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Copyright 2000, Society of Petroleum Engineers Inc.
This paper was prepared for presentation at the SPE European Petroleum Conference held inParis, France, 24–25 October 2000.
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Abstract
The acquisition of gas in mud data while drilling for geological
surveillance and safety is an almost universal practice. This
source of data is only rarely used for formation evaluation due to
the widely accepted presumption that they are unreliable and
unrepresentative. Recent developments in the mud logging
industry to improve gas data acquisition and analysis has led to
the availability of better quality data.
Within a joint ELF/ENI-Agip Division research program, a new
interpretation method has been developed following thecomprehensive analysis and interpretation of gas data from a
wide range of wells covering different types of geological,
petroleum and drilling environments.
The results, validated by correlation and comparison with other
data such as logs, well tests, PVTs etc, enable us to characterise:
• lithological changes,
• porosity variations and permeability barriers,
• Seal depth, thickness and efficiency,
• Gas diffusion or leakage,
• gas/oil and hydrocarbon/water contacts,
• vertical changes in fluid over a thick mono-layer pay zone,
• vertical fluid differentiation in multi-layer interval,
• biodegradation.
The comparison between surface gas data, PVT and
geochemistry data clearly confirms the consistency between the
gas show and the corresponding reservoir fluid composition.
The near real time availability, at no extra acquisition cost, of
such data has led to:
• the optimisation of future well operations (logging, testing,
....),
• a better integration of while drilling data to the well
evaluation process,
• a significant improvement both in early formation evaluation
and reservoir studies especially for the following
applications where traditional log analysis often remains
inconclusive:
• very low porosity reservoirs,
• thin beds,
• dynamic barriers and seal efficiency,
• low resistivity pay,• light hydrocarbons.
Examples show both wellsite quicklook with simple lithological
and fluid interpretations and more complex reservoir and fluid
characterisation applications in varied geographical and
geological contexts that demonstrate how GWD data is
integrated with more standard data sets.
1. INTRODUCTION
The measurement of drilling gas data (gas shows) is standard
practice during the drilling of Exploration and Development
wells.
Continuous gas monitoring sometimes enables us to indicate, in
general terms, the presence of hydrocarbon bearing intervals but
rarely to define the fluid types (oil, condensate and/or gas,
water).
Gas data are at present largely under-utilised because they are
considered unreliable and not fully representative of the
formation fluids.
There are many reasons for this. On the one hand, poorly
established correlations between reservoir fluids and shows at
surface. On the other hand, the influence on recorded data of
numerous parameters such as formation pressure, mud weight
and type, gas trap position in the shaker ditch, mud outtemperatures, etc. One reason may be the very low cost of such
data, often equated with low value.
Until a few years ago, the analysis performed on gas shows was
generally restricted to the use of Pixler and/or Geoservices
diagrams (or equivalent), Wetness, Balance, Character and Gas
Normalisation (Pixler, 1968 Haworth et al., 1985; Whittaker &
Selens, 1987; Wright, 1996).
Recent improvements in gas acquisition technology and the new
GWD methodology allows to perform reservoir interpretation in
near real time for fluid identification and contacts (OWC, GOC,
SPE 65176
Improved Integrated Reservoir interpretation using the Gas While Drilling (GWD) dataD. Kandel, SPE, TotalFina Elf; R. Quagliaroli, SPE, ENI Agip Div.; G. Segalini, TotalFina Elf; B. Barraud, TotalFina Elf
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2 D. KANDEL, R. QUAGLIAROLI, G. SEGALINI, B. BARRAUD SPE 65176
etc.), lithological changes, barriers efficiency, thus allowing
operations optimisation (e.g. coring, wireline recording and
sampling, testing operations). It is also possible to integrate the
GWD interpretation in Reservoir, geochemical, PVT analysis and
comprehensive studies.
2 METHOD
2.1 Data Acquisition
The measurement of gas shows in the circulating drilling mud
was introduced in the early days of mud logging (ML) with two
objectives. Firstly as a safety device to indicate well behaviour
to drillers and secondly as an indicator of hydrocarbon bearing
zones. Today, gas shows measurement is systematically acquired
in the petroleum industry for the same reason but is seldom used
to its full potential, mainly due to an ongoing prejudice that the
data are not representative of the formation fluids and/or that the
recording of these data is strongly influenced by varying drilling parameters.
Since the beginning and still today, the ML gas system is
composed of three parts:
• a "GAS TRAP" to extract gas from the mud stream situated
somewhere between bell nipple and shaker box (often in the
latter)
• lines, pumps and filters enabling the transport of a dry gas
sample to the ML unit
• a detection system in the ML unit
Recent developments in the mud logging industry, to improve
gas data acquisition and analysis has led to the availability of
better quality data which can provide since roughly the 90’s
reliable lithological and fluid informations:⇒ In the 80's, most of the ML companies introduced the
flame ionisation detectors (FID) to replace previous TOTAL
GAS (TG) and chromatograph measurements. The TG
measurement gives the total amount of hydrocarbon components
extracted from the mud and burned in the detector. The TG could
now be correlated with the C1-C5 readings from the new breed
of chromatographs (Mercer, 1968).
Finally, over the last few years, several ML companies have
introduced fast gas chromatographs with improved resolution
(C1-C5 in less than one minute), improved C1/C2 separation,
and, above all, improved reliability and repeatability. High-speed
chromatographs using a thermal conductivity detector have also
appeared on the market but were not tested within this project.
⇒ Work carried out by Texaco in the early 90's led to a
significant improvement in basic trap design with the
introduction of the QGM (Quantitative Gas Measurement) trap
which was a major step in reducing the effect of environmental
changes (Wright et al., 1993). An alternative proposition from
Geoservices was to replace the trap generally situated in the
shaker box by a pumping system supplying the trap with a
constant volume of mud sucked from a probe situated close in the
flowline, to the bell nipple (De Pazzis et al., 1989).
The improved efficiency of these traps means that the gas sample
delivered to the ML unit is increasingly representative of the true
gas content of the mud and therefore of the gas associated with
the formation fluid.
The work described here relies on the systematic use of either a
QGM or a constant volume trap linked to FID TG detector and
chromatograph. The results can only be improved by the use of the above-mentioned new generation of chromatographs. Choice
of this kind of equipment implies a high level of verification,
calibration and quality control.
2.2 Gas data quality control and processing
Before describing the method, we have to stress the point that the
acquisition environment can significantly influence gas data.
Thus, it is important, before any interpretation, that the well site
geologist make sure that the gas detector calibration procedures
are respected and checks if changes have occurred in the mud
system, in drilling conditions, etc.
Concertation between the company representative and the MLcontractor is important to reduce the risk of interpretation errors.
This illustrates why the gas data Quality Control (QC) should be
done at the well site where operational conditions can be fully
detailed and annotated. It is often difficult, when the
interpretation is done at the office, to be sure that a change can be
linked to a formation or fluid change and not simply to an
operational artefact.
In the following examples, we will see how drilling parameters
changes can influence the gas data and how we can correct the
gas measurement artefact to obtain “normalised” gas ratios.
A change of the mud density, of the mud type or a bit trip can
induce sharp and localised disruption of all gas data, TG and
chromatographic responses (fig. 1). This is why we consider thatthe GWD method is still, today, a semi-quantitative approach.
But despite these drilling artefacts, the amount of all of the
components varies with the same amplitude. Thus, analysis of the
gas composition changes in percentage has to be carried out in
order to understand the relative variations between the
components. But before that, another QC concerns the lowest
threshold detection for the components, fixed by experience at 10
PPM for the most commonly used FID chromatographs. Below
this limit, values are considered as possible electrical artefacts
and could be unreliable for analysis. For the interval drilled with
an Oil Based Mud (OBM) in well A, most of the iC4 to nC5
values are below 10 PPM (fig. 1) and for GWD analysis the
values of the components were added together and the possibleunreliability was taken into account.. On the contrary, all
components in the deeper section of well A, drilled with Water
Based Mud (WBM), are above this limit. The GWD analysis will
be different for these two intervals, knowing that the best values
are within the main hydrocarbon-bearing reservoir.
The second QC is the C1/C2 separation limit. The upper
threshold limit for the separation of these two components
depends on the chromatograph type. In the case of well A, this
ratio upper limit is 80 and one interval has higher C1/C2 values,
between 80 and 100 (fig. 2). For this interval, C1 and C2 have to
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SPE 65176 IMPROVED INTEGRATED RESERVOIR INTERPRETATION USING THE GAS WHILE DRILLING (GWD) DATA 3
be added together in the GWD interpretation process.
Afterwards, the C1/C2 separation improves with depth,
especially in the interval drilled with WBM.
Considering the partial poor detection of iC4 to nC5 and the
locally poor C1/C2 separation, the general overview of well A in
terms of gas show variations use % (C1+C2), %C3 and %
(iC4+nC4+iC5+nC5). This representation denotes the more
representative gas shows in formations drilled with WBM because of the better extraction of the heavier components from
the mud. It also enables the identification of major changes in gas
composition in the OBM drilled interval which were not visible
with the raw chromatograms and which are not linked to drilling
artefacts (fig. 3).
The TG/ΣC vs. depth plot where ΣC=C1+C2+C3+C4+C5 is
another output used to verify that the gas acquisition has been
correctly carried out.
With a FID TG detector this ratio will be equal to 1 if only C1 is
present. It will be greater than 1 if the gas show contains heavy
components (fig.4).
A more useful output for QC when heavy components are
present is the TG /ΣCcor vs. depth plot where the ΣCcor is thevalue corrected for the FID response of the individual
components:
ΣCcor = C1+2xC2+3xC3+4x(i+nC4)+5x(i+nC5)
Reliable data can be qualified as being close to 1 (+/- 20%) on
this ratio. Gas data whose value on this plot is significantly less
than 0.8 is unreliable. On the contrary, values over 1.2 are
unreliable or are linked to the presence of heavy components
measured by the TG detector but not recorded by the
chromatograph. The existence of these components can be linked
to:
q the presence of organic matter,
q the presence of tight levels if we are not in a water bearing
zone,
q the presence of a hydrocarbon containing heavy components,
q the presence of a water-bearing zone or of a
hydrocarbon/water transition zone, knowing that aromatics
are more soluble in the presence of water.
In well B figs. 4 and 5, the interval around 1400 m shows, for
both ratios, a value greater than 1. This can be explained by the
presence of heavy components (C6, C7..). The production test
performed in this interval produced light oil.
The TG/ΣCcor ratio could therefore also be used as semi-
quantitative heavy gas richness indicator.
In this well B the gas acquisition is good (homogeneous data and
values close to 1).
Following QC of the gas data, the next step is to present the data
in a way that facilitates interpretation. Generally, the ML unit
output, even when it contains several different gas ratio logs,
remains raw data. The method used in this project consisted in
applying techniques often used in wireline log analysis to gas
data. The techniques include:
• eliminating and/or correcting poor quality data,
• using multiple ratio logs and crossplots in order to define the
most discriminating ratio for a particular problem,
• using normalised TG (NTG) to eliminate "environmental"
effects such as drill rate, mud flow and borehole diameter,
• using various techniques to improve the signal to noise ratio
(changing sampling rates, averages etc.),
• using "cut-offs" to eliminate shaly or tight zones, for
example on C1/C2 and TG/ΣCcor ratios. The TG vs. % C1
crossplot (or % (C1+C2)) depending on the C1/C2 separation
limit) enables differentiation high background gas levels
giving a hydrocarbon signature, where the points are
organised along trends, from low TG values where
lithological effects or drilling artefacts are illustrated by
scattered points (fig. 6). The limit between the scattered
points and the organised trends corresponds to the cut-off at
TG > 21000 PPM for fluid representative points. This
crossplot demonstrates three trends corresponding to three
different fluid behaviours well C (fig. 6).
Thus, QC initiates the first level of interpretation.
Tests on a very large number of wells have led to a simplified
catalogue of ratio logs and crossplots and their applications (Fig.
7). However this list is by no means exhaustive and the
interpreter should not hesitate to multiply the different ways of
displaying the data. The use of up to date computing techniques
can be easily obtained from most ML companies.
3 GAS RATIO LOG AND CROSSPLOT
INTERPRETATION
Following the QC of the data and the preparation of the various
ratio logs and crossplots the processes of analysis and
interpretation can begin. These processes should respect the
following "philosophy":
• interpret ratios vs. depth (their changes, not their absolutevalues) along the whole well profile
• always cross check results with other ratios and crossplots
• use cut-offs for reservoir and fluid behaviour analysis
• accept no ties with fixed interpretative models
• if possible integrate the gas data with all available well data
(tests, electric logs, etc.)
• maintain a critical approach
A plot of ratios vs. depth creates a gas log, which can be directly
compared with FEWD and wireline logs and then integrated in
composite log plate. The other data available from mud logging
such as lithology, drilling rate, calcimetry and fluorescence are
also fundamental to the interpretation process.
This process can be subdivided into two relatively distinct steps
allowing operators to treat the same data at two different levels of
analysis.
The first, called “basic interpretation” including QC, should be
essentially performed at the well site in real time to support well
operations.
The second step, “advanced interpretation”, is usually carried out
in the office where more information (general studies, regional
data) and the integration with different professionals and
approaches is possible. In addition, lack of time and operational
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4 D. KANDEL, R. QUAGLIAROLI, G. SEGALINI, B. BARRAUD SPE 65176
pressure will often limit the intervention of well site personnel.
3.1 Basic interpretation
Lithological aspects
The amplitude and the composition variations of gas shows can
be directly related to the rock's porosity, lithology and fluid
content. Trend breaks and gas composition changes and their
evolution, can, in many cases, be related to lithology changes.
The ratios used for this purpose are mainly the %C1 (or C1/ ΣC)
and TG/ΣC. Other ratios such as (C4+C5)/(C1+C2) and C1/C3 or
C2/C3 vs. depth are also useful for identifying the main changes.
In the fig.8, the arrows on the %C1 ratio log indicate the main
lithology changes in well “D” which have been confirmed by
wireline log interpretation and petrographic analysis. The sharp
breaks on the trend, reflecting the variations of gas composition,
are directly related to lithology changes (Beda et al., 1999).
The gas composition of the upper part of well A shows three
main tendencies. From the top to the bottom, the gas becomes
heavier with depth, then lighter and then heavier again (fig. 9).
The three trends are affected by smaller breaks corresponding to
lithology changes identified by the wellsite geologist and/or to
important TG variations. These breaks of secondary order are
interpreted as lithology changes. The combination of these gas
show composition breaks and the main TG intervals allow us to
distinguish five main gas response intervals, delineated by
colours. The five intervals are seen on the (C1/C3) vs. (C2/C3)
crossplot and probably reveal three different background gas
behaviours (fig. 10) confirming the complexity of hydrocarbon
migration pathways and kitchen of well A suggested by other
techniques such as organic geochemistry.
Fluid contacts
Within a reservoir, a sharp change in a ratio followed by a
stabilisation at a significantly different value generally means the
presence of a possible fluid contact (OWC, GOC, GWC....).
Whether the value is higher or lower than the previous section
will obviously depend on the type of fluid contact and the ratio
used.
To determine if the change is related to a hydrocarbon/water
contact, it is necessary to integrate the ratio with the evolution of
the TG or NTG (figs. 11 and 12). If the TG or NTG strongly
decreases, it means, in most cases, the passage of a
hydrocarbon/water contact.Furthermore, fluorescence information will reduce uncertainties.
Fluid evolution with depth:
The %C1 ratio log is also used in the examples of figures 13 and
14 to illustrate how gas shows may or may not indicate a gradual
fluid change within a reservoir. Figure 13 shows a clear trend
indicating a variation in fluid composition with depth. In fact,
due to the combined effects of pressure, temperature and gravity
(thermogravitational equilibrium), the fluids in any continuous
reservoir will tend to become heavier with depth. In such a case
the gas information should lead to a specific fluid sampling
programme as one fluid sample will not be enough to
characterise the reservoir fluid.
Figure 14 shows the opposite case where no fluid evolution is
apparent from the %C1 ratio. The variations observed are
strongly dependent on the type and composition of hydrocarbon
present.As explained before the TG/ ΣCcor ratio can indicate a transition
zone between hydrocarbon and water. The combination with TG
or NTG supports the interpretation proposed for Well C. From –
2358 m to –2366.5 m, within a clean sandy interval, TG
decreases progressively whereas TG/ΣCcor increases from –2362
m, exceeding the 1.1 upper threshold limit defined for the ratio
at–2366.5 m and then is continuously increasing with depth (fig.
15). The final interpretation gives a HC/water transition zone
between –2358 m and –2366.5 m containing two zones of
different residual oil saturation intervals, -2358/-2362m and –
2362/-2366.5 m.
Cap rock efficiency:
Figure 16 is an example of the use of gas shows to indicate the
efficiency of a cap rock. In this case the %C1 ratio is plotted
against depth in an oil-bearing reservoir. A gradual increase in
C1 with respect to the heavier components from the OWC to the
top of the reservoir is observed. This lightening trend continues
roughly 30 m. into the shaly cap rock indicating that the seal is
only partial in this section. The true cap rock is situated 30 m.
above the reservoir top.
In fig.17 a log of the same ratio from another well clearly
indicates that the cap rock above the reservoir and the shale
separating the two reservoirs both have satisfactory sealingefficiencies.
As in the general GWD approach, combination of different ratios
and other data can help in the interpretation. In fig. 18, two cap
rocks are deduced from %C1 changes, from strong decreases of
TG and from a shift of the estimated pore pressure regime. The
upper porous intervals indicate a slight vertical gas leakage.
Knowledge of cap rock efficiency is only partial at best and the
information procured from gas shows will lead to a better
understanding of the petroleum system.
Biodegradation:
The ratio of iC5/nC5 is a good indicator of biodegradation. This
ratio is generally superior to 1 for biodegraded oils. Figure 19
shows a sharp increase in the value of this ratio on entering the
R11 reservoir. Laboratory analysis of the oils confirmed that they
were biodegraded. In this case the reservoir was one of several
over a large interval.
This information would obviously influence both the test
programme and the detailed lab measurements to be carried out
on the fluids.
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SPE 65176 IMPROVED INTEGRATED RESERVOIR INTERPRETATION USING THE GAS WHILE DRILLING (GWD) DATA 5
3.2 Advanced interpretation
Despite the progress described in this paper in the domain of gas
show analysis, it is still hazardous to attempt to precisely predict
the nature of the hydrocarbon encountered. One of the main
reasons for this is that gas shows are representative of the gas
associated with the hydrocarbon and not of the hydrocarbon
itself. The gas associated with an oil may be dry or rich from case
to case. Without other data such as fluorescence or wireline logs
hydrocarbon type prediction remains difficult.
Gas shows do, however, give an excellent image of the way the
fluids change with depth thus allowing a qualitative evaluation.
This data source can be extremely precious, notably in the case of
multilayered reservoirs.
Following calibration using production test or WFT (wireline
formation test) results it may even be possible to attain a
quantitative evaluation.
Case 1 – Field depletion identification (Well C)
The main target of well C was to recognise a deep sand channel
not reached by the two first wells, which have been producing for
ten years. The production induced a shallowing of the WOC of
about 30 m. The pressure tests study on well C concluded in a
decrease of 42 bars of the formation pressure compared to the
other producing wells. A GWD analysis was carried out to
confirm the connectivity of the sand channel of well C to the
other producing reservoirs, to identify the actual OWC and to
confirm or not the presence of a secondary GOC generated by the
depletion.
Figure. 20 shows that the TG response within the reservoir of
well C is mostly linked to the reservoir quality except at the top,
around 2305 m in degraded facies and at the bottom of thereservoir, where TG decreases progressively in a clean sand
interval. Figure 20 also illustrates that the gas show composition
(%C1) varies rapidly with depth. Applying cut off on TG and
TG/ΣCcor (see fig. 6 & 15) the %C1 and %C3 ratios on figure 21
better illustrate this tendency for the gas shows to become rapidly
heavier with depth but not in a continuous manner. For the upper
part of the reservoir, the gas shows composition is lighter below
some of the barriers identified with the combination of TG and
(C4+C5) / (C1+C2) ratios. From 2340 m, for the lower part of
the reservoir, this phenomenon is not observed. On the contrary,
for the bottom of the reservoir, the associated gas composition
changes abruptly in two main steps at 2358 m and 2362 m. At
2358 m, TG starts to decrease progressively (fig. 20) and at 2362m, the TG/ΣCcor values increase progressively from 1 to reach
1.1 at 2366.5 m. These ratios changes and tendencies are
characteristic of a hydrocarbon/water transition zone.
The vertical gas show composition evolution is demonstrated
with the TG vs. %C1 crossplot on figure 22. Four fluid
behaviours are differentiated:
q The gas cap with the lightest gas composition
q The upper part of the reservoir
q The lower part of the reservoir below a significant tight level
(2340- 2342 m)
q The transition zone, which could be divided into two
different oil saturation intervals.
Despite the identification of many tight levels limiting the
vertical free gas saturation and thus the fluid equilibrium in the
well and not acting as major dynamic barriers, the final
interpretation confirmed the depletion of the reservoir. The
depletion generated three phenomena :
q a raising of the initial WOC of about 9 meters for well C,from 2366.5 m to 2358 m ;
q the degassing of the oil : the hydrocarbon column seems to
be below the initial bubble point. The strong variations of
gas shows composition are linked to an increase of the
saturation in free gas along the column. The barriers slow
down the vertical gas migration and induce a increase of the
lightest components below these barriers for the upper part
of the reservoir;
q creation of a « secondary » gas cap. The Neutron/Density
gas effect on electric logs confirms this interpretation and the
pressure measurements give a similar GOC.
The integration of gas data with electric logs interpretation
confirms the lithological and fluid contacts interpretation (fig.23). The added value of such a composite approach is the
illustration of the fluid behaviour evolution with depth. In a near
future, the combination of GWD with electric log interpretation
should enable a more quantitative interpretation approach in
terms of porosity and fluid type identification.
Case 2 – Field Reservoir model (Well L)
This is another example where gas shows can be used to identify
tight beds, which may behave as potential dynamic barriers
during production.
As a general rule major gas shows indicate fluid variations and
minor shows indicate lithology, supposing the well equilibrium isconstant. The transition from reservoir facies to tight facies or
shale often leads to an increase in the heavier components of the
show (see § 3.1). Simultaneous analysis of two logs against
depth, TG or %C1 and (C4+C5)/(C1+C2) enables, within a
continuous reservoir section, the identification of zones
containing little or no hydrocarbons. Barrier identification can be
carried out when the gas show is no longer characteristic of the
fluid. This method cannot be applied in the water-bearing zone of
the field in question because gas behaviour in aquifers is very
similar to that in the tight zones.
Case history:
The case presented corresponds to a development well on agas/light oil field with a thick sandy carbonate reservoir. The
study covered several wells in the same field and the results were
compared with the geological model of the reservoir.
The method used is qualitative. On the left-hand side of figure 24
the overall fluid evolution with depth is indicated by a base line
on the (C4+C5)/(C1+C2) ratio log. If this ratio is above 0.03 then
the zone is considered to be a barrier (confidence=100%). Any
values significantly to the right of the baseline but not reaching
the defined cut-off are considered uncertain barriers (confidence
= 50%).
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6 D. KANDEL, R. QUAGLIAROLI, G. SEGALINI, B. BARRAUD SPE 65176
On the right hand side of the figure we represent the permeability
barriers from the gas interpretation compared with the apparent
barriers from wireline log (density-neutron) porosity cut-off and
barriers retained in the reservoir model following the wireline log
interpretation. The definition of tight beds from logs was based
on a cut-off of 8% porosity.
On the same figure, on a scale from -100 to +100 bars, we have
indicated the difference between initial reservoir pressure and theWFT results of the development well in question.
Interpretation and application to the model
On the whole, a good correlation exists between the tight beds
identified from gas shows and the permeability barriers defined
in the model .
In the upper, gas bearing, section of the reservoir the porosity log
cut-off indicates several potential barriers whereas gas shows
show a reduced number of uncertain barriers. The defined
reservoir model correlates more closely with the gas shows than
with the log cut-off. Barriers defined from wireline logs appear,
in this gas zone, too pessimistic.
The WFT results illustrate the pressure effects of the production process; increase in pressure in the gas zone due to gas injection
and depletion in certain levels of the oil zone. These results also
clearly indicate where the most important permeability barriers
are situated. Here again gas show interpretation gives a better
overall fit than conventional log interpretation. Even the small
change in depleted pressure at X420 can be identified.
The gas analysis indicates barriers in conformity with the fluid
flow in porous media. These barriers indicate the reservoir to be
less heterogeneous than the porosity cut-off method suggested.
Therefore the values of the vertical permeabilities should be
reviewed and increased, as the kv's used in the model are
deducted from a porosity-permeability relationship.
A review of the reservoir model following the gas showinterpretation on a large number of wells throughout the field has
led to the suppression of many barriers indicated by logs in the
gas zone and to the limiting of the extension of certain barriers in
the oil zone.
This example clearly illustrates that gas show interpretation can
make significant contributions to the reservoir model definition
and to the understanding of the reservoir behaviour.
Case 3 –Dynamic Units Field correlations
This GWD study case was launched in order to obtain any fluid
and compartmentalisation informations not seen on wire-line logs
on a complex field by using only the GWD data acquired duringdrilling.
The given lithologic, reservoir and fluid informations were as
follows:
q The source rocks situated just above the reservoirs (SR 2 &
1) were considered as the cap rock,
q From the bottom to the top, four reservoir units were
defined, R4, R3, R2 and R1. The four reservoir units are
hydrocarbon bearing but only the two upper ones were
considered to have good reservoir characteristics,
q only one type of fluid was considered for the whole reservoir
section, evolving normally with depth, i.e. becoming heavier
with depth: successfully tested gas-condensate in R2 and R1
only and a possible, but unsuccessfully tested, gas zone in
the R3 of some wells,
q a strong lithological barrier, roughly located in the upper R3
and basal R2 units, acting as a possible barrier to
hydrocarbons of the R4 degraded unit,
q Many fluid contacts, varying or not from one well toanother.
The main conclusions for the reservoirs are as follows.
The supposed fluid contacts are partially confirmed, invalidated
or not identified, because they are situated within tight zones.
From gas show analysis, it seems difficult to represent the whole
hydrocarbon-bearing interval by a unique fluid behaviour type.
Its characteristics would be probably dependent on its vertical
and structural location. In fact, the fluid behaviour is not constant
with depth and the R4 unit has apparent medium to good
reservoir characteristics.
Three fluid behaviours are defined (fig. 25):
q In the bottom part of the reservoir interval, the fluid is thelightest and is getting lighter with increasing depth. This
zone concerns the R4 and the lower R3 units, which are
apparently in continuity.
q In the upper part of the reservoir, the fluid is the heaviest.
The gas composition has a normal evolution, becoming
heavier with depth, according to the gravitational
segregation. This zone concerns mainly the R1 layer.
q In the intermediate part, the fluid characteristics seem rather
constant. This zone concerns mainly the R2 and the basal R1
layers.
We can distinguish two possible dynamic intervals:
one in the R4-R3 layers, corresponding to “Fluid 2”,
one in the R2-R1 layers, including “Fluid 1.2” and “Fluid 1”. The existence of these two dynamic units is supposed because:
q a strong lithological barrier, roughly located in the upper R3
and basal R2 units, separates the lower and the intermediate
zones (fig. 25);
q The intermediate and the upper fluid types are very similar
in composition if compared to the lower fluid type.
The PVT results of the last well test sample are in line with these
conclusions. At least two possible hypotheses are considered:
1. existence of two hydrocarbon sourcing and migration
pathways:
q a per-descencum sourcing from the source rocks SR 2 & 1 to
fill the R2-R1 layers;q a permanent gas flow from an unexplored deeper source rock
filling R3 and R4.
A slow percolation of this deeper fluid through the R3-R2 tight
interval could create a mixed fluid zone in the middle of the
upper dynamic unit (R2-R1).
2. Presence of a cracking effect below a certain depth or
temperature level in the lower part and a gravity segregation in
the upper part.
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SPE 65176 IMPROVED INTEGRATED RESERVOIR INTERPRETATION USING THE GAS WHILE DRILLING (GWD) DATA 7
The main conclusions for the overlaying source-rocks and
seals are as follow:
q The two source-rocks SR 2 and 1 are characterised by
different background gas compositions.
q If the main source-rocks are probably acting as cap rocks,
they do not ensure the total seal of the system. The main seal
for hydrocarbon and pressure regime is assumed by
Formation 3 (fig. 25) situated approximately 150 m higher than the source rocks. A secondary and final seal is situated
at the base of Formation 1 (figs. 18 & 25).
q The gas inducing pressure is leaking/diffusing mainly
through Formation 3, which is acting as a “pressure filter”.
Thus, little gas shows occur in two homogeneous (porous?)
intervals in Formation 2 (fig. 18). These gas peaks are higher
when the Formation 3 is thin (well 1: 40m thick).
4. CONCLUSIONS
The method described in this paper brings together know-how
from a wide variety of disciplines such as well geology, reservoir
engineering, thermodynamics, geochemistry and sedimentology.It enables the definition, for each well studied, of two well
profiles. One reflects lithology variations, the other fluid
variations.
Repeatable applications for the interpretation of both profiles
have been identified.
Lithology variations
• cap rock and reservoir quality
• tight zones
• Low Resistivity Sands
• thin bed evaluation
• geosteering using gas while drilling
Fluid variations
• contacts and transition zones
• vertical fluid evolution
• identification of thermodynamic units
• gas leakage or diffusion
• biodegradation
This information, obtained in near real time and at no extra
acquisition cost, enables the optimisation of future logging and
testing programs and will significantly reduce uncertainties in
geologic and reservoir models.
The data, both raw and as ratios, is easily available from thewellsite in formats that allow a rapid integration with wireline
logs and other data into the global interpretation process.
Although major improvements have been made in the acquisition
and interpretation domains there remain a number of
uncertainties linked to the drilling environment and the effects of
dissolution and adsorption / desorption. Therefore, as is true for
most data acquisition techniques, there is room for improving the
environmental corrections to the data. As with the great majority
of well data, the gas log cannot be interpreted alone and requires
integration with all well data available.
However, in many cases, where traditional wireline log
interpretation leaves doubts about the presence of reservoirs or
their fluid content, gas log interpretation may reduce the
uncertainty. This is particularly true in the case of:
• very low porosity reservoirs
• thin and multi-layer reservoirs
• Low Resistivity Pay
• light hydrocarbons (especially when associated with the
previous three)
• depleted reservoir.
The contribution of gas show interpretation to the complete
reservoir interpretation should lead to a better estimation of the
volume of hydrocarbons in place.
At any stage in the currently accelerating Exploration/ Production
cycle, adding value to the earliest and most cost-effective data at
our disposal is essential. Gas while drilling is an excellent
candidate to help us do just that.
ACKNOWLEDGEMENTS
The authors wish to thank the management of ELF EP and ENI-
Agip Div., and their different operating subsidiaries for
permission to publish this paper and the data it contains resulting
from a joint research project into mud gas interpretation. We
would also like to extend our appreciation to Alain Louis and
Alan Mitchell ELF EP, Giulio Beda, Carlo Carugo and Dario
Manfroi, ENI-Agip Div, and the other members of the joint
ELF/ENI-Agip "Well Data Acquisitions" project for their helpful
ideas, reviews and encouragement. Our thanks also go the
SPWLA for their permission to publish some of the figures and
explanations from last year’s paper given in OSLO.
REFERENCES
Beda G., Quagliaroli R., Segalini G., Barraud B. & Mitchell A., 1999,
Gas While Drilling (GWD) ; A Real Time Geologic and Reservoir Interpretation Tool, 40Th Annu. SPWLA Logging symp, Oslo, Norway,
711732
De Pazzis L.L., Delahaye T.R., Besson L.J. & Lombez J.P, 1989, New
Gas Logging System Improves Gas Shows Analysis and Interpretation,SPE Annual Conference, SPE 19605
Haworth J.H., Sellens M. & Whittaker A., 1985, Interpretation of
Hydrocarbon Shows Using Light (C1-C5) Hydrocarbon Gases from
Mud Log Data,. AAPG Bull.V.69, No.8, p.1305-1310.
Mercer R.F., 1968, The Use of Flame Ionisation Detection in Oil
Exploration, 2nd CWLS Formation Evaluation Symposium.
Pixler B.O., 1968, Formation Evaluation by Analysis of HydrocarbonRatios, 43rd Annual Meeting SPE, Houston, n.2254.
Wright A.C., Hanson S. A. & De Laune P. L., 1993, A New Quantitative
Technique for Surface Gas Measurements, SPWLA 34th Annual
Logging Symposium.
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8 D. KANDEL, R. QUAGLIAROLI, G. SEGALINI, B. BARRAUD SPE 65176
Wright. A.C., 1996, Estimation of Gas/Oil Ratios and Detection of
Unusual Formation Fluids from Mud Logging Gas Data., SPWLA 37th
Annual Logging Symposium.
Whittaker A. & Sellens G., 1987, Advances in Mud Logging - 2,Analysis uses alkane ratios from chromatography, Oil & Gas Journal,
May 18th, pp 42- 49.
Whittaker A., 1991, Mud Logging Handbook, Prentice Hall
ABOUT THE AUTHORS
Denis Kandel is currently the GWD leader for ELF EP in Pau,
FRANCE. After graduating in geology from the IGAL, France,
and a Doctorate thesis in structural geology from the University
of Paris in 1992, he joined ELP EP the same year. His career
with ELF has covered periods in wellsite geology, regional
geological synthesis, prospect definition and geologist in the
Deep offshore team for ELF Nigeria during two years.
Roberto Quagliaroli is at present Leader for Surface Logging
Development in ENI-Agip Operations Geology Dpt. in Italy.
After graduating in geology from the University of Parma in
1975 he worked for Geoservices, Halliburton and Pergemine. He
joined Agip in 1980 where he has worked in various assignments
in North Sea, West and North Africa in Operations Geology and
Formation Evaluation.
Gérard Segalini is currently a member of ELF EP's fluid study
group in Pau, FRANCE. He is a graduate reservoir engineer from
the ENSPM in Paris and for several years was an operations
reservoir engineer in ELF's West African subsidiaries.
Bernard Barraud graduated with prospecting geologist's diplomafrom the Henri Loritz School in Nancy, FRANCE. His career
with ELF has covered periods in wellsite geology, prospect
definition and sedimentology. He is currently applying the
methods described here on behalf of ELF's operating
subsidiaries. He is based in Pau, FRANCE.
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SPE 65176 IMPROVED INTEGRATED RESERVOIR INTERPRETATION USING THE GAS WHILE DRILLING (GWD) DATA 9
Fig. 1 Chromatogram vs. Depth plot
Fig. 3 % of the components vs. Depth plot
Fig. 2 TG and C1/C2 vs. Depth plot
CHROMATOGRAM
1550
2050
2550
3050
3550
4050
4550
1 10 100 1000 10000 100000
TG (in ppm)
D E P T H
1 10 100 1000 10000 100000
Bit runs
TG
C1
C2C3
iC4
nC4
iC5
nC5
C1, C2, C3, iC4, nC4,
iC5 & nC5 (in ppm)
Oil
Based Mud
Water
Based Mud
Fig. 1
Lower limit
of representative
values for Chromatogram
WELL A
1550
2050
2550
3050
3550
4050
4550
0 10000 20000 30000 40000 50000
C1 sur C2
D E P T H M
0 20 40 60 80 100 120
Bit runs
TG
Bit runs
C1 over C2
Upper limit of C1 / C2
good separation
TG en ppm
QUALITY CONTROL
TG & (C1 / C2)
Oil
Based Mud
Water
Based Mud
Fig. 2WELL AQUALITY CONTROL
TG & (C1 / C2)
1550
2050
2550
3050
3550
4050
4550
53 63 73 83 93 103(%C1+%C2)
D E P T H M
0 10 20 30
Bit runs
%(C1+C2)
%C3
%(iC4+nC4+iC5+nC5)
%C 3 & (%iC4+nC4+iC5+nC5)
%(C1+C2), %C3 & %(iC4+nC4+iC5+Nc5)
Oil
Based Mud
Water
Based Mud
Fig. 3% OF COMPONENTS
Major Changes in
Gas composition
WELL A% OF COMPONENTS
%(C1+C2), %C3 & %(iC4+nC4+iC5+nC5)
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10 D. KANDEL, R. QUAGLIAROLI, G. SEGALINI, B. BARRAUD SPE 65176
TG/ΣC
0
200
400
600
800
1000
1200
1400
1600
1800
2000
2200
2400
2600
0 1 2 3 4 5
D E P T H ( m )
Fig. 4 TG/ΣC vs. depth plot (with courtesy of SPWLA)
Fig. 6 TG vs. % (C1+%C2) cross plot
TG/ΣCcor
0
200
400
600
800
1000
1200
1400
1600
1800
2000
2200
2400
2600
0 1 2 3 4 5
Fig. 5 TG/ΣCcor vs. depth plot (with courtesy of SPWLA)
WELL CQUALITY CONTROL & FLUID REPRESENTATIVE POINTSTG vs. (%C1 +%C2)
85
87
89
91
93
95
97
99
0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 110000 120000 130000
TG
% C 1 + % C 2
Lower threshold for "fluid" representativepoint: Cut_off TG @ 21,000 ppm
Lithological
effect or
unreliable data
Three different
fluid behaviours
No cut-off applied
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SPE 65176 IMPROVED INTEGRATED RESERVOIR INTERPRETATION USING THE GAS WHILE DRILLING (GWD) DATA 11
Fig. 7 Typical gas ratio logs &
crossplot applications
Fig. 8 Arrows indicate the main lithology changes.
Good correlations are observed between the %C1 ratio
and log and the wireline logs (with courtesy of
SPWLA)
Fig. 9 TG and % (C1+C2). Strong lithological effect with
gas show composition variations
•Chromatogram QC
•C1 / C2 QC
•TG / ΣC QC
•TG / ΣC corrected QC, litho , fluid,..
•(C1 / Σ C), (C2 / Σ C), etc, … QC, litho , fluid,..
•TG vs. (C1 / Σ C) QC, fluid
•C1 / C3 litho, fluid,..
•(C4 + C5) / (C1 + C2) & TG litho
•iC5 / nC5 biodegradation
•(C1 / C3) vs. (C2 / C3) luid
•(C4 + C5) / (C1 + C2) vs. (C1 + C2) / C3 luid
•etc,...
WELL ALITHOLOGICAL ASPECT
TG & % (C1+%C2)
Porous levels, Vertical Gas Diffusion& Lithology changes
1550
1650
1750
1850
1950
2050
2150
2250
2350
2450
2550
2650
2750
2850
2950
3050
3150
3250
3350
3450
0 10000 20000 30000 40000 50000
TG in ppm
D E P T H M
94 95 96 97 98 99
TG
Bit runs
%(C1+C2)
% (C1+C2)
Gas diffusion from
the main (deeper) reservoir
2675 m/RT: seal of diffusion
See figure 10
for color code
OWC @ 2220 m/RT ?
Lithology
change
(sedimentary
sequence ?)
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12 D. KANDEL, R. QUAGLIAROLI, G. SEGALINI, B. BARRAUD SPE 65176
Fig. 10 (C1/ C3) vs. (C2 / C3) cross plot showing two
different gas shows behaviours
Fig. 11 TG vs. depth log showing reservoir
boundaries and contacts (with courtesy of SPWLA)Fig. 12 %C1 vs. depth log with reservoir boundaries
and contacts (with courtesy of SPWLA)
TG m
1850
1875
1900
1925
1950
1975
2000
2025
2050
0 50000 100000 150000 200000 250000
D
EP
T
GOC
BOTTOM RESERVOIR
TOP RESERVOIR
OWC
C1/ΣC
1850
1875
1900
1925
1950
1975
2000
2025
2050
0 10 20 30 40 50 60 70 80 90 100
DEP
T
TOP RESERVOIR
GOC
OWC
BOTTOM RESERVOIR
WELL ALITHOLOGY ASPECT &
BACKGROUND GAS BEHAVIOUR DIFFERENTIATION
(C1 / C3) vs. (C2 / C3)
C1 / C3
C2
/C3
0
2
4
6
8
10
0 100 200 300 400 500 600 700
Cut-off
TG > @ 13.000 ppm
and
0.9 < TG/Sccor < 1.1
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SPE 65176 IMPROVED INTEGRATED RESERVOIR INTERPRETATION USING THE GAS WHILE DRILLING (GWD) DATA 13
Fig. 13 Example of fluid evolution with depth within
a mono-layer reservoir (with courtesy of SPWLA)
Fig. 15 TG and TG/ΣCcor vs. depth plot
Fig. 14 Example with stable C1-C5 composition
throughout the reservoir (with courtesy of SPWLA)
Fig. 16 Example of poor sealing capacity of
The cap rock (with courtesy of SPWLA)
C1/ΣC
1450
1500
1550
1600
1650
1700
1750
0 10 20 30 40 50 60 70 80 90 100
DEP
T
TOP RESERVOIR
OWC
C1/ΣC
1400
1450
1500
1550
1600
1650
1700
1750
1800
0 10 20 30 40 50 60 70 80 90 100
DEPT
TOP RESERVOIR
OWC
2290
2310
2330
2350
2370
2390
0 20000 40000 60000 80000 100000 120000 140000
C1 sur C2
D e p t h m / T V D S S
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 2.1 2.2
TG
TG over sumCcor
Lower limit of data quality
-2362 m
FLUID EVOLUTION with DEPTH
TG & TG / SCcor
Fig. 15
Continuous Increase
-2366.5 m
TG/Sccor
-2358 m
C u t - o f f T G @ 3
4 0 0 0 P P M
WELL C
Lower limit of
data quality
or detection of
heavy components
C l e a n r e s e r v o
i r
D e g r a
d e
d
r e s e r v o
i r
TG in ppm
WELL CQUALITY CONTROL & FLUID EVOLUTION
TG & TG / SCcor
C1/ΣC
1850
1875
1900
1925
1950
1975
2000
2025
2050
2075
2100
2125
2150
0 10 20 30 40 50 60 70 80 90 100
DEP
T
CAP ROCK
SHALE NOT SEALING
TOP RESERVOIR
BOTTOM RESERVOIR OWC
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14 D. KANDEL, R. QUAGLIAROLI, G. SEGALINI, B. BARRAUD SPE 65176
Fig. 17 Example of good sealing capacity of the cap rock
and the interbedded shale (with courtesy of SPWLA)
Fig. 19 Example of biodegraded oil-bearing reservoir
Fig. 18 Example of good sealing capacity of the
uppermost cap rocks over the source rock
C1/ΣC
1550
1575
1600
1625
1650
1675
1700
1725
1750
1775
1800
0 10 20 30 40 50 60 70 80 90 100 110
DEPT
CAP ROCK SHALE 1
RESERVOIR 2
RESERVOIR 1
BARRIER SHALE 2
OWC
BOTTOM RESERVOIR 2
Well K
5200
5250
5300
5350
5400
5450
5500
5550
5600
5650
5700
5750
5800
5850
5900
5950
0 20 40 60 80 100 120
D e p t h ( m D / R T )
0.2 0.7 1.2 1.7 2.2
TG/500
%C1
Av. Est. Pore Pres.
Bit runs
GWD ANALYSIS
CAP ROCKS EFFICIENCY
TG, %C1 & Estimated Pore Pressure
R E S E R V O
I R
5410 m
S O U R C E - R O C K
TG/500 & %C1
Seal
Seal
5478 m
5260 m
5277 m
Porous
intervals
Est. Pore Pressure (sg)
Slight Gas &
Pressure leakage
Fig. 18WELL KCAP ROCK EFFICIENCYTG, %C1 & Estimated Pore Pressure
% iC5/nC5
1800
1850
1900
1950
0 0.5 1 1.5 2 2.5
Gas
R6
R3
R8
R9
R10
R11
R2
BIODEGRADATION
1600
1650
1700
1750
S T O N G
GOC Log
OWC Log
NOBIODEGRADATION
D e p t h m / t r
W E A K
WELL GBIODEGRADATION IDENTIFICATION
% (iC5 / nC5)
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SPE 65176 IMPROVED INTEGRATED RESERVOIR INTERPRETATION USING THE GAS WHILE DRILLING (GWD) DATA 15
Fig. 20 TG and %C1 ratios vs. depth. Background
gas related to reservoir quality and strong
gas shows composition variation
Fig. 22 TG vs. %C1. Fluid behaviour differentiation
Fig. 21 %C1 and %C3 vs. depth.
Fluid behaviour evolution with depth
2290
2300
2310
2320
2330
2340
2350
2360
2370
2380
2390
2400
0 20000 40000 60000 80000 100000 120000
TG
D e p t h m / T V D S S
80 85 90 95 100
WO C
Bit runs
TG
%C1
WOC uncertainties
Gas Cap
presence ?
TG & %C1
%C1
Reservoir
quality
uncertainties
WELL C Fig. 22
Sand
Silty Sand
Argilaceous Silt
Shale
Top réservoir depth
uncertainty
WELL CTG & %C1WELL C
FLUID BEHAVIOUR IDENTIFICATION
%C1 & %C3
2290
2300
2310
2320
2330
2340
2350
2360
2370
2380
2390
2400
80 85 90 95 100%C1
D e p t h m / T V D S S
0 2 4 6 8 10
Cut_off
TG > 21.000 ppm
0.9<TG/C15c<1.1
Tight
ZoneFluidBehaviour
GOC @ 2303.5 m/TVD
2362m/TVD
Zoneprobably
while
degassing
Probablygasbearingzone
Transitionzone
Water inflow
Oil sat. ?
2358m/TVD
%C3
FWL @ 2366.5 m/TVD
Topwellbarrier
Sand
Silty Sand
Argilaceous Silt
Shale
Zone probably
belowinitialbubble point:
highfree gassaturation
TopFieldbarrier
8 0
8 2
8 4
8 6
8 8
9 0
9 2
9 4
9 6
9 8
100
0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 110000 120000 130000
TG
% C 1
Zone 1: Gas cap
Zone 2: Free gas saturated oil
Zone 3: Free gas saturated oil
Zone 4: Probably degassing oil
Zone 5: Oil / Water Transition zone
lithology
effect or
unreliable
data
Gas
Free gas saturated oil
Probably degassing oil
No cut-off
Oil / Water
Transition zone
Threshold
limits of fluid
representative points
Cut_off TG @
21,000 ppm
o r
34.000 ppm
WELL CFluid behaviour differentiationTG vs. %C1
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16 D. KANDEL, R. QUAGLIAROLI, G. SEGALINI, B. BARRAUD SPE 65176
Fig. 23 Wireline and GWD data – Composite log
Fig. 24 Case 3 (well X) : Comparison between
permeability barriers indicated by gas shows and
by wireline logs.
DRILLING PARAMETERS LOGS INTERPRETATION GAS WH IL E DRILL IN G D AT A AN D INT ER PR ET AT IO N FINA L INTE RP RE TAT IO N
WIRELINE & GWD DATA - COMPOSITE LOG WELL C
-1 -0,5 0 0,5 1
-100 -80 -60 -40 -20 0 20 40 60 80 100DELTA P bars
BARRIERS FROM D/N LOG
BARRIERS FROMGAS SHOWS
RESERVOIR MODELBARRIERS
0 0,02 0,04 0,06 0,08 0,1 0,12 0,14
D E P T H M
(C4+C5)/(C1+C2)
WOC
base line
X100
X200
X300
X400
X500
X600
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SPE 65176 IMPROVED INTEGRATED RESERVOIR INTERPRETATION USING THE GAS WHILE DRILLING (GWD) DATA 17
Fig. 25 Well to well gas show interpretation in term
of fluid dynamic units, major dynamic barrier and
cap rock efficiency
F 1
F 2
F 3
F 4
F 5
S R 1
S R
2
R 1
R
2
R 3
R 4
Seal
Seal
Fluid 1
Fluid 2
Water
???
Fluid 1-2
Seal
Seal
WELL 4
Fluid 1
Fluid 2
Fluid1 -2
Seal
Seal
Tight zone
F 2
- F 3
F 1
S R 1
S R 2
R 1
R 2
R 3
WELL 3
Seal
Seal
Seal
Seal
F 1
F 3
F 4
S R 1
S R 2
R
1
R
2
R 3
WELL 2
R4
Water
Fluid 1
Fluid2
Fluid 1-2?
Seal
Seal
Tight zone
F 1
F 2
F3
S R 1
S R 2
R 1
R 2
R 3
WELL 1
R4
Seal
Seal
Water
Fluid 1
Fluid 1-2
Seal
Seal
Tight zone
GAS WHILE DRILLING ANALYSIS SYNTHETIC WELL TO WELL CORRELATIONS
CASE 4
F 1
F 2
F 2