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GAS WHILE DRILLING (GWD); A REAL TIME GEOLOGIC AND RESERVOIR INTERPRETATION TOOL

G.Beda, R.Quagliaroli ENI Agip Div., Milano, Italy; G.Segalini, B.Barraud, A.Mitchell ELF EP, Pau, France

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 the comprehensive 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 gas/oil and hydrocarbon/water contacts vertical changes in fluid over a thick mono-

layer pay zone The comparison between surface gas data and PVT 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 low resistivity pay light hydrocarbons

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 out temperatures, etc. One reason may be the very low cost of such data, often equated with low value. At present the analyses performed on gas shows are generally restricted to the use of Pixler and/or Geoservices diagrams (or equivalent), Wetness, Balance, Character and Gas Normalisation. 2, 4, 5, 7, 8 Taking advantage of recent improvements in gas acquisition technology a new method for the analysis and interpretation of gas while drilling has been established. The subsequent characterisation of the reservoirs and fluids present in the well demonstrates the major potential of gas shows. 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. 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

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For many years the formation evaluation aspect was limited to the combustion of the gas extracted from the mud using a catalytic filament. This gave what we all know as TOTAL GAS (TG). An attempt was made to differentiate hydrocarbon types by installing two filaments at different voltages leading to two measurements, TG and PETROLEUM VAPORS. The latter was equivalent to TG without the methane content. This robust, but very qualitative method was greatly improved by the gradual introduction of gas chromatographs to the well site enabling the definition of alkane gas components in the C1 to C5 range in a 5 minute cycle. The door was beginning to open towards formation fluid characterisation from gas in mud measurements. Since the early 70's ML companies and operator's alike began to look at the potential of gas in mud analysis. It was quickly understood that the factors linking gas in mud to the true formation fluid content were complex. Early attempts at fluid characterisation could be apparently successful on one well and completely false on the next due to differences in the environment of the measurement. Perturbing aspects included mud type, well balance, drilling practices, reservoir characteristics but, above all, the acquisition techniques employed. In the 80's the introduction on a wide scale by the ML companies of flame ionisation detectors (FID) in a new breed of chromatographs led to a significant improvement in the quality of gas measurements at the wellsite. 3 These were followed by the use of FID for the TG measurement itself. The TG measurement could now be correlated with the C1-C5 readings from the chromatograph. If significant advances had taken place on the analytical side, little or nothing had been done to improve the source of sample quality and validity - the GAS TRAP. Until very recently the standard gas traps used by ML companies were, in general, incapable of producing a comparable gas reading for an identical formation from well to well. Interpretation was hazardous due to the instability of TG and changes in the ratios between the different C1-C5 components. These variations were essentially due to problems linked to the mud level in the trap, the position of the trap, agitator motor speed and even wind in the atmosphere around the trap, all producing changes in trap efficiency. 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.6 This was attained by modifying the structure and components of the standard trap. The QGM trap has the advantage of being available from all ML companies. 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.1 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. 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. The work described here relies on the systematic use of either a QGM or a constant volume trap linked to FID Total gas 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 of good and reliable data is one of the weak points in our daily geological activity. Gas data can be significantly affected by the acquisition environment and it is important, before any interpretation, that the well site geologist checks if changes have occurred in the mud system, in drilling conditions, etc. Concertation between the company representative and the ML contractor 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. 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. The TG/C vs. depth plot where C=C1+C2+C3+C4+C5 is the main output used to verify that the gas acquisition has been correctly carried out. With an 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.1). A more useful output for QC when heavy components are present is the TG /Ccor vs. depth plot where the Ccor is the value corrected for the FID response of the individual components: Ccor = C1+2xC2+3xC3+4x(i+nC4)+5x(i+nC5)

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Reliable data can be qualified as being close to 1 (+/- 20%). Gas data whose value on this plot is significantly less than 1 is unreliable. In figs. 1 and 2, 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..) measured by the TG detector but not recorded by the chromatograph. The production test performed in this interval produced light oil. The TG/Ccor ratio could therefore also be used as semi-quantitative heavy gas richness indicator. In this well 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

normalising TG to eliminate "environmental" effects such as drill rate, mud flow and borehole diameter (NTG)

using "cut-offs" to eliminate shaly or tight zones

using various techniques to improve the signal to noise ratio (changing sampling rates, averages etc.)

Tests on a very large number of wells have led to a simplified catalogue of ratio logs and crossplots and their applications (Fig. 3). However this list is by no means exhaustive and the interpreter should not hesitate to multiply the different ways of displaying the data. Using up to date computing techniques this 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

absolute values) along the whole well profile always cross check results with other ratios and

crossplots accept no ties with fixed interpretative models integrate the gas data with all available well

data

maintain a critical approach A plot of ratios vs depth creates a gas log which can be directly compared with FEWD and wireline logs. 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, 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 size of a gas show can be directly related to the rock's porosity, lithology and fluid content. Trend breaks and gas composition changes and their evolution, can be, in many cases be related to lithology changes. The ratios used for this purpose are mainly the C1/C and TG/C. Other ratios such as (C4+C5)/C1 and C1/C3 or C2/C3 vs. depth are also useful for identifying the main changes. In the fig.4, the arrows on the C1/C ratio log indicate the main lithology changes 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. Fluid contacts Within a reservoir, a sharp change in the 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. 5 and 6). If the TG/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:

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The C1/SC ratio log is also used in the examples of figures 7 and 8 to illustrate how gas shows may or may not indicate a gradual fluid change within a reservoir. Figure 7 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 8 shows the opposite case where no fluid evolution is apparent from the C1-C5 components. The variations observed are strongly dependant on the type and composition of hydrocarbon present. Cap rock efficiency: Figure 9 is an example of the use of gas shows to indicate the efficiency of a cap rock. In this case the C1/SC 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.10 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 sealing efficiencies. 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 11 shows a sharp increase in the value of this ratio on entering the 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 test or WFT (wireline formation test) results it may even be possible to attain a quantitative evaluation. Well A The well consists of shaly sand sequence with good reservoir characteristics. Seven oil bearing zones have been identified by formation evaluation and three of them have been successfully tested. In fig.12 the C1/C ratio shows the presence of C1 only in the upper part suggesting the existence of good seal above the reservoir (to the depth of 1700). Furthermore, below this depth the sharp peaks to the left (decreasing values of C1/C) identify the presence of heavy alkanes (most likely hydrocarbon bearing levels). Figure 13 shows the main lithology changes confirmed by petrographic and stratigraphic study. The arrows on the plot indicate the main lithology changes. In figs. 14 and 15 the shaly zones have been eliminated using a cut off on the TG log and only the hydrocarbon bearing zones are shown. On both figures the two different ratios show the existence of two separate trends. The evolution of the upper three zones could be explained by the variation of the GOR with depth proved by the two production tests performed on zones 22 and 8. In the lower part of the well, only the lowermost zone has been tested. In this section an evolution of the GOR can be inferred from the behaviour of the ratios as shown in fig.16. The two main intervals show an opposite trend leading us to think that the oil of the two groups is different. In the crossplot in fig. 16, the two main zones are more clearly differentiated and characterised The explanation for this behaviour came from geochemistry which proved the existence of two oil groups with different degrees of maturity, migration pathways and migration times. Figure 16 also shows the C1/C3 vs C2/C3 values obtained from recombined PVT samples. The PVT points from zones 22 and 8 overlay the gas show values of the same zones confirming the validity of the approach and proving the potential of gas while drilling for reservoir characterisation.

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Well B The example well crossed a thick deltaic sand-shale series, identifying more than 50 reservoir levels. These reservoirs contain dry gas, condensate gas and oil. Tests were carried out on 5 reservoirs and cased-hole WFTs on another 5. From this data only it was clearly impossible to define the fluid in all the reservoir levels. The thinness of the reservoirs and the minor changes from one fluid to another did not allow an approach to fluid typing using classic well log analysis. Gas shows proved to be an indispensable asset for evaluating fluid type and quality as a complement to the thermodynamic study. Two gas ratios were selected to enable an initial qualitative interpretation. After calibration using the test and WFT results it was possible to attribute a condensate content to every gas bearing level. On figure 17 the C1/SC and C2/C3 ratios are shown for the 51 reservoir levels drilled. The values of these ratios represent an arithmetic mean of the gas shows recorded while crossing the level in question. Comparison of these ratios with the Gas Oil Ratios (GOR) from the test and WFT results enabled the definition of three fluid groups: a first group concerns "dry gas" with C1/SC>90

and C2/C3>3 a second group concerns gas rich in condensate

with C1/SC between 83 and 90 and C2/C3 between 1.5 and 3

the final group identifies the oil layers with C1/SC

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initial reservoir pressure and the MDT 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 overall 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 MDT 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 classic log interpretation. Even the small change in depleted pressure at 3870 can be identified. The gas analysis provided 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 used in the model are deducted from a porosity-permeability relationship. A review of the reservoir model following the gas show interpretation 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 reservoir model definition and to the understanding of reservoir behaviour. 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 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 the wellsite 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 / disorption. 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 an 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 multilayer reservoirs Low Resistivity Pay light hydrocarbons (especially when associated

with the previous three) 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 , ELF EP, Carlo Carugo and Dario Manfroi, ENI-Agip Div, and the other members of the joint ELF/ENI-

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Agip "Well Data Acquisitions" project for their helpful ideas, reviews and encouragement. REFERENCES 1 - De Pazzis L.L.,Delahaye T.R.,Besson L.J. and Lombez J.P, New Gas Logging System Improves Gas Shows Analysis and Interpretation, 1989, SPE Annual Conference, SPE 19605 2 - Haworth, J.H., Sellens, M. and Whittaker A. , Interpretation of Hydrocarbon Shows Using Light (C1-C5)Hydrocarbon Gases from Mud Log Data,.1985, AAPG Bull.V.69, No.8, p.1305-1310. 3 - Mercer, R.F., The Use of Flame Ionisation Detection in Oil Exploration, 1968, 2nd CWLS Formation Evaluation Symposium. 4 - Pixler, B.O. , Formation Evaluation by Analysis of Hydrocarbon Ratios, 1968, 43rd Annual Meeting SPE, Houston, n.2254. 5 - Wright. A.C. , Estimation of Gas/Oil Ratios and Detection of Unusual Formation Fluids from Mud Logging Gas Data., 1996, SPWLA 37th Annual Logging Symposium. 6 - Wright A.C.,Hanson S. A. and DeLaune P. L., A New Quantitative Technique for Surface Gas Measurements, 1993, SPWLA 34th Annual Logging Symposium. 7 - Whittaker, Alun, Mud Logging Handbook, 1991, Prentice Hall 8 - Whittaker A. and Sellens G., Advances in Mud Logging - 2, Analysis uses alkane ratios from chromatography, 1987, Oil & Gas Journal, May 18th, pp 42- 49. ABOUT THE AUTHORS Giulio Beda works at present in Surface Logging Development in ENI-Agip Operations Geology Department in Italy. After graduating in mining technology he joined Agip in 1975 where he has worked in various assignments in operations and reservoir geology, formation evaluation mainly in Western and North Africa. 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. Grard 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 diploma from 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. Alan Mitchell is currently senior well geologist in the well construction technology network of ELF EP in Pau, FRANCE. After graduating from the University of Nottingham, UK, he worked for 5 years in mud logging and pore pressure evaluation before moving to ELF as a well site geologist. Since obtaining his diploma as an engineer in geology from the ENSPM in Paris he has been continuously involved in well geology operations and know-how development.

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Fig. 1 TG/C vs depth plot

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Fig. 2 TG/Ccor vs depth plot

Fig. 3 Typical gas ratio log and crossplot applications

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Fig.4 In this example, the arrows indicate the main lithology changes. Good correlations are observed between the C1/C ratio log and the wire line logs.

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Fig. 5 TG vs depth log showing reservoir boundaries and contacts

Fig.7 Example of fluid evolution with depth within a mono-layer reservoir

Fig.6 C1/C vs depth with reservoir boundaries and contacts (same data as fig.6)

Fig. 8 Example with stable C1-C5 composition throughout the reservoir

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Fig. 9 Example of poor sealing capacity of the cap rock Fig. 10 Example of good sealing capacity of the cap

rock and the interbedded shale

iC5/nC5

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Fig. 11 Example of biograded oil bearing reservoir

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Fig. 12 C1/C ratio vs depth with, the anomalies indicate the presence of hydrocarbon bearing zones

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GOR 70 SCF/STB40.8 API

PT 3 ZONE 22OIL

GOR 20 SCF/STB41.3 API

PT 2 ZONE 8OIL

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Fig. 14 TG/C ratio vs depth, only the hydrocarbon bearing zones have been plotted using a cut off on TG

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Fig. 13 TG/C ratio, the arrows indicate the main lithological changes.

Fig. 15 C1/C ratio, two opposite trends are present

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Fig. 16 C1/C3 vs C2/C3 plot, a very good correlation has been established between gas shows and PVT data

Fig.17 Multi-layered reservoir evaluationFig.17 Multi-layered reservoir evaluation

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Fig.18 Gross Heating Value correlationsFig.18 Gross Heating Value correlations

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commercial specification

GHV calculated from processed DST samples

(level 1)

(level 35-36)(level 50)

(level 42-43)

(level 14)

NOTE THAT FIGS 17 AND 18 MAY BE MODIFIED. FIG. 19 IS BEING PREPARED.

Fig.19 Comparison between permeability barriers indicated by gas shows and by wireline logs