nguyen nam and larry fink - department of...

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March 2009 1

FROM ANGLE STACK TO FLUID AND LITHOLOGY STACKS – A CASE STUDY FROM NORWEGIAN SEA

Nguyen Nam and Larry Fink

Landmark Graphics

Seismic amplitudes contains some additional information about lithology and pore-fluid in the

reservoir. By combining AVO intercept and gradient attributes along an angle of rotation, an optimal seismic stack can be designed to provide maximum discrimination between either fluids or lithologies. The fluid stack is an optimal stack for enhancing fluid effects in the seismic data. This stack is used to highlight hydrocarbon reservoirs. A lithology stack is an optimal stack for enhancing lithology variations where fluid effects are removed or reduced. This stack is used for mapping instances of sand.

In this case study, AVO intercept and gradient attributes were computed from a combination of near-mid-far angles stacks. Then crossplot intercept and gradient data at the reservoir to define background/shale trend and classify how lithologic and/or pore fluid changes are separated from the background trend. After computed intercept and gradient was properly calibrated to the modelled synthetic data, crossplot analysis can be performed with much greater confident. Rotation angle is typically defined as the angle between background trend and the vertical axis in crossplot. With this angle, fluid and lithology stacks were generated to verify successfully the fluid contact and lithology/facies changes in the reservoir across the entire 3D seismic survey.

Petroleum Geology Conference and Exhibition 2009 2-3rd March, 2009 Kuala Lumpur Convention Center, Kuala Lumpur, Malaysia

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2 Geological Society of Malaysia

VARIATION IN THE ORIENTATION OF THE MAXIMUM HORIZONTAL STRESS

ACROSS THE SARAWAK BASIN, OFFSHORE EASTERN MALAYSIA

Adrian White1, David Castillo1, Marian Magee1 and Andy Firth2

1GeoMechanics International, 55, St. George’s Terrace, Perth, WA 6000, Australia 2Murphy Sarawak Oil Company, Tower 2, PETRONAS Twin Towers, KLCC, 50088 Kuala Lumpur, Malaysia

It is vital to consider the contemporary stress field during well planning because it can be misleading

to assume that regional trends will be valid for a field without evaluating specific offset well data from that field. The Sarawak Basin, Offshore Eastern Malaysia, is a case where drastic horizontal stress azimuth variations are observed from the north to the south and from the east to the west of the basin. This complex tectonic nature makes it especially important to understand the stress orientations that occur in each field. As a means of illustrating the importance of understanding the stress field, wellbore stability analyses are essential in determining drilling parameters and such studies rely heavily on accurately constrained maximum horizontal stress (SHmax) azimuths.

The orientation of SHmax has been determined in several fields across the Sarawak Basin over the last couple of years. These stress orientations were determined through the identification of wellbore breakouts seen in OBMI (oil-based mud imager) data acquired by Murphy Sarawak Oil Company. Analyses of the image data show significant variation in the SHmax azimuth. There is a reasonable degree of consistency between the Permas, Endau, Serampang and Batu Kapur fields in the northern half of the Sarawak Basin. In these fields the SHmax azimuth is approximately northwest-southeast. However, in fields located 50-100 kilometres to the south (Pemanis, Merapuh, Belum, Serendah and Temana) the azimuth of SHmax is east-west. To complicate matters, the fields bounding this southern group reveal SHmax azimuths that trend north-south (the Bayan field to the west and the Golok and Golok Barat fields to the east). Maximum horizontal stress azimuth is significantly different again in the Sapih field located in the extreme northeast of the Sarawak Basin. In this field the SHmax azimuth is northeast-southwest.

The abundance of faults in the Sarawak Basin suggests that these structures could be contributing to the spatial variation in SHmax azimuth. Fault stability studies in a number of the fields show that there is active faulting in the basin. It has been proven around the world that active faults influence and perturb the orientation of the horizontal stresses. It is thought that this may be the cause of the significant stress rotations observed across the Sarawak Basin.

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March 2009 3

GEOMECHANICAL APPLICATIONS FOR INTEGRATED EXPLORATION AND

DEVELOPMENT DRILLING AND PRODUCTION OPTIMISATION

Adrian White1, Marian Magee1, Katharine Burgdorff1, David Castillo1 and Anan Amornprabharwat2

1GeoMechanics International, 55, St. George’s Terrace, Perth, WA 6000, Australia

2CPOC, Tower 2, PETRONAS Twin Towers, KLCC, 50088 Kuala Lumpur, Malaysia Wellbore instability and the risk of sand production are issues that can have serious impacts on

successful field development. Accurate geomechanical models were constructed to limit the risk of these problems in the Jengka and Muda fields, Malay Basin. The aim was to determine drilling and completion constraints, from a geomechanical perspective, for further exploration and development of the Jengka and Muda fields. Analyses helped to determine drilling mud weights for different wellbore trajectories, casing designs, the sanding risk associated with different completion strategies, optimal perforation orientation and quantify sand-free drawdown and depletion.

Constructing robust geomechanical models that matched the offset experience proved to challenging because stress magnitudes appear to be in excess of those observed across much of the Malay Basin. The geomechanical modeling shows that in both the Jengka and Muda fields the stress field is associated with a strike-slip regime (Shmin < SV < SHmax). The maximum horizontal stress (SHmax) azimuth was determined to be approximately NNE-SSW in both fields. Modelling of the magnitude of pore pressure also proved to be challenging because thermal effects appear to contribute to the magnitude of overpressure together with under-compaction.

Wellbore instabilities are unlikely to be a concern if mud weights are adjusted according to the trajectory of the borehole. Modelling also shows that uncertainties in shale rock properties and the pore pressure magnitude have the greatest impact on the mud weight required to achieve hole design.

Multi-stage triaxial tests and advanced thick walled cylinder tests, conducted on samples from the Jengka and Muda fields, proved valuable in constraining rock mechanical properties and in the calibration of the sand production predictions. These data allowed the creation of rock material models which greatly helped the analysis. Sand production analyses indicated there are preferential wellbore perforation directions that reduce the risk of sand production following depletion. This is due to the anisotropy that exists in the magnitudes of the horizontal stresses. Perforations in all orientations should be stable at initial reservoir conditions with up to 1500 psi drawdown. Following drawdown, perforations with the highest chance of producing sand are oriented in the direction of greatest compression.

CPOC used the geomechanical model and wellbore stability analysis to successfully drill 7 exploration/appraisal wells with minimum not productive time. The geomechanical model was thereby verified, helping to reduce drilling cost, but will also be used to enhance future production through making recommendations on the optimum completion strategy for the strike slip stress regime identified.


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ORGANIC GEOCHEMISTRY AND THERMAL MATURITY OF

MADBI FORMATION, SHABOWAH OILFIELD, MASILA BASIN, YEMEN

Mohammed H. Hakimi 1, Wan Hasiah Abdullah 1 and Mohammed R. Shalaby2

1 Department of Geology, Faculty of Science, University of Malaya

2Geoscience and Petroleum Engineering Department, Universiti Technologi PETRONAS The East Shabowah Oilfields in the Masila Basin is one of the most productive oilfields in the

Republic of Yemen (Fig.1). The Masila Basin contains sediments of Jurassic and younger age. The Madbi Formation lies conformably on the Shuqra Formation (Beydon et al., 1998). Madbi, Shuqra and Naifa Formations together make up Amran group (Fig.2). The Madbi Formation an important regional source rock is widespread and is encountered in the East Shabowah Oilfields where it consists of two units. The lower unit commonly consists of an argillaceous lime and a basal sand, and forms a good reservoir in some oilfields of the Masila Basin. The upper unit is composed of laminated organic rich shale, which is a prolific source rocks in the Masila Basin (Mills, 1992; SPT, 1994). In this study, organic rich shales were analysed by means of organic petrographic and organic geochemistry methods with the objective of evaluating the oil generating potential of the shales. The petrographic analysis was performed by using vitrinite reflectance (%Ro) measured in reflected “white light” under oil immersion. The geochemical analyses carried out include determination of the total organic carbon content (TOC wt%), bitumen extraction, and gas chromatography-mass spectrometry (GC-MS). Based on the biomarker distribution analysed, the sediments are interpreted to have been deposited under varying oxic to anoxic conditions in a marine environment (Fig.3). Good source rock potential is suggested by high values of TOC of 7.5-12.2 wt% (Fig.4) and high extractable organic matter content and hydrocarbon yields exceeding 8,000 and 1800 ppm, respectively (Fig.5). The shale samples analysed are thermally mature for hydrocarbon generation as suggested by %Ro values of 0.65-0.91%.

References BEYDON, Z.R., AL-SORURI, M., EL-NAKAL, H., AL-GANAD, I., BAROBA, R., NANI, A.O., AL-

AAWAH, M., 1998. International Lexicon of stratigraphy V. 111. ASIA. MILLS, S. J., 1992. Oil Discoveries in the Hadramaut: How Canadian Oxy scored in Yemen, Oil and Gas

Journal, (9 March), 49-52p. SPT (Simon Petroleum Technology), 1994. The Petroleum Geology of the Sedimentary Basins of the

Republic of Yemen, Non exclusive report in V. 7 TOTAL COMPANY, 1999. East Shabowah Oilfields. Unpublished

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Figure 1: Mosaic of TM Land sat image of Yemen showing the locationof East Shabowah oilfields.

Figure 2: Lithostratigraphic column of East Shabowah area, Masila Basin (Modified after Total Company, 1999).


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Figure 3: Biomarker distributions in Madbi sediments: distribution of triterpanes m/z 191(left) and n-alkanes and isoprenoids (right).

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Figure 4: Source potential rating based on TOC-EOM plot (left) and source-rock richness plot (right) for the organic rich shale, study area

Figure 5: Histogram of extractable organic matter (EOM) and hydrocarbons yield (left), diagram displaying percentage of extract fractions (Aliphatic, Aromatic and NSO compound) (right) for the studied


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APPLICATION OF NON-CONVENTIONAL ANALYTICAL TECHNIQUES

TO COALY PETROLEUM SOURCE ROCK EVALUATION

Wan Hasiah Abdullah1 and Peter Abolins2

1Department of Geology, University of Malaya, 50603 Kuala Lumpur, Malaysia 2PETRONAS Carigali Sdn Bhd, Level 16, Tower 2, PETRONAS Twin Towers, KLCC, 50088 Kuala Lumpur, Malaysia

Petroleum geochemists frequently depend on a limited number of techniques for assessing the source

rock potential of coal-bearing strata. Such widely used techniques include TOC (Total Organic Carbon), Rock-Eval, vitrinite reflectance and, to a lesser degree, PyGC, visual kerogen typing, and biomarkers. Amongst these, the technique that provides the best balance between information gained, rapidity of analysis, and cost effectiveness is Rock-Eval. However, this technique has been cited by some workers as inadequate to evaluate oil-generating potential of coals. As such, alternative techniques, or integration of a number of techniques, are considered appropriate to enhance source rock evaluation of coaly petroleum source rocks.

Outside of the petroleum sector, other industries have adopted techniques for studying organic material including coals. The concept of coal quality, or grade, in mining and industrial utilisation is based on a number of parameters and compositional elements which encompasses the coal type, rank (or maturity), ash yield, calorific value and the occurrence of elements such as sulphur, phosphorus etc. Some techniques, such as vitrinite reflectance and visual maceral analysis, are common with the petroleum industry. Other techniques typically used include TGA (thermogravimetric analysis), FTIR (Fourier Transform Infrared), and NMR (Nuclear Magnetic Resonance). Such techniques have barely entered mainstream source rock evaluation programmes, primarily because of either a lack of inter industrial collaboration or that the techniques were not easily accessible to geochemistry service providers. This study investigates some of these emerging techniques with respect to source rock evaluation.

In this study, five Tertiary aged coal samples from Sarawak (Bintulu, Merit-Pila & Mukah-Balingian) were investigated by means of proximate analysis (ASTM method) and by thermogravimetric analysis (TGA) so as to define its physicochemical quality. More advanced techniques such as FTIR and NMR were also studied. Data obtained from these methods were correlated to the Py-GC fingerprints and to the petrographic data determined using photometry reflected light microscopy. Considering that rank (maturity) is generally regarded as the most influential factor in determining the coal quality and its petroleum generating potential, the coals selected in this study are of approximately similar rank having vitrinite reflectance in the range of 0.4-0.5%Ro. Therefore any compositional variation, or related physicochemical parameters, observed may therefore be attributed predominantly to the coal type.

Once the cross-industry terminology differences were ironed out (such as the definition of ‘volatile matter’), it was observed that there is good correlation of proximate analysis volatile matter content and carbon content between the analysis carried out using ASTM methods and that performed by TGA. Moreover, the ratio of % carbon to % volatile matter showed good correlation with maceral content of the coals whereby samples with greater abundance of vitrinite gave higher carbon to volatile ratio compared to those higher in hydrogen-rich liptinite content as supported by the FTIR data. A good correlation is also obtained between NMR and Py-GC fingerprints as indicated by a distinctively higher aliphatic to aromatic ratio for samples that are richer in liptinite content.

All of the physicochemical techniques performed here complement each other and produce reliable results that can be applied to determine either coal quality or for evaluation of petroleum source potential. In conclusion, therefore, it is apparent that there are several other techniques that we could be using for coaly source rock characterization, techniques which are now becoming more commonly available to petroleum geochemists.

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March 2009 9

A NEW STRATIGRAPHIC AND STRUCTURAL MODEL

FOR THE MIRI FIELD, ONSHORE WEST BARAM DELTA, SARAWAK

Yuniarti Ulfa1 and Zuhar Zahir Tuan Harith2

Department of Geoscience and Petroleum Engineering, Universiti Teknologi PETRONAS, Bandar Seri Iskandar, 31750 Tronoh, Perak, Malaysia

[email protected] [email protected]

The Miri Formation is a siliciclastic sequence consisting of a succession of coarsening upwards clay-

sand packages where the sandstones form important oil reservoirs in the Baram Delta Province. The Middle Miocene Miri Formation, which crops out in the town of Miri in northeast Sarawak on and around the topographic feature called Canada Hill

The outcrops illustrate a complex structural geology and stratigraphy. Many authors on various aspects have studied these outcrops. However the definite stratigraphy and the structural model of the area comprising the Miri Oil Field are still questionable today.

Recent developments in Miri Town have exposed some new outcrops, which provide new geological insights. The present study aims at utilizing these new insights to investigate and model the structural deformation pattern in the study area. Stratigraphic measurements were carried out on five outcrops namely 1) Miri Hospital Road (horizontal beds); 2) Miri Hospital Road (vertical beds); 3) Airport Road Outcrop; 4) Miri Hill Top Garden and 5) Boulevard Road Outcrop. All outcrops (except outcrop number 2) show sub-horizontally to low angle dipping layers. The outcrops were logged and samples were taken for biostratigraphical analysis. The logged sections range from 20 to approximately 400 meters thick (stratigraphic thickness). The stratigraphic section correlations (supported by the biostratigraphic data) were used to produce a two-dimensional facies model.

Based on lithology, sedimentary structures, bedding geometry and fossil assemblages, the sediments are grouped into twenty-five litho facies types. These are; i) facies A - homogenous coarse grained sandstone; ii) facies B - graded siltstone; iii) facies C - amalgamated hummocky cross-stratified sandstone; iv) facies D - bioturbated siltstone; v) facies E - fine grained bioturbated sandstone; vi) facies F – mudstone; vii) facies G - parallel stratified sandstone with mud drapes; viii) facies H - grey parallel laminated siltstone; ix) facies I - trough cross stratified sandstone parallel stratified to siltstone; x) facies J - interbedded to bioturbated siltstone and fine sandstone; xi) facies K - lenticular bedding; xii) facies L - massive sandstone; xiii) facies M - mudstone interbedding with parallel stratified to hummocky cross-stratified sandstone; xiv) facies N - rhythmic stratified sandstone and mudstone; xv) facies O - sand-clay alternation facies; xvi) facies P - massive coarse sandstone with liesegang; xvii) facies Q - low bioturbated coarse sandstone; xviii) facies R - sandstone and shale interbedding with sedimentary dike; xix) facies S - massive sandstone parallel stratified to siltstone; xx) facies T – shale; xxi) facies U - flasser-bedded sandstone; xxii) facies V - swaley cross-stratified sandstone; xxiii) facies W - thick, massive and structureless sandstone; xxiv) facies X - trough cross-stratified sandstone with mud drapes; and xxv) facies Y - wavy-bedded sandstone. These facies types are subsequently grouped into two main facies associations (architectural elements), which represent the major paleo-environments of the Miri Formation. These are tide-dominated estuary and shallow marine facies associations. Biostratigraphical analysis has also confirmed that the thick vertical sequence (Hospital Road) is early Middle Miocene in age and belongs to the Lower sequence of the Miri Formation. The other outcrops in this area (sub-horizontally dipping layer) belong to the Upper sequence of the Miri Formation.

The new exposure of the Lower Miri Formation (thick sequence of vertical beds) has led to a new structural interpretation. Previously the Miri Oil Field structure has been referred to as having undergone two periods of deformation, with an extensional phase predating the compressional phase. The exposures of 400-meters thick vertical dipping beds of the Lower Miri Formation adjacent to sub-horizontal dipping sequence


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(Upper Miri Formation) suggest another major thrust fault associated with a flower structure. It is proposed that the structure forming the Miri Oil Field evolved under extensional phase followed by a compressional phase associated by strike-slip tectonic processes.

Figure 1: One fresh outcrop (Miri Hospital Road Outcrop) exposed by recent development in Miri Town shows an overview of vertical dipping beds. The vertical dip various from 70°-90° with total stratigraphic thickness is 404 meters.

Figure 2: Another fresh outcrop shows an overview of the stratigraphy from overall gently dipping beds associate with faults on the Boulevard Road outcrop, respectively. Total stratigraphic thickness of this outcrop is 43 meters.

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March 2009 11

STUDY ON COMPLEX RESISTIVITY OF ROCK CORES

AT 100 HZ - 200 KHZ

Hilfan Khairy1, Zuhar Zahir Tn. Harith1, Umar Fauzi2

1Universiti Teknologi PETRONAS, Malaysia 2Institut Teknologi Bandung, Indonesia

[email protected] [email protected]

Study of complex resistivity was accomplished on sandstones rocks which have different porosity and

permeability. The experiment was designed to measure resistivity response in frequency range of 100 Hz to 200 KHz. The confining pressure was applied from 1000 psig until 3000 psig while the saturations were increased gradiently. Complex resistivity and dielectric permittivity result are presented in this paper together with their respective analysis on saturation changes, pressure, porosity and permeability.

The measurement setup and two electrode configuration are described to prevent parasitic impedance in high frequency.

We obtained the resistivity generally decrease with increasing confining pressure. At certain water saturation series the resistivity increase with pressure. This indicates a complicate of resistivity interpretation depend on pressure and saturation condition. Also for certain rock sample there is an optimum saturation before resistivity slightly changes on the other way. More intensified study must be established to address these results for waterflood monitoring.

Resistivity measurement


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Sonic measurement

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March 2009 13

ANALYSIS OF FRACTURED CARBONATE RESERVOIR

(NAFT-SAFID FIELD) USING IMAGE LOGS

H. Seifi

National Iranian Oil Company (Exploration Directorate),Tehran , Iran [email protected]

Introduction The key to successful exploration in fractured reservoirs is to predict where natural fracturing is

abundant. Therefore, the use of borehole imaging technology to locate fractures and determine the geometry of the existing fractures, lateral and vertical distribution of productive fractures, fracture quality and hydrocarbon potential, prior setting casing is an essential element in evaluating the economics of any given well.

This paper aims to present results of fracture system characterization demonstrating how the information obtained from the borehole imaging devices provides better understanding of the complex fractured reservoirs. Examples include data acquired in a range of geological environments and borehole conditions. Field data presented here include borehole imagining examples from well drilled with conductive mud .In this paper we present the analysis of well #40 from Naft-Safid field.

As a result, directions of minimum horizontal stress derived from borehole breakouts are presented in a borehole in the Naft-Safid. We have found a clear tendency for a dominant N50W direction of breakouts on approximately perpendicular to the regional stress.

The Naft Safid reservoir is located approximately 100 miles north of the Persian Gulf in southwestern Iran, and is northwest of the Haft Kel Field and almost due south of the Masjid-i-Sulaiman reservoir. It is approximately 40 miles northeast of Ahwaz. Naft-Safid is an elongated asymmetrical anticline that trends in a northwest and southeast direction and dips more steeply on the western flank of the axis than on the east.

The well NS-40 was drilled vertically up to 1869 m with 8.25 inch bit across the reservoir section. The target formation with reservoir potential was Asmari Formation. The well was logged with conventional logs, EMI across the reservoir section. The main objective of the EMI survey was to characterize fractures for their distribution, types and orientation.

Fracture Analysis The EMI images revealed a number of fractures in certain zones of the Asmari formation. There are

102 such fractures found at certain places. These fractures have a variation in their aperture appearance and trace continuity across the wellbore .Therefore they are classified into three categories; open fractures, partially -open fractures, the partially-open fractures their traces look like hairline fractures and are largely discontinuous across the wellbore.

The are dominantly at 50 degrees to N40W.Open fractures have dominant N70E strike and N50W strike in Asmari. Density of open fractures was computed to represent number of fractures per meter. The highest density of open fractures is found in zones; 1734-1740m, 1690-1692m, 1780-1786m zones.(figure 1)

From reservoir point of view the transverse fractures (i.e., NE-SW fractures) are more critical because they may connect the well drilled for the oil column with the gas-cap and water-pool .Similarly the longitudinal fractures (i.e., NW-SE fractures, the blue set) can also connect the well either with the gas-cap or the water-pool if they intersect GOC or WOC.

The present fracture model is based on just one vertical well. Fracture data from some more wells (more importantly from deviated and horizontal ones) is required to validate and refine the fracture model.

Based on both dip types, an average dip magnitude of 15 degrees can be taken for structural dip computation for the whole interval. The borehole is deviated to NE with low angle 5 degree in lower zone.


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The structural dip varies from10 degrees to 20 degrees in Asmari formation, with no major change in the dominant S55W dip azimuth. Similarly the general strike does not change much from N45W-S30E.

In vertical wells and those with smaller deviation, the orientation of borehole elongation is aligned with the trend of minimum horizontal stress. Similarly, the strike of drilling induced is aligned with the trend of maximum horizontal stress.

In-Situ Stress at Well NS-40 The strike of induced fractures according to the image is N55E which means that the principal

maximum horizontal stress is in this direction. Therefore local stress of this well is as the same as the regional stress NE in Zagros basin. There is atypical induced fractures which is shown in figure2.In this figure also the strike rosette diagram of Drilling Induced fracture is shown.

Borehole breakouts were observed in the well. The large majority of these elliptical breakouts have their longer axis oriented in almost N50W-S50E direction. Based on the borehole breakouts the in-situ stress directions around the study well are oriented, N40E-S40W for maximum horizontal stress (σHmax), and N50W-S50E, for the minimum horizontal stress (σHmin).

The ovalizations of the wellbore in breakout places are in direction of N50W-S50E Which indicates that the orientation of minimum horizontal stress (σHmin) around WELL NS#40 is almost N50W-S50E and the orientation of maximum horizontal stress (σHmax) is N40E -S40W .This orientation of in-situ stress matches with the regional orientation of Zagros stresses. In Figure 3 Breakout direction of well NS-40 is generated by Caliban module which shows the N50W direction and this figure confirms the strike of induced fracture because it is perpendicular to the strike of induced fracture.

In-situ stress orientations determined based on borehole breakouts identified in well NS-40 EMI images and caliper data show borehole breakouts oriented on the average NW-SE , which is parallel to the minimum horizontal stress (σHmin) orientation in that area. No clear drilling induced were observed in the well; if they had developed, they would be oriented NE-SW to be parallel to the maximum horizontal stress orientation. The overall orientations of σhmin and σHmax around well NS-40 are NW-SE and NE-SW, respectively (Figure 4).

Conclusions Based on observations and interpretation of the image-logs from 1660m to 1860m, the highlights of

the study are given below: • The structural dip varies from10 degrees to 20 degrees in Asmari formation, with no major change in

the dominant S55W dip azimuth. Similarly the general strike does not change much from N45W-S30E.

• Asmari reservoir is moderately fractured, mostly with open fractures, about 103 open fractures are found in this study. Their dip are dominantly at 50 degrees N40W.

• Generally two orthogonal sets of open fractures are present. The NE-SW striking fractures are transverse and NW-SE striking fractures are longitudinal.

• In situ stress analysis the overall orientations of σhmin and σHmax around well NS-40 are NW-SE and NE-SW, respectively.

• It is recommended in most of Iranian reservoir which are fractured for study of fractures ,density of fractures ,strike and dip of fractures. The best way to increase knowledge about them is running borehole imaging tools.

• Direction of maximum horizontal stress should be known to analyze borehole stability analysis and determine direction of horizontal section to intersect the fractures. So it is recommended to run FMI and EMI image logs to increase knowledge about the formation.

• In Case study to have accurate evaluation of fractures it is highly recommended to take cores at places from at least one well.

References: Stefan M. Luthi, Geological Well Logs and Their Use in Reservoir Modeling, 2000

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Cooper R.I., et al, The Use of Resistivity-at-the-Bit Images and Annular Pressure While Drilling in Preventing Drilling Problems,SPE,March2001

Goodall I. ,et al, Resistivity Image Data, Vøring Basin, Offshore Norway, AAPG Methods in Exploration No. 13, p. 143–159,2002

Williams J. H. ,Johnson C. D., Acoustic and optical borehole-wall imaging for fractured-rock aquifer studies, Journal of Applied Geophysics 55 (2004) 151– 159,2004

Zoback M.D., et al, Determination of stress orientation and magnitude in deep wells, International Journal of Rock Mechanics & Mining Sciences 40 (2003) 1049–1076, 2003

Lovell, M.A., Williamson, G. and Harvey, P.K., Borehole imaging: Applications and case histories, Geological society special Publication, No. 159, 1999

Figure 1: Statistical plots for the dips of open fracturesfound in the Asmari Formation(NS-40)

Figure 2: a)Close view of Induced Fractures b)Strike Azimuth Rosette of Induced Fractures


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Figure 3: Breakout directions in Naft-Safid Field ,well #40

Figure 4: Top view and 3D view to show orientations of in-situ stresses with respect to breakouts and Drilling Induced Fracture in NS-40

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March 2009 17

3D SEISMIC MAPPING AND MODERN-DAY SLOPE MORPHOLOGY

OF THE SOUTH GABON BASIN, OFFSHORE WEST AFRICA Nurhuda Jamin, Christopher Jackson, Lidia Lonergan, Howard Johnson

Department of Earth Science and Engineering, Imperial College London, Prince Consort Road, London SW7 2BP, UK [email protected]

Three-dimensional seismic data is used to describe the detailed morphology of a 3085 km2 area of the

modern-day slope within the South Gabon Basin, offshore West Africa. A number of features are recognised which document gravity-flow or oceanographic current-related depositional processes (e.g. slope gullies, channel-levee complexes and sediments waves), and the escape of fluids from within the basin-fill (e.g. pockmarks).

A dip-map of the seabed illustrates the overall structure of the study area and indicates that the shelf-edge trends NE-SW and the slope dips towards the southwest. A number of interesting morphological features are also observed. Gullies, which are located on the slope, are V or U-shaped in cross-section, up to 45 ms deep and 51-87 m wide. They are best developed on the upper slope and extend up to 20 km down slope before broadening, shallowing and ultimately dieing-out. Sediment waves are developed on the lower slope and appear to infill and bury the distal reaches of some of the slope gullies. These sediment waves, which are highly asymmetric in cross-section, migrate upslope towards the east, have wavelengths of up to 1.3 km and heights of 5-10 ms. A series of NE-SW-trending slope channels are identified in the north-western part of the study area. These channels, which stack to form a shallowly-buried ‘channel-complex’, are developed over an area of ca. 781 km2 and have a cumulative thickness of ca. 492 ms. Individual channels vary in size and map-view and cross-sectional geometry. Channels display well-developed levees and are up to 410 m wide and 115 ms deep.

Pockmarks are observed on the slope where they either form linear arrays or are more randomly distributed within pockmark ‘fields’. A pockmark field is identified on the southern, more gently-dipping part of the slope. Individual pockmarks in this location are circular to sub-circular, and are 86 - 212 m in width and up to 80 ms deep. On the slope, however, pockmarks commonly appear to have coalesced to form elongate gullies with widths ranging from 63-170 m and with cumulative depths of up to 80 ms.

In conclusion, the use of 3D seismic data helps to characterise the modern-day morphology of continental slopes and the depositional, erosional and fluid-flow process occurring upon them. More specifically, 3D seismic data, where available, has advantages over bathymetric surveying (e.g. side-scan sonar etc) in that it allows the seabed features to be examined in section as well as plan-form.


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SOURCE ROCK DELINEATION AND THERMAL MATURITY

IN TATUA PROVINCE, OFFSHORE SARAWAK BASIN TEDROS MEZGEBE .G1, WAN ISMAIL WAN YUSOFF2, JAMAAL HOESNI3

Department of Geosciences and Petroleum Enginering, Universiti Teknologi PETROENAS (UTP), Bandar Seri Iskandar,

31750 Tronoh, Perak Darul Ridzuan, Malaysia [email protected] [email protected] [email protected]

Key words: Burial, Maturation, Expulsion, Exploration, Modeling, Source Rock

INTRODUCTION Hydrocarbons are produced from offshore Sarawak basin province. The province consists of Tertiary

half-graben basin in filled with carbonate and clastic sedimentary rocks. This paper will present burial history chart, maturation window, and hydrocarbon expulsion window of the study area. The main points need to know are the vertical extent of strata which can be the source rock for the hydrocarbon generation and the hydrocarbon quality (maturity) of the source rock. Four drilled sections of wells JL-1, JL-2, JL-3 and JL-4 were chosen for modeling of hydrocarbon generation history. They were selected because of their available data and obtained results. All of them penetrated thick sedimentary sequences, including lower Oligocene and Miocene source rock horizons. The modeling of the wells characterize the thermal and generation history of perspective deposits not only in the study area but also the lateral continuation of the other horizons with discovered economic oil and gas fields. The research works on the stratigraphic sequence of each well lithologies to optimize the model of the source rock due to the available geochemical, seismic, well, and variable heat flow, The technique which is important to develop the burial history, hydrocarbon maturation, and generation would be simulated by 1D basin modeling (GENEX 4.0.3) specialized software to cover the full history of petroleum formation for the selected field and to delineate the source rock. The thickness of the

Oligocene and Miocene suggests very high sedimentation rate because of the observed high subsidence. These high sedimentation rate resulted from the model is accompanied by accumulation of mature organic matter observe from the vitrinite reflectance. Generally, from thermal maturity modeling are in harmony with the geochemical data indicating the Oligocene and lower Miocene coal or shale served as an effective source rock throughout the locality. The generation of the hydrocarbon from JL field in the basin initiated at 1800-2400 m depth.

RESULTS FROM 1D MODELING A set of wells were selected to

evaluate the history of maturation using the vitrinite reflectance index and generation from the JL area. A representative well JL-1 should be noted that using vitrinite reflectance method for

Figure 1: Burial history of JL-1 well in side chart 1 is Temperature in °C calibration versus depth and chart 2 is vitrinite reflectance versus depth model are included to show past and present heat flow of the basin respectively. It shows us sharp subsidence 0.7 km from 0.4 to 1.1 km and almost with slight or no uplift.

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maturation stage estimation is not a simple problem because this method is reliable only for vitrinite from coal layer; it is less reliable for vitrinite reflectance from terrestrial organic matter in clays with total organic carbon (TOC) <0.5% (Monzer Makhons, et.al, 2005).

CONCLUSION It is believed that the lithology for the source rock is shale or coal within the age of Miocene to

Oligocene, with net thickness in at the range of 35-111 m, variable heat flow ranges of 50-110 mWm2 for present to 43Ma in age within the temperature range is 85-170 °C at depth interval of 1238-2049 m were determined from the model. The results in (Figure 2) clearly indicate that high sedimentation rate and vitrinite reflectance was one of the most decisive parameters for the quantity and quality of organic matter in the basin within Oligocene to Miocene times. From this point of view, the thickness of the Oligocene and Miocene suggests very high sedimentation rate.

ACKNOWLEDGEMENT I have greatly profited initiation hints, kindly lavished interest in the topic of my research from my

supervisor AP. Wan Ismail Wan Yusoff thanks to him first and foremost to pass my deepest gratitude next to God.

REFERENCE Keneth Theis, Mansor Ahmad HamdanMohamad, Richard Bischke ,JeffreyBoyer, And Daniel

Tearpock, 2006, Structural And Stratigraphic Development Of The Extension Basin: A Case Study Offshore Deepwater Sarawak And North Sabah, Malaysia.

Magoon, L.B, and W.G.Dow, eds, 1994, Applied Source Rock Geochemistry, The Petroleum System-From Source Rock To Trap. AAPG Memoir 60, pp.93.

Monzer Makhons, Yu. I. Galushkin, 2005, Basin Analysis and Modeling of the Burial, Thermal and Maturation History in Sedimentary Basins.

PETRONAS, Petroleum industry of Malaysia, 1988 Mazlan B. Hj. Madon, Redzuan Bin Abu Hassan and Peter Abolins, 1999, The Petroleum Geology and

Resources of Malaysia, pp 273-455.

Figure 2: sedimentation rate and subsidence (These high sedimentation rates resulted from the model is the accumulation of high mature organic matter observing from the vitrinite reflectance. However, well data shows well data variation of sedimentation depends on subsidence of the area.)


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Figure 3: The formation age of the source rock, reservoir and seal are based from the simulation of the 1D modeling. As a result, it shows the realistic source rock age and determines the development of maturation to aid in the prediction of timing of hydrocarbon generation and expulsion.

Figure 4: Here the most important idea is that if we have the confidence where the kitchen is located (Figure 3) and we know current production has been found, we can use stratigraphic analysis of seismic record sections to predict where our probable distribution facies for the mature source rock . Sketch of North South Interpreted Seismic Section of JL-Filed Wells (the green color is the map of the extended source rock delineated)

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Reconstructing Mixed Fluvial-, Tide- and Wave-Influenced

Clastic Coastal Depositional Systems in the Early Miocene, Nyalau Formation, Sarawak Basin.

Meor Hakif Amir Hassan1,3, Howard D. Johnson1,

Abdul Razak Damit2, Peter Allison2 and Wan Hasiah Abdullah3 1Department of Earth Science and Engineering, Imperial College London SW7 2AZ, United Kingdom

2PetroleumBRUNEI, Unit 2.02, Second Floor, Block D, Yayasan Sultan Haji Hassanal Bolkiah Complex, Jalan Pretty, Bandar Seri Begawan BS8711 Brunei

3Geology Department, University of Malaya, 50603, Kuala Lumpur, Malaysia [email protected]

Introduction The Early Miocene (Cycles I-II) of the southwestern Sarawak Basin (Tatau-Balingian-Tinjar

Provinces) is comprised of thick (>6 km), vertically stacked successions of alluvial plain, coastal plain, coastal and offshore depositional systems. The lower coastal plain and coastal deposits are most variable having formed in a wide range of sub-environments. These are preserved in complex vertical and lateral vertical facies successions, recording spatial and temporal variations in depositional processes (variable interaction of fluvial-, tide- and wave-influence) superimposed on larger scale fluctuations in shoreline behaviour (regressive and transgressive). This is superimposed on larger scale cycles of regional coastal retrogradation.

This wide range of sedimentary environments and vertical facies successions is well preserved in outcrops of the Nyalau Formation around Bintulu, central Sarawak, which have been the subject of a detailed sedimentary facies analysis. We present the results of the facies analysis here, with an attempt to reconstruct the depositional systems, and explain the vertical and lateral facies variations by comparing it with present day tropical climate, mixed energy depositional systems along the NW Borneo coast, especially Brunei Bay which also display similar facies variations.

Results Based on the detailed sedimentary logging of c. 200 m of stratigraphy from 4 separate locations, nine

facies associations have been identified: 1) Offshore; 2) Lower Shoreface; 3) Upper Shoreface; 4) Prograding Tidal Bar / Mouthbar; 6) Tide-Dominated Channel; 7) Fluvial-Influenced, Tide-Dominated Channel; 7) Fluvial-Dominated Channel; 8) Bay Fill; 9) Mangrove.

FA 1: Offshore Up to 10m thick successions of bioturbated mudstone, wave rippled lenticular bedding and

structureless dark mudstone, interbedded with thin, graded and laminated siltstone and sandstone and thin, hummocky cross-stratified (HCS) sandstone. Moderate – strong bioturbation (Ichnofabric Index 3-5), with a diverse, mixed Cruziana – Skolithos assemblage.

FA 2: Lower Shoreface Up to 15m thick successions, composed of thin bioturbated mudstone interbedded with cm – dm thick

hummocky cross stratified sandstone, coarsening and thickening upward into amalgamated stacks of dm thick, fine grained, HCS sandstone beds. Sand content is high (50 - 75% of succession). Bioturbation is moderate, predominantly vertical trace fossils (Skolithos ichnofacies).

FA 3: Upper Shoreface Up to 6m thick, amalgamated stacks of fine – medium grained, hummocky cross stratified and planar

laminated sandstone beds, with intercalated mud draped, cross bedded sandstone. High sand content (>75%). Bioturbation moderate, mainly in the form of Ophiomorpha (Skolithos ichnofacies).


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FA 4: Prograding Tidal Bar / Mouthbar Up to 10m thick, heterolithic successions coarsening and thickening upward from sand streaked and

lenticular bedded mudstone, into wavy and flaser bedding, and cross bedded sandstone. The beds dip at a low angle to palaeo-horizonal (inclined heterolithic stratification). Palaeocurrents unidirectional, ebb or flood dominated. Bioturbation sparse (II 2), in the form of small and simple burrows (Planolites, Teichichnus).

FA 5: Tide-Dominated Channel Up to 6m thick, fining upward successions predominantly composed of clean, well sorted, cross-

bedded sandstone, wavy bedded heterolithics and thin sand-mud interlayering. Heterolithics commonly form packages of inclined stratification. Cross bed foresets commonly lined by thin, mud or organic debris drapes. Crossbed sets display uniform bed thickness. Alternating thick and thin sand-mud couplet packages (neap-spring cyclicity). Palaeocurrents unidirectional, and can be either ebb-dominant, or flood dominant. The base of succession is erosive, forming concave upward profiles, and commonly filled by mud clasts. Bioturbation sparse to strong (II 2-5), mainly in the form of small vertical burrows (Skolithos, Cylindrichnus), and simple horizontal tubes in mud drapes (Planolites).

FA 6: Fluvial-Influenced, Tide-Dominated Channel Up to 6m thick, fining upward successions predominantly composed of cross-bedded sandstone, wavy

bedded heterolithics and thin sand-mud interlayering. Heterolithics and cross-bed foresets display thicker mud drapes (>0.5cm). Interbeds of thick structureless mudstone. Common soft sediment deformation and fluid escape structure. The base of succession is erosive, forming concave upward profiles, and commonly filled by mud clasts. Bioturbation sparse (II 2), mainly Planolites.

FA 7: Fluvial-Dominated Channel Up to 6m thick, tabular, thinning upward successions predominantly composed of cross bedded,

medium grained sandstone, commonly intercalated with planar laminated sandstone, climbing ripples and wavy bedded heterolithics. Cross-bed foresets and heterolithics can be frequently lined by organic debris or mud drapes. Organic debris can form thick layers in between sandstone facies, or is finely dispersed in massive sandstone. Small, mud-filled channels are mainly composed of inclined stratification, in the form of lenticular bedding, and thin sandstone layers interbedded between thicker dark mudstone. Palaeocurrents are unidirectional and ebb-dominant. The base of the succession is erosive, forming concave upward profiles, and commonly filled by mud clasts, or laminated sandstone beds. Sand-mud couplets display irregularly spaced interlayering. Bioturbation absent or sparse (II 1-2). When present, trace fossils are in the form of small Planolites of Skolithos. Organic debris drapes are subtly burrowed by carbon lined burrows (Palaeophycus?).

FA 8: Bay Fill Thick sections of heterolithics. Mainly composed of lenticular bedded mudstone and rhythmites,

intercalated with thinner intervals of wavy and flaser bedding. Bioturbation is sparse (II 2), mainly in the form of small, horizontal burrows (Cruziana ichnoassemblage), eg. Planolites, Teichichnus.

FA 9: Mangrove Mud dominated successions commonly capped by thin, impure coal. Predominantly composed of

rooted, dark coloured, carbonaceous mudstone, sometimes associated with light colored, rooted mudstone. Abundant plant debris, including tree stumps and logs. Remnants of rhythmic lamination or lenticular bedding, mostly destroyed by generalised burrow mottling.

Stratigraphic relationships These facies associations are commonly preserved in erosively-bounded, vertical successions

(10s m thick), representing abrupt landward and seaward facies dislocations of lower coastal plain and coastal environments. A common vertical facies pattern comprises tide-influenced facies associations (5-30 m thick) that alternate abruptly with wave-dominated facies associations (5-30 m thick). The combination of both tide- and wave-influenced coastal deposits is interpreted as representing (1) a restricted, inshore depositional system (lagoon/bay environments), with both fluvial input and significant tide-influence, and (2) an open

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marine-facing, wave-influenced, shoreface environment, probably with barrier islands and associated sub-environments. The common association of mud drapes in hummocky cross-stratified beds of lower shoreface deposits also suggests mixed energy (wave- and tide-influence) conditions and high suspended sediment loads within the coastal barrier system.

Comparisons with present day environments: Brunei Bay There are four recurring depositional sequences: (1) coarsening upward shoreface successions that are

abruptly overlain by bay muds, mangroves, tidal bars and fluvial/tidal channels (progradational sequences), (2) incomplete shoreface successions that are deeply eroded by thick channel stacks or bay fills and mangroves directly overlying offshore mudstone (unconformable progradational sequences), (3) sharp-based shoreface successions that are abruptly overlain by bay/lagoonal facies (force regressive sequences), and (4) coarsening upward shoreface successions that are abruptly overlain by offshore marine facies (transgressive sequences). The abrupt vertical segregation of (1) inshore fluvial- and tide-influenced environments with fringing mangrove swamps, and (2) coastal to offshore, wave-/tide-influenced environments is reminiscent of modern sedimentary environments in Brunei Bay. Facies and sand body types in Brunei Bay are critically compared with those in the Early Miocene Nyalau Formation.

Modern day Brunei Bay displays an assortment of fluvial, wave and tidal environments, and is a possible analogue for the Nyalau Formation (Damit, 2000 unpublished; Lambiase et al., 2003). Tide-dominated channels are present in the subtidal regions of Inner Brunei Bay, enveloped by heterolithic bay fill muds. Prograding tidal bars composed of heterolithics are commonly bank attached in Inner Brunei Bay, and associated with estuary or delta mouths. The lobate shaped mouthbar of the fluvial dominated, tide-influenced Trusan Delta also displays a facies succession very similar to the elongated bars. Tide-influence distributary channels gradually become fluvial dominated as we move landward on the coastal plain. Mangrove vegetated tidal flats fringe the shoreline of Brunei Bay, and also gradually colonise abandoned delta lobes or tidal bars.

The tide-dominated Inner Brunei Bay is barred from wave and storm processes of the open sea by sand spits and barrier islands composed of storm and wave-dominated deposits.

References Damit, A.R. 2000. Brunei Bay, Northwest Borneo: Depositional System. Unpublished PhD Thesis, University

of Aberdeen: 529pp. Lambiase, J.J., Damit, A.R., Simmons, M.D., Abdoerrias, Hussin, A. 2003. A depositional model and

stratigraphic development of modern and ancient tide-dominated deltas in NW Borneo. In Sidi, F.H., Nummedal, D., Imbert, P., Darman, H., Posamentier, H.W. (eds), Tropical Deltas of Southeast Asia – Sedimentology, Stratigraphy and Petroleum Geology. SEPM Special Publication No. 76: 109-124


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PETROLEUM SOURCE ROCK EVALUATION OF THE SEBAHAT AND GANDUMAN FORMATIONS,

DENT PENINSULA, EASTERN SABAH

Khairul Azlan Mustapha and Wan Hasiah Abdullah

Department of Geology, Faculty of Science, University of Malaya, 50603 Kuala Lumpur, Malaysia. The Sebahat and Ganduman formations of Miocene-Pliocene age comprise part of the Dent Group.

The onshore Sebahat and Ganduman formations form part of the sedimentary sequence within the Sandakan Sub-Basin which, to a large extent is located in the southern portion of the Sulu Sea off eastern Sabah. The Ganduman formation lies conformably on the Sebahat Formation. The shaly Sebahat Formation represents the distal facies of a holomarine deposit while the sandy Ganduman Formation represents the proximal unit of a fluvial-deltaic system (Ismail Che Mat Zin, 1994). In the offshore, these formations are currently being investigated for their respective hydrocarbon potential. However, the available data on probable source rocks and their quality is sketchy. Thus, the present study has been undertaken to evaluate the oil-generating potential of the sediments from these two formations. The analyses performed include determination of Total Organic Carbon (TOC) content, bitumen extraction, Rock-Eval pyrolysis, Pyrolysis-GC, vitrinite reflectance and maceral analysis.

Based on the organic geochemical analyses, the TOC content of the Sebahat Formation sediments are generally high and considered to have fair to good hydrocarbon source rock (Peters and Cassa, 1994). The range is between 0.7–6.3%wt for mudstones, 21.3-22.1%wt for coaly sandstone, and 47.7%wt for coal. The TOC content in the Ganduman Formation sediments are slightly higher than the Sebahat Formation, ranging from 1.1–4.8%wt (mudstones), 12.4-14.7%wt (coaly sandstone), and 48.5-57.3%wt (coal). The crossplot of TOC vs S2 (Figure 1) summarize the source rock potential of the Sebahat and the Ganduman samples. Within both formations, the coal samples posses very good hydrocarbon generating potential and relatively decreased from coaly sandstone to mudstones.

The extractable organic matters are dominated by NSO compound, typical for immature samples. Fractionation of EOM (extractable organic matter) into hydrocarbon compounds (aliphatic and aromatic) , indicate that most of the mudstone samples posses common to adequate generating potential while the coal samples are rich in hydrocarbon compound (Figure 2).

The analysed samples of both formations are dominated by type III kerogen, and are predominantly gas-prone based on HI vs Tmax plots (Figure 3). Maceral point counting reveals that the dominant maceral composition is vitrinite (Figure 4). However, a significant amount (15-35% by volume) of liptinite maceral is present in the Ganduman Formation (Figure 4 and Figure 5) with lesser amounts in the Sebahat Formation (Figure 4). This evidence supports the high Hydrogen Index value of two coal samples from Ganduman Formation (141 and 387 mgHC/gTOC) as shown in Figure 3. The n-alkene/alkane doublets predominance in the Py-GC pyrogram with n-octene to xylene ratio of 0.5 for a coal sample (Figure 6a) suggests a mix oil and gas prone source rocks as been previously reported for the Nyalau Formation coals (Wan Hasiah, 1999). The mudstone sample on the other hand posses no hydrocarbon generating potential (Figure 6b).

Both formations are thermally immature to generate either oil or gas based on vitrinite reflectance values in the range of 0.20 – 0.35%Ro for Ganduman Formation and 0.20-0.40%Ro for Sebahat Formation (Figure 7). The Tmax data is in reasonably good agreement with %Ro values.

Although these onshore sediments are thermally immature for petroleum generation, the stratigraphic equivalent of these sediments offshore are known to have been buried to deeper depth (e.g. Leong and Azlina, 1999) and could therefore act as potential source rocks for predominantly gas and possibly minor oil.

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Figure 1: Cross plot of TOC versus S2 of the Sebahat and the Ganduman samples

Figure 2: Source bed rating of hydrocarbons compound derived from EOM


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COALBED METHANE(CBM) PROSPECT IN JAMALGANJ COAL FIELD, BANGLADESH

Md. Habibur Rahman

17/8, K. M. Das lane, Tikatuli, Dhaka 1203, BANGLADESH

Methane and coal are formed together during coalification, a process in which plant biomass is

converted by biological and geological forces into coal. The Methane that is stored in coal seams and the surrounding strata are released during coal mining.

Although coalbed methane (CBM) technology is yet to start in Bangladesh there is a good prospect of CBM development in certain coal fields especially in Jamalganj coal field. The high-volatile to medium-volatile bituminous coal of Jamalganj coal field is very suitable for CBM exploration in terms of their depth of occurrence, thickness of coal seam, coal reserve and areal extent. The thickest seam III (over40m ) can be a primary target for CBM development especially where it combines with seam IV in the eastern part of the coalfield. However, there are a number of unknown factors like actual gas content of coal, the coal permeability, and in-seam pressure that should be evaluated before the commercial CBM development.

In fact, interest in CBM development in Jamalganj coal field was shown by a multinational company. In early 1990s, the company submitted a proposal for undertaking exploration and development of CBM in Jamalganj coal field. They projected a conceptual target of producing 26 billion cubic feet gas per year. Accordingly, the total gas thatcould be produced would be about 340 bcf (0.34 Tcf ). However there was no report of a positive negotiation between the company and the Government of Bangladesh subsequent to the submission of the report.

Bangladesh is now badly in need of energy resources for her growing economy, that's why CBM exploration in Jamalganj coal field can be a very good option. It can provide natural gas that is equivalent to a small size gas field compared to eastern Bangladesh gas province.

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nguyen nam and larry fink - department of...

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