Reservoir Interpretation Using Gas While Drilling

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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



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



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




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.




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%).




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.




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.




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.




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)




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




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 ?)




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




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




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)




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


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


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




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




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

Documents

Reservoir Interpretation Using Gas While Drilling