter and are ready to digest the second
instalment. Our group has grown quite a bit since June; indeed we are now
cruising towards the 300 mark with new members joining each day.

For those of you that may be interested you may like to know that the
employment category breakdown of our membership is as follows:

E&P company staff 48%
E&P consultants 12%
SW vendors 26%
Other 14%

Hopefully you’ll agree that it’s a healthy mix of people, dominated (rightly so) by
those that carry out Geomodeling tasks and those that supply the Geomodeling
technology – this was the demographic I was hoping to achieve. The ‘Other’
category is a mix of academics, recruitment specialists and other interested but
“non-G&G” people.

Whilst I did receive some feedback regarding the 1st newsletter it would be of
great benefit to the group if more people contributed. Not necessarily in the
provision of articles but by providing comments or opinions. I appreciate we are
all busy but please take a few minutes to do this if you can. The people who
write the articles have invested some time and effort in them and are keen to
receive as many comments as possible.

As before, on the next page you will find a listing of all the articles in this
newsletter, hopefully you will find something of interest. As ever, if you would
like the format to be changed for subsequent newsletters please let me know –
all constructive comments (good & bad) are welcome.

Welcome again,

Mitch Sutherland (group administrator)
mitch.sutherland@blueback-reservoir.com

Page 1 The Geomodeling Network – Sponsored by Blueback Reservoir www.blueback-reservoir.com

August 2008

Table of Contents

1. Member Articles, Reviews & Questions

1.1 Modeling N:G and Associated Properties- workflows and Pitfalls
Page 3
By Jose Varghese – Shell
An article that looks at some of the ways N:G can be defined and modeled
and the inherent pitfalls that await the unwary geologist.

1.2 To model N:G or not to model N:G Page 11
By Juan Cottier – Blueback-Reservoir
Should we even be considering modeling N:G in 3D? This article is sure to
raise a reaction!

1.3 Questions relating to Probabilistic Vs Deterministic methods of
calculating GIIP or STOIIP Page 15
By Jose Varghese – Shell
Multiple questions on calculating volumes (methodologies, varying contacts,
monte-carlo simulation workflows etc)

2. New Geomodeling Technology
2.1 Roxar’s August webinar’s Page 20

2.2 JOA – Handling of complex fault geometries using Jewel Suite Page 21

2.3 EMGS and Blueback Reservoir launch ‘BRIDGE’, an EM integration tool
for Petrel Page 27

2.4 Petrophysical Analysis Workflows using OpenSpirit Page 29

3. Career Networking Page 29

4. Requests for newsletter No3 Page 32


August 2008

1. Member Articles, Reviews & Questions

1.1 Modeling NTG and Associated Properties- workflows and Pitfalls
Jose Varghese (Jose.varghese@shell.com)

Defining Net to Gross (NTG) at the well level and modeling it in the static
reservoir model play an important role in the hydrocarbon volume calculation.
Though it may sound simple, there are chances for erroneous calculations in
NTG, during reservoir modeling. This document aims to highlight some of the
issues, recommended workflows and also invite comments and suggestions from
the readers.

WORKFLOW PRACTICES

When it comes to defining and modeling of NTG, people have been following
many workflows, such as:

Use Gamma ray or Vshale or Porosity or a combination of all these to define Net
and Non Net interval at the well log scale.
Use the facies log (created using the log cut-off or manually interpreted) and
create a NTG log (e.g. NTG= if(facies=0, 0,1) ; i.e. If the facies code is non
reservoir, keep NTG zero, else keep it as 1)
Once the facies 3D model is created, generate a binary NTG model from the
facies model itself (e.g., NTG_model= if(faciesmodel=1,1, 0); this creates an
exact copy of facies model.
Upscale binary NTG log into the Geocellular model and interpolate
independently.
Upscale binary NTG log into the Geocellular model and interpolate it
conditioning to facies model, but keeping NTG=0 in non reservoir facies.
Upscale Binary NTG log into the Geocellular model and interpolate it
Watson: Holmes! What conditioning to facies model, and model it in all facies (including non reservoir
kind of rock is this! facies).
Keep the property values as zero in the Non reservoir interval, upscale and
model conditioned to facies.
Holmes: Sedimentary, my
Upscale cut property logs (Porosity, permeability etc) and model it conditioned
dear Watson. to facies, assign zero values in Non reservoir facies.
......I’ll get my coat! Upscale cut property logs (Porosity, permeability etc) and model it conditioned
to facies, (model it in all facies).

It can be seen that, there are issues with some of the workflows. These issues
become significant, when the cell thickness or layering scheme in the model is
very coarse and the heterogeneity seen in the logs are not captured by the


August 2008

layering scheme. We can see some of these issues in detail in the following
sections.

DEFINITION

As mentioned earlier, NTG is defined either by using a log cut-off or by using a
reservoir – Non reservoir discriminator log (a facies log).

One of the QC method used in checking the Upscaled/modelled result is to
compare the Equivalent Pore Column(EPC), between the well level properties (as
shown below) and the corresponding model derived properties. They would
(should) match when the the layering scheme has properly captured the
heterogeneity seen in the wells.


August 2008

Many of the issues come up during the modeling stage only, not at the well log
scale of interpretation.

For mappable shale layers (deterministic shales), as shown in the figure below,
NTG can be assigned to “ZERO”. The accuracy of defining the layer boundary is
user controlled.

Net pore volume in this case is Zero. No need for even making layers in this unit.

But for those shale intervals interpreted in wells, which are not correlatable
(present in the reservoir units, which need to be distributed stochastically in a
model), the definition and modeling of NTG bring some issues in the workflows
practiced.

MODELING ISSUES

quot;Can ye make a model of Consider a perfect case of layering as shown below. Here both the original facies
it? and upscaled cells match exactly. In other words, each cell represents 100% of
If ye can, ye understands the same facies at the well log level. But this remains an ideal case, as the user
it, and if ye canna, ye does not have a control on the exact match of facies boundaries and layer
dinna!quot; boundaries. This can be approximated by taking a fine layering. Sometimes, the
model dimensions and the modeling strategy would require going for a coarser
layering.
Lord Kelvin (supposedly)


August 2008

Now consider the following situation, where the layering is bit coarser. When
the facies logs are upscaled, the resulting cell facies DO NOT represent 100% of
the same facies at well log level.

Consider the Reservoir and Non Reservoir facies cells inside the red circles. The
reservoir cell is not 100% reservoir and similarly Non reservoir cell is not 100%
non reservoir. In such cases, the different upscaling and modeling practices have
different impact on the GIIP or STOIIP calculated.


August 2008

Consider the flowing case

If NTG is created by using the facies in the model as a criteria (ie NTG_model=
if(faciesmodel=1,1, 0); this creates an exact copy of facies model.), as seen in the
red rectangle, it can be seen that, we overestimate reservoir facies in some
cases (green rectangle) and in some case we underestimate the reservoir facies (
Pink rectangle). So it is clear that the “Binary NTG in the model” is not a
representation of the facies at the well log level.

So the correct procedure would be to upscale the binary NTG log (raw log), so
that it becomes a non binary log (all values between 0 and 1 possible). This will
account for the Reservoir and Non reservoir fractions lost during upscaling.
Consider the upscaled non binary NTG in the above figure (blue rectangle). See
the cell with a yellow boundary. It is a Non reservoir cell in the model. But it has
actually about 5% of reservoir facies as well. A binary NTg with “0 “ value will not
account for this. But the upscaled NTG with a value of 0.05 accounts for the 5%
reservoir facies.

When there are many wells and similar discrepancies due to coarser layering
occurs, the sum total of all such discrepancies would result in incorrect
GIIP/STOIIP.


August 2008

Summary

Always use a facies interpretation (reservoir, non reservoir discrimination).
Always use a binary NTG at log level and upscale it to the model.
Make sure that the R/NR log used in defining NTG is consistent with the current
facies log /model used.
Do not use a binary NTG directly in the model (created from facies).

MODELING PROPERTIES
quot;The primary role of
the geologist is to
recognise the existence Once the NTG is upscaled, how to proceed with modeling NTG as a full 3D
of phenomena before model? The practices seen for creating 3D NTG property are,
trying to explain themquot;
Create NTG Model directly from facies model (discussed and mentioned as the
B.M. Keilhau, 1828
wrong method in earlier section).
Model NTG using the upscaled NTG log, independently of facies.
Model NTG using the upscaleld NTG log, facies conditioning done, but assign
zero facies in Non reservoir facies .
Model NTG using the upscaled NTG log, facies conditioning done, model all
facies.

If NTG is modeled independently of facies, it MAY result in scenarios where the
interpolated NTG model shows a low value, in a place where the facies model
would show a good reservoir facies. This will result in inconsistency. But if the
modeling is done conditioning to the facies (model NTG is each facies
separately), the resulting NTG model will be consistent with the facies model.

While conditioning to facies, if NTG is assigned as “0” in the non reservoir facies,
the same mistake of making a binary NTG in the model would be repeated. In
other words, the NTG value in the Non reservoir cell is not necessarily zero
always. That cell may have a representation (though low) from a reservoir facies
as well. Hence it will have a low but non zero NTG. If we assign this to zero, we
are practically loosing that much reservoir volume.

Summation of all such “small” errors in a case with many wells, would result in
volumetric discrepancies.


August 2008

Summary

Model NTG by conditioning to facies model.
Model NTG in all facies including Non reservoir.

UPSCALING/MODELING OF OTHER PROPERTIES

Similar issues can be seen with the upscaling/Modeling of other properties like
Porosity, Permeability etc.

Usually when the petrophysicist gives the processed porosity log, it will have a
zero value in the non reservoir intervals. These zero values would influence the
upscaling process and can cause double dipping in the net pore volume and
hence in the GIIP/STOIIP results. Zero is also considered as a value and used for
averaging during the upscaling process. Consider the example as shown in the
following figure.

The cell with a red rectangle on it, has a reservoir facies. But it is not 100%
reservoir facies. As shown by the upscaled NTG, that cell is 60% reservoir and
40% non reservoir. But for the 60% reservoir facies, the corresponding porosity
is a low value of 0.12, which is not representative of the reservoir facies. In other
words


August 2008

Net Pore Volume= Gross Volume * NTG * Porosity of the reservoir facies

=Gross volume *0.6 *0.12 = 0.072*Gross Volume --- double dipping

But it should have been

=Gross Volume *0.6 * 0.2 = 0.12 * Gross Volume

This issue can be solved by making the porosity (other properties as well) values
in the non reservoir interval as “Undefined”. Consider the following illustration

The impact of undefining the property values and then upscaling can be seen in
the property values in the upscaled cells. Consider the cell with reservoir facies
(red rectangle outline). It has 30% non reservoir in it. But the porosity assigned
in that cell is representative of the reservoir facies only.

Now consider the cell with non reservoir facies (orange rectangle outline).
Though it is a non reservoir cell, it is not 100% non reservoir. It has 20% of
reservoir facies (with a 20% porosity as well).That brings up another question.

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10

August 2008

If Porosity is modeled, by conditioning to facies AND assigning zero value to non
reservoir facies, what will happen to those non reservoir cells which has a
reservoir facies fraction in it?

It can be seen that, if a zero porosity value is assigned to all non reservoir facies,
the cumulative effect of many such non reservoir facies cells (with some fraction
of reservoir facies in it), would result in volumetric discrepancies.

Even if this would create porosity values in non reservoir, it is co existing with
very low NTG values and hence the net pre volume will be correct.

Summary

Make the properties to Undefined in the Non reservoir sections.
Model the properties conditioning to facies and in all facies.

------------------------------

1.2 To model Net to Gross or not to model Net to Gross!
Juan Cottier – Blueback Reservoir (juan.cottier@blueback-reservoir.com)

quot;The purpose of war In my view there are two overwhelmingly important and connected issues to
consider here:
is not battle but
victory.quot; Firstly: net to gross is an artificial construction, it does not exist and it should
or:
not be modeled in 3D.
The purpose of
analysis is not Secondly: any attempt to model N:G will fail because of simple issues regarding
modelling but scale and selection.
understanding.
Sun Tsu,
The Art of War, ca 500 BC
So, why does net:gross not exist? The concept of “net rock” has been about
since Schlumberger ran the first log in 1927 and probably before that. The idea
of “pay” or “producing intervals” or “kh” from a well test is standard oil field
practice for reservoir engineers but is very different from a geoscientists idea of
n:g.

11

August 2008

Net to gross is an artificial construction to allow 1 dimensional data namely a
well log to be used to explain a 3 dimensional asset. If the well results are not
considered in three dimensions then a “good rock / bad rock” discriminator can
be applied and everyone can be happy with their “understanding” of their lovely
new well and pat themselves on the back. As geologists, we should know that a
4 metre thick channel with a 2cm shale drape on the top can extend for
kilometres in one direction and can pinch out to provide a 4m shale sequence
within a few metres in another direction.

Texans drilling wells in the 1930s and 1940s used net to gross because they had
no choice. Those net to gross values were contoured up to create reservoir
“You can have it good,
quality maps. When mapping software came in to play in the 80s the good, old
fast, or cheap: pick any
school geologists would complain about the mapping algorithms, and for very
two.” good reason, because they were not thinking geologically: ………….. fluvial
The Project Manager's Maxim
channels, stacked dunes, delta front beach sands or offshore sand-bars.

In 3D we should model what we think is representing the subsurface, we can use
facies modeling, we can attempt to describe a 3D volume with the detail and
heterogeneity and the complexity. We don’t need to start the process by
defining “good rock / bad rock”. Nor should we do. All rock is equal, comrades,
even if some rock is ultimately more equal than others.

So, why is it impossible to model correctly?

Well there is a scale thing to start with. See the attached jpg photo. There is no
doubting here that there is excellent sand (orange) and non porous shale (grey).
There is also little doubt that it would be possible to sum the relative
proportions of sand and shale and come up with a n:g. But look at the lens
cap(*). We are looking at beds considerably smaller than 6 inches which is the
standard sampling interval for logs, the resolution of tools may well be greater
than that ….. so how could you possibly get a correct result from log data.

For example a gamma log would be smeared with “average values”. It is possible
to use curve inflections, or the curve tendency towards a value rather than an
absolute value to identify thin beds. But still. It is also worth noting that these
are not what would be described a “thin beds” in a “thinly bedded” or “tiger
stripes” reservoir. I have worked on a field in West Africa where the sand shale
couplets were providing sand beds of 2-5mm.

12

August 2008

Rockefeller once explained
the secret of success. 'Get up
early, work late - and strike
oil.'
Joey Adams

It is also worth considering what is used as a cut off.

Vshale? From a gamma log? How is the radioactivity of a rock any indication of if
its ability to flow oil? Well, it’s probably because you get a gamma log with any
tool run and it’s the one bit of log analysis any geoscientist can do.

What about porosity? A porosity cut off at 10% porosity? 5%? Why? Absolutely
no reason. Probably because, like many decisions in the oil world, it “feels about
right”.

But surely porosity can be a direct link to permeability? And permeability is
about flow and flow is the discrimination between “good rock / bad rock”.

Excellent! That means we should use permeability as a cut off. Isn’t it?

Rule of thumb in the oil patch is 1 milliDarcey for oil and 0.1 milliDarcey for gas.

Well for start off there is no way to directly measure permeability in the
subsurface other than perhaps the NMR tools. Most perm logs come from a
transform from a porosity log and that transform often comes from a
relationship identified in core plugs. These plugs are samples of rock that have
been sitting around for millions of years doing nothing and then within a matter
of weeks are taken from some pressure of 1000s of PSI, to atmospheric, shipped
across the world, washed and cooked and then tested. No wonder a core plug
perm is always 20 times less than that identified by a well test. Which brings us

13

August 2008

back to scale. So do we apply our n2g cut off to the core perm or the well test
perm? Air perm or in situ perm?
“The product of an
arithmetical computation
is the answer to an
Consider the following:
equation; it is not the
solution to a problem.” We use a permeability cut off for defining net:gross. We now have non net rock
By Ashley Perry (bad) which doesn’t flow and net rock (good) which does flow. But of course it’s
not the perm that flows oil it’s the relative perm …. The relative permeability is
dependent on the saturation of the oil versus the saturation of the water. Which
is the continuous phase? Oil or water? So should our n:g cut off be relative
permeability? As we produce oil and inject water then our oil and water
saturations will change, and so will our relative perms, and so will our
continuous and non continuous fluids. And this is two phases, shall we add gas
and make it three phases?

Do we need to constantly update our n:g? Time-lapse net to gross modeling?

For those of you still reading, here is Darcy’s Law straight from Wikipedia.

Wikipedia: “The total discharge, Q (units of volume per time, e.g., m³/s) is equal
to the product of the permeability (κ units of area, e.g. m²) of the medium, the
cross-sectional area (A) to flow, and the pressure drop (Pb − Pa), all divided by
the dynamic viscosity μ (in SI units e.g. kg/(m·s) or Pa·s), and the length L the
pressure drop is taking place over.”

“Say you were standing
with one foot in the oven That means if permeability is calculated from Darcy’s Law then it is proportional
and one foot in an ice to viscosity and indirectly proportional to the pressure drop ……………… so if gas
bucket. According to evolves from the oil, then the perm will change and the rel perm will change and
statistics, you should be our net to gross will change? Really? No … of course not, because net to gross
perfectly comfortable” does not exist.
Bobby Bragan, 1963
Then again try telling a senior geoscience manager who has had a long a
successful career using n:g that it doesn’t exist.

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August 2008

Much of this could well be rubbish …. But it’s worth a thought for a moment or
two.

----------------------------

1.3 Probabilistic Vs Deterministic Results when computing
GIIP or STOIIP
Jose Varghese – Shell (jose.varghese@shell.com)

Question 1:

When we compute GIIP or STOIIP using probabilistic methods and deterministic
methods(low case, mid or most likely case and high case), is it ALWAYS true that
the P50 case of Probabilistic method should be near to the Deterministic mid
case(or most likely case)…..and same for Low & P90 and High & P10 cases??

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August 2008

Question 2:

Can there be a situation where, the deterministic cases like low case and high
case are not at all captured in the Probabilistic ranges? (Logically thinking it
should be captured in the Probabilistic range)

If the answer to this question is NO (ie deterministic cases should be always
within the Probabilistic range), then my real problems comes (next figure)

Example Case: varying three contacts in a probabilistic workflow

16

August 2008

While running the monte-carlo workflow, let’s say each of the contact is put as a
variable with a Normal distribution.

In every run, a random value is chosen for the contact. But that random selection
of all three contacts NEED NOT BE like shown with Blue colour (all lows in one run
or all Highs in one run). If only this is achieved, we would be able to include the
deterministic low – high cases within the probabilistic ranges.

If the situation is like shown with red colour, the probabilistic range will not
include the deterministic low- high values.

Deterministic Low case is calculated by taking ALL low case contacts (and probably
but not necessarily all low cases of other parameters like NTG, Porosity etc). Ie in
case of contacts, in all the three zones shown above, the deterministic low case
will take the lowermost value only

Similarly is the Base/Mid case and high case

17

August 2008

Do the simplest thing
that could possibly
work.
By Kent Beck

One solution is to run the simulation for large number of runs… Expecting that in
some runs, it will capture all low ranges and in some cases all high ranges, thereby
simulating GIIP/STOOIP values near to the Deterministic Low and High cases. ..But
again..this NEED NOT be true always...

When deterministic Low or High is calculated, we introduce a DEPENDENCY -..ie
for one parameter if a low value is selected, other parameters are also selected
from the low value

This kind of dependency is difficult to introduce in a Monte-Carlo workflow….or
may be large number of runs are needed. (Please correct me if I am wrong

In Petrel..it is difficult…what about other 3D modeling software? )

If the parameters can be related in some way, then the dependency can be
achieved… eg

Contact 3= Contact 1- XX meters

Now vary contact 1 in a normal distribution. For every run, and every value of
Conatct1, Contact 3 also would get a value with a similar trend (ie high or low ).

18

August 2008

BUT this is possible only if the two parameters are having same standard deviation
(please correct me if I am wrong)

The same question goes for dependency between properties like Porosity,
permeability, saturation etc.

------------------------------

19

August 2008

2. Technology Updates

2.1 Roxar Webinars
For those of you that read the first Geomodeling Network newsletter you will
have read about Roxar’s new structural modeling software, so this is a chance to
see what all the fuss is about!

On the 28th August 2008, Roxar will be hosting a series of solution webcasts on
the following:

- RMS Structural at 10am
- Tempest for Simulation at 11am
- EnABLE for history matching at 12pm
- VVA a high end attribute package which includes seismic
interpretation at 2pm

Each webcast is designed to give you a brief insight to the functionality that the
software can provide. It should not last more than 20 minutes and will give you
the opportunity to request a full demonstration thereafter, at a time and
location convenient with you.

Please do join us for this informative event and feel free to pass this onto other
colleagues within your organization that may find this of interest.

To confirm you attendance at any of the above webinars please respond to
neelesh.ambedkar@roxar.com who will manage the logistics for the event and
will send out the appropriate web address and pass code.

-----------------------------
“Software is the only
engineering discipline
The next ppt presentation from Christian Höcker is certainly one of the first Jewel
in which the equivalent of
Suite presentations I have read and I found it interesting for a number of
changing the wing on an reasons. Firstly because they have successfully focused their technology on a
airplane problem that exists and cannot be solved using some of the existing products on
constitutes maintenance.quot; the market and secondly it’s nice to see new software from outside of the “big
2”.
by Jim Highsmith
Mitch

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August 2008

2.2 JOA – Handling of complex fault geometries using Jewel
Suite
“There are only 2 Christian Höcker – Director of G&G Technology at JOA Oil & Gas BV
industries that refer to (hocker@joa.nl)
Faulted faults are frequent in geological regions with multi-phase tectonics,
their clients as however, they can also be encountered in delta settings. Faulted faults are one
„Users‟: illegal drugs of the more challenging geometries when it comes to proper representation of
‘real geology’ in reservoir models. This article in slide format shows an example
and computer
of faulted faults in a Niger delta field using seismic data, and how it was
software” represented in framework models and geocellular grids using Jewel Suite
functionality.
Edward Tufte
It is also argued here that fault relation tables are an insufficient approach when
building framework models of so-called ‘fault-flip zones’, a frequent
phenomenon in crestal collapse structures. Fault-to-fault relationships must be
defined per intersection segment rather than for entire faults.

JOA® Jewel Suite™

Handling of complex fault geometries
in reservoir models built with Jewel Suite

• Faulted Faults
• Topology handling in fault flip zones

Christian Höcker
JOA Oil & Gas
INTE(R)MODEL – Integrated Reservoir Modelling Services

21

August 2008

Introduction
quot;640K ought to be
enough for • Faulted faults are frequent in regions with multi-phase
anybody.quot; tectonics but can also be encountered in delta settings.
• Fault-flip zones are common in crestal collapse features.
Bill Gates of Microsoft, 1981
• Both geometries are difficult / impossible to represent in
common modelling packages – or cannot be translated
from static models into simulations models.
• The following slides show examples of these geometries
in seismic interpretation, as structural framework model
and in 3Dgrid representation, using Jewel Suite.

Copyright JOA 2005-2008 ©

Faulted Fault in Jewel Suite™ Surface
(Trimesh) Representation
Modelling Workflow:
• Synthetic fault of older set is dissected
set of 4 north-hading faults
by 4 antithetic faults
• Synthetic fault has been interpreted on
seismic using fault sticks assigned to a
single fault plane
• After automated triangulation limited
user edits were applied to consolidate
the faulted base geometry
• The accurate intersection geometry
was established using semi-automated
retraction and extension functionality in
Jewel Suite™

slivers

faulted fault
S-hading


22

August 2008

Faulted Fault: Detail
Detail:
• Detail of intersection geometry
between faulted synthetic and
outermost antithetic fault of
younger crestal collapse set

outermost antithetic fault
map view of faulted fault
of younger collapse set
(interpretation is not
necessarily complete)

quot;Contrary to popular
belief, UNIX is very
user friendly. It's just
very selective about Copyright JOA 2005-2008 ©

who it's friends are.quot;
Anon.
Faulted Fault in JOA® 3Dgrid

Geocellular Gridding:
• The faulted fault surfaces have been
used as input to 3Dgridding
(100 x 100 m, 2000 - 8000 ft)
• The grid orientation was defined at
an arbitrary angle to the fault
direction.
This means that JOA® 3Dgrids are
insensitive to structural orientation
and can chosen freely to optimally
address subsequent work steps,
i.e. full-field or sector reservoir
simulation.

• Faults in the 3D grid seem to
continue too far if compared to
displayed fault surfaces. This is not a
real issue but relates to the fact how
faults are drawn on the 3Dgrid slice,
i.e. faulted cells are


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August 2008

Faulted Fault in J-slice of JOA® 3Dgrid
Geocellular Gridding:
• Slice through 3Dgrid model in J-direction (along faulted edge of synthetic fault)


Topology Handling with ‘Fault Flip Zones’

Issue:
• Crestal collapse structures
commonly show fault flip zones in
N-hading antithetic
which fault hierarchy changes.
• For fault framework building this
means that a unique abutting rule
between faults (as in fault relation
tables) cannot be defined.
blue fault is dominant at these
• In Jewel Suite™ fault-to-fault
intersection segments
relations are defined for single
intersection segments between
faults, meaning that laterally varying
topology relationships in fault flip
zones can be handled properly.
“Don't take a map
drawn at a smaller 3 S-hading
synthetic faults
scale and enlarge it
for work at a
larger scale”
synthetic faults are dominant
at these intersection segments
geologist &
cartographer proverb

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August 2008

experiment is
”An
Full-Field 3Dgrid model
considered
successful if no
more than half of
the data must be
discarded to obtain
agreement with your
theory”
The Compensation
Corollary

• The previous slides are from small features in a much bigger full-field model with the specs:
100 x 100 m, ijk dimensions of 200 x 100 x 50 cells. A final 50 x 50 m model is in preparation.
• The model geometry and properties extend to surface (not shown here) to support integrated
velocity modelling and geomechnical simulation.
• This means a new definition of ‘full-field’ to include overburden at appropriate resolution for
Copyright JOA 2005-2008 © integration loops outside the conventional static-dynamic reservoir modelling.

Do X-faults exist?

Issue:
• In radial extension geometries
the abutting relationship
between conjugate fault sets is
not always easy to determine
from seismic evidence.
• In fault flip zones one can
encounter seismic sections with
an apparent X-geometry – the
example here is a quite
convincing case.
• Obviously the X-geometry does
not extend far laterally; the grey
fault terminates some 100 m
behind this section while the
green one stops 50 m in front of
it.
However, the geometry is real
and relevant for HC containment
– fluid contacts in the reservoir
above 1600 ms differ to either
side of the X-fault geometry.
Ignoring either one of the two
faults in modelling or increasing
the gap between them would
mean a significant flaw in
reservoir definition.


25

August 2008

Summary

• Proper representation of fault geometries in framework
models and 3D (simulation) grids is a prerequisite for
effective subsurface workflows.
• In Jewel Suite it is also easy to implement:
– The 3D gridder takes fault and horizon geometries as interpreted
and turns them into high-fidelity grid models.
– The resulting 3Dgrids can be transmitted to simulators without
geometry degradation.
– Non-Neighbour Connections or fault transmissibilities are
properly handled by the software
 no tedious edits in the simulator environment.


Jewel Suite is a ‘young’ integrated workflow application for subsurface
modelling, simulation and decision making. It has been developed and is
marketed by JOA Oil & Gas, a Dutch software company with long-standing
experience in subsurface modelling, now with global support coverage.

Jewel Suite 2008 contains modules covering seismic interpretation, well log
correlation, structural framework modelling, property modelling, upscaling and
reservoir simulation, all integrated in one platform. The heart of this ‘new kid on
the block’ is the revolutionary and patented 3Dgridder that supports building of
geological and simulation models without the constraints known from the big
players in this field. Not only can complex geometries like with faulted faults be
represented in the geological models without simplification, the geometries can
also be communicated without degradation to a number of linked reservoir
simulators, among which Eclipse.

A more extensive discussion of 3Dgrid types used in geomodelling and simulation
environments is in preparation for the next edition of the Geomodelling Network
News.

------------------------------

26

August 2008

2.3 EMGS AND BLUEBACK RESERVOIR LAUNCH BRIDGE, AN EM INTEGRATION
TOOL FOR PETREL

Trondheim, 11 June 2008

Electromagnetic Geoservices (EMGS) and Blueback Reservoir have collaborated
to develop and launch a new decision-support tool for exploration professionals
called Bridge. Bridge has been created to help oil & gas companies find and
develop hydrocarbons more efficiently. The new software enables the easy
integration of electromagnetic (EM) data with other geophysical and geological
information, resulting in a clearer and more complete understanding of the
subsurface.

Terje Eidesmo, EMGS chief executive officer, said: “This is an important
milestone for EMGS and the industry. Bridge will enable our customers to
capitalise on the benefits of EM by allowing the easy integration EM information
with their workflows. By integrating EM data with conventional geophysical,
quot;Everything that can be geological and well log information, our customers can improve their
invented has been exploration risking process and the assessment of a reservoir’s potential.”
invented.quot;
Bridge is an EM plug-in for Petrel, one of the industry’s leading geological and
geophysical integration platforms. The launch of Bridge brings long-awaited EM
Charles H. Duell,
functionality to the standard Petrel workflow. Petrel was originally created and
Commissioner, U.S. Office of
developed by the founders of Blueback Reservoir.
Patents, 1899.

“We have been working with the team who created Petrel. The heritage,
expertise and experience we bring from our respective fields is an endorsement
for Bridge and the increasing demand for EM integration by the industry bodes
well for the uptake of this product. The launch of Bridge also reaffirms our
leadership in the EM sector”, continued Eidesmo.

Jan Egil Fivelstad, Blueback Reservoir’s chief executive officer, commented: “EM
data adds great value for geoscientists, and Bridge will make this technology
more accessible and understandable. There has been a growing recognition
throughout the oil and gas industry of the need for extra functionality in
interpreting EM data and as a result we expect the demand for this product to
continue to grow”.

27

August 2008

Blueback Reservoir and EMGS will be demonstrating Bridge at the EAGE, SEG
and PETEX exhibitions in 2008.

Contacts

Terje Eidesmo
EMGS chief executive officer +47 73 56 88 10

Chris Guldberg
EMGS PR manager +47 73 56 88 10

Paul Hovdenak
Blueback Reservoir, Manager Software Sales & Development +47 98 23 03 40

About EMGS

EMGS is the market leader in deep EM imaging. The company launched the EM
imaging industry in 2002 with the commercialisation of seabed logging, a proven
exploration method that uses EM energy to find offshore hydrocarbons without
drilling wells. This proprietary and patented technology has been developed
over the past 10 years, and its ability to indicate hydrocarbons directly is
enabling EMGS's customers to dramatically improve their exploration
performance in frontier and mature provinces.

EMGS employs over 300 people from three main offices in Trondheim, Norway;
Houston, USA; and Kuala Lumpur, Malaysia. The company operates the world's
largest EM vessel fleet, and has conducted more than 350 surveys for many of
the world's leading energy companies.

Please visit our website www.emgs.com for the latest news and in-depth
information about EMGS and EM imaging technology.

For general enquiries please email findinghydrocarbons@emgs.com

About Blueback Reservoir

Headquartered in Stavanger, Blueback Reservoir AS is an independent E&P
service company with offices in Stavanger and Oslo, Norway, and London, UK.
The company supplies subsurface consulting services and software solutions to
the E&P industry globally and is recognised as a leading provider of subsurface
3D reservoir modelling services and solutions. Blueback Reservoir delivers such
services to a whole range of companies, including service companies, small and
medium-sized independent E&P companies, super majors and national oil
companies.

28

August 2008

For further information, please visit www.blueback-reservoir.com or email
sales@blueback-reservoir.com

------------------------------

2.4 Petrophysical Analysis Workflows using OpenSpirit

Attached is link to a webcast to enable you to learn how to enhance your
integrated petrophysical workflows by importing curve data from any
OpenSpirit-enabled data store into your petrophysical analysis application. Data
can then be exported back to the corporate data store, or any OpenSpirit-
enabled interpretation application. A live demonstration of a workflow will be
shown during the webcast. Please either click on the link below or cut and paste
it into your internet browser.
http://www.openspirit.com/movies/Webcasts/2008%20August/Aug2008.htm

------------------------------

3. Career Networking
Another of the reasons for instigating The Geomodeling Network was to
advertise career positions that may be of interest to our members. This will
never be the major part of our newsletter as the intention is to keep it as
technically focused as much as possible. However I intend to carry on with this
section until someone convinces me otherwise.

Position: Pore Pressure Analyst
Location: Houston
Contact: Cole Wiseman on wiseman@intellicaprecruiting.com or (US)713-529-
2100

The pore pressure analyst will be responsible for supporting the Gulf of Mexico
exploration teams by applying established tools and techniques to constrain
subsurface fluid pressure regimes. Required experience includes using either 1)
basin modeling techniques, 2) offset well drilling and petrophysical analysis,
and/or 3) seismic velocity analysis to determine subsurface fluid pressures.
Candidate should have working knowledge of all above-mentioned technologies
used in pore pressure applications, and ideally, extensive experience in applying
one or more of these technologies in exploration.

The candidate should have or quickly develop the ability to incorporate basin
modeling, drilling, petrophysical, and/or seismic datasets to develop an

29

August 2008

integrated approach to pore pressure prediction. Work will be required at
multiple scales, from regional to prospect scale, including active drill-well
operations. Support regional team by developing an understanding of regional
controls on fluid pressure regimes. Support portfolio teams by performing
“A good rule of thumb is prospect evaluations of top-seal integrity and effective stress. Provide
predictions on hydrocarbon column capacity given a prediction of effective
if you've made it to
stress and a spectrum of possible fluid densities. Support active drill-well
thirty-five and your job operations from pre-drill well planning through real time modeling adjustments
still requires you to wear as drilling parameters and new petrophysical data are collected.
a name tag, you've made Roles/Responsibilities:
a serious vocational
error.” Technical focus in or practical knowledge of pore-pressure prediction from
the standpoint of basin modeling techniques
Dennis Miller
Technical focus in or practical knowledge of pore-pressure prediction from
the standpoint of seismic velocity data and geophysical attributes
Technical focus in or practical knowledge of pore-pressure prediction from
the standpoint of offset wells (drilling parameters & petrophysical data)
Perform evaluations of top-seal integrity and effective stress; provide
predictions on hydrocarbon column capacity given a spectrum of possible
fluid densities
Work with Exploration & Production Technology group to devise new
approaches and innovative solutions to complex problems confronting the
business unit
Work with both Regional and Portfolio teams in the Gulf of Mexico and
provide subsurface pore-pressure analysis at multiple scales, from regional
down to prospect level
Work with drilling and well-operations groups to support well planning
and real-time operations decisions regarding fluid pressures and borehole
stability
Effectively communicate technical workflows and results to audiences
with varying exposure to the technology, from inexperienced staff to
senior-level management

Skills/Competencies:

“It‟s just a job. Grass Apply two or more relevant workflows in pore-pressure prediction
Learn and apply technical workflows for seal-capacity analysis
grows, birds fly, waves
Have ability to adapt to solve technical problems within this technical
pound the sand. I beat specialty Work with Exploration & Production Technology to seek out
people up.” innovative approaches
Muhammad Ali Have an appreciation for technical uncertainties and be able to
incorporate their impact on modeling results
Ability to work at multiple scales

30

August 2008

Contribute to a team-oriented work environment

Required Experience:
Minimum of (5) years of related experience in the upstream oil and gas industry

Required Education:

Bachelors Degree in Geological Sciences, Masters or PhD a plus

------------------------------

Position: Product Champion – Geophysics & Electromagnetics
Location: Stavanger
Contact: Paul Hovdenak, Manager of Software Development & Sales
(paul.hovdenak@blueback-reservoir.com)

Blueback Reservoir is currently in a growth phase and we are now looking to
expand our software team and strengthen our support and technical sales. Our
new software product for integration of electromagnetic data (CSEM) with
Petrel has generated strong interest in the market place, and combined with our
further software development plans, we are now hiring a product champion to
meet our goal of bringing electromagnetic data and CSEM technology to the
masses!

The product champion position involves:
Planning our development strategies
Working with our developers to ensure our products are delivered
according to plan
Working with our sales people to ensure commercial success
Working with our clients to help them get started and utilize our solutions
successfully

Successful candidates will have:
Relevant education at MSc or similar level
Experience with Petrel or other G&G applications
Relevant industry experience within geophysics and electromagnetic
domains
Self motivated and able to act independently with minimum supervision
Willingness and ability to travel domestically and internationally

In return Blueback Reservoir can provide an interesting and challenging position,
whilst at the same time offering a highly attractive base salary and company
bonus scheme.

31

August 2008

------------------------------

4. Requests for the newsletter No3
After receiving 2 Geomodeling Network newsletters you should by now realize
the kind of newsletter we are trying to achieve. If you would like to add any
article for the 3rd newsletter (scheduled for December 2008), then simply email
me the proposed article and I will do my best to include it.

That goes for SW vendors too. If you have some new functionality coming out at
the end of the year or you have a case study you think our readers would be
interested in then forward the details to me and I will add it to the technology
section in the next newsletter.

You may have also read a previous email from me detailing a Schlumberger
training course/field trip. I do not mind advertising these type of events, but it
doesn’t mean I’ll be listing the ‘Introduction to Petrel/RMS training courses
occurring over the next few months! if there are some unique events or field
trips coming up in your region that are open to general participation then send
me the info to include in the next newsletter or as an extra email shot.

Apology
As a member of the Geomodeling Network you will have received an email from
me earlier on this month promoting the Schlumberger fracture modeling
training course/field trip. Unfortunately I issued the email without checking
where I had placed the members email details. This meant that your email
details were then made available to the other network members.

Once I realized my mistake I tried to recall the message but this only worked for
a small handful of the entire list and was therefore largely ineffective.

Based on my error a few members were contacted directly by recruitment
consultants (who are also network members), so my sincere apologies for any
discomfort and inconvenience that I may have caused and will try to do better
next time.

Regards,
Mitch
mitch.sutherland@blueback-reservoir.com

Fin
32

Modeling NTG Pitfalls

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