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PGCE 2011
- Conference date: 07 Mar 2011 - 08 Mar 2011
- Location: Kuala Lumpur, Malaysia
- Published: 03 July 2011
41 - 60 of 104 results
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Deghost + Denoise + Demultiple + Velocity & Q inversion + Depropagate = Seismic Imaging
More LessThe recent advances in seismic acquisition and processing have made it possible to obtain more accurate representations of subsurface geology than ever before. More accurate and advanced implementations of deghosting, denoise, demultiple and anisotropic velocity inversion and Qattenuation- factor determination techniques are the fundamentals of high resolution seismic imaging. Receiver-side deghosting through dual-sensor streamer (PGS), over/under single-sensor streamer (WesternGeco), single-streamer Broadseis (CGGV) or 2C/4C OBC acquisition & processing has become common practice whereby extending usable frequency bandwidth of seismic data. Denoising through filtering in a variety of data domains (shot, receiver, offset, cdp) through XT, FK,
TauP, FX, Wavelet-Transform based techniques are very successful and available from all vendors. Effective demultipling through short-period and long-period 2D/3D surface & interbed multiple attenuation techniques are essential for the success of the next steps namely: (1) Velocity & Q inversion and (2) Depropagation (Backpropagation) + Imaging Condition = Seismic Imaging (Migration). The best subsurface imaging approach PreStack Depth Migration method has to rely on highfrequency accurate background models as compared to earlier approaches which use smooth background models with some hard-boundaries as needed i.e. salt or carbonates. Otherwise, it is unlikely that reservoir imaging below challenging overburden settings will be resolved. To realize the
goal of high-frequency accurate background model building, direct-arrival tomography and reflection travel-time tomography, acoustic/elastic inversion, Q-tomography, full-waveform inversion techniques are being utilized to set up the appropriate background model for final imaging.
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Dip-Dependent Corrections for Data Reconstruction in Trueazimuth 3D SRME
Authors Peter Aaron, Roald van Borselen, Rob Hegge, Simon Barnes and Maz FaroukiThis paper presents a method to apply dip-dependent azimuth, midpoint and offset corrections during the data reconstruction in True-azimuth (TA) 3D Surface-related Multiple Elimination (SRME). The method is applied to synthetic examples and a field dataset. Comparisons are made with a TA 3D SRME which uses a more conventional differential NMO reconstruction, with no additional corrections. Results show that the new method is capable of correcting for primaries, diffractions, multiples and diffracted multiples. It is demonstrated that correcting for azimuth, midpoint and offset effects using geological constraints, during the data reconstruction can significantly improve the prediction of multiples in the presence of complex 3D events, such as diffracted multiples.
TA 3D SRME has already been shown to deliver a significant uplift in de-multiple when compared with 2D SRME and other zero-azimuth forms of 3D SRME (Aaron et al 2008). This is the result of honoring the azimuth of input traces by predicting multiples at the exact input source and receiver locations. However, in order to predict multiples with TA 3D SRME, a large number of traces are needed with a wide array of midpoint, offset and azimuth values. Since it is not feasible to acquire all of the required offsets and azimuths needed at each location, they must be reconstructed from the data that is available. While the differential NMO in the data reconstruction part of the SRME process attempts to correct for the offset difference between the desired trace and the best fitting trace, it does not correct for the differences in midpoint and azimuth. Our method corrects for the azimuth, midpoint and offset differences between the desired and best fitting trace. The dip-dependent TA 3D SRME was applied to an offshore field dataset and showed improvement in attenuation of the complex diffracted multiples when the dip-dependent corrections are applied during data reconstruction.
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Seismic Imaging Near and Within the Basement Offshore Malaysia; Including Comparisons of Imaging Algorithms
Authors Nabil El Kady, M. Shah Sulaiman, Zabidi M. Dom, Tang Wai Hoong, Lee Mei Lu, Pavel Vasilyev and Martin BaylyBetter 3D acquisition and better imaging have made it possible to explore complex basement plays in Vietnam, Indonesia, and the Malay Basin with some success. It is postulated that oil from adjacent formations may get trapped (under favourable conditions) in vughs and fractures within the basement. Imaging the basement architecture is a key issue (Deva Ghosh et al., TLE, April 2010, also; Areshev, 1992, Reservoirs in Fractured Basement on the continental shelf of Southern Vietnam, Journal of Petroleum Geology, Vol 15, Issue 3, pp 451–464). In this paper we describe the data preparation; velocity model building and migration methods applied to successfully image the data. The basement fractures are present at a variety of scales but to aid interpretation the larger, seismic scale fractures and faults need to be clearly imaged. In addition to imaging the basement, the seismic data processing flow also was designed to resolve and image shallower clastic horizons. Pre-processing of this data followed a generally industry standard marine data processing flow, however, particular attention was paid to the deep basement events and to the application of multiple attenuation type processes. This data exhibits a strong vertical compressional acoustic velocity change between the younger clastics and the harder, older basement, with the possibility of intermediate velocity metasediments. Due to the extreme spatial changes in depth of the basement and regional scale faulting there are strong and rapid lateral velocity changes within the dataset. This necessitates the application of pre stack depth migration techniques that can comprehend the lateral changes.
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Broadband Marine Seismic – Breaking the Limits
Authors Robert Soubaras and Carl NotforsThe importance of recording the full range of frequencies (low as well as high) is widely accepted. High-fidelity, low-frequency data provides better penetration for the clear imaging of deep targets, as well as providing greater stability in seismic inversion. Broader bandwidths produce sharper wavelets and both low and high frequencies are required for high-resolution imaging of important features such as thin beds and stratigraphic traps. The industry has been facing many issues that have limited the performance of marine seismic surveys with respect to bandwidth. Among them, we find mechanical and acoustic noise, source and receiver ghosts and attenuation with depth. Until recently, conventional de-ghosting was found to be sub-optimal. Thanks to recent advances in technology and also in operational capabilities, we have seen several improvements, in particular with the use of solid streamers, deep towing and notch diversity. We describe a different technique to achieve broadband marine streamer data. The proposed
solution is a new combination of streamer equipment, novel streamer towing techniques, and a new de-ghosting and imaging technology. It uses receiver notch diversity to yield a broadband spectrum and takes full advantage of the low noise and low-frequency response of the new generation of solid streamers. As a result, the method creates an exceptionally sharp and clean wavelet for interpretation. It can be tuned for different water depths, target depths and desired output spectra.
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Seismic Imaging Below Shallow Gas Cloud – A Comparison Between PSTM, PSDM & 4C OBC Datasets
Authors Tan Boon Hua, Amy Mawarni M. Yusoff and Gunawan TaslimSeismic data degradation due to shallow gas cloud is a common occurrence in the Malay Basin. As with many fields with large structures located in the central axis of the Malay basin, the field under study in this paper is also beset with this issue. This field, which is currently in the development stage, is a 30km long by 10km wide E-W trending elongated four way dip closure intersected by N-S & E-W striking normal faults. Two main structural culminations can be observed on the field. The major culmination lies to the eastern side of the field while a smaller one lies to the western side. The field is found to contain both oil and gas accumulation. A marine streamer 3D seismic survey was acquired over the field in 2002. The survey was acquired with an E-W line
orientation. This 3D survey data was originally processed using Pre-Stack Time Migration (PSTM) in 2002. Amplitude and frequency attenuation of reflectors were particularly severe on the two crestal culminations from approximately 800ms onwards. This problem was attributed to the presence of shallow gas and is further compounded by the presence of multiply stacked gas zones below the shallow gas. As a result, a number of key problems were inherent in the dataset, namely depth uncertainties especially at the crestal zones, fault imaging uncertainties within the gas cloud and also vertical resolution issues. The 2002 dataset was reprocessed using Pre-Stack Depth Migration (PSDM) in 2009. The aim of this exercise was to improve seismic imaging within the gas cloud, to improve vertical resolution via increased sampling rate, to increase the signal to noise ratio via new processing technologies such as SRME & model based Q and also to reduce depth uncertainty by deriving a high resolution velocity model representative of the changes in geology. Overall, the PSDM data did demonstrate improvements in terms of reflector continuity and frequency content within the gas cloud area. Fault imaging uncertainty, even though still present, has also improved as the fault interpretation within the gas cloud was carried out with greater confidence. Depth prediction at wells based on the PSDM has also shown improvements over the PSTM based prediction. Despite these improvements, the fundamental uncertainties in the dataset remain present as they were inherent to the acquisition process itself. Also in 2009, a 4-Component Ocean Bottom Cable (4COBC) test line was acquired over the gas cloud zone on the eastern culmination of the field. This operation was carried out to demonstrate two key points. The first was to demonstrate the feasibility of carrying out an OBC acquisition in the studied field while the second and more important point was to demonstrate the data quality improvements of the OBC data over conventional streamer data. The 4COBC test line was acquired in a N-S orientation as opposed to the E-W orientation of the streamer acquisition with the intention to undershoot the gas cloud, and thus give better imaging. Preliminary results from the 4COBC data has shown marked improvements over the streamer data on the particular test line in all imaging and structural aspects which were noted earlier. These results suggest that 4COBC seismic acquisition is feasible in this field and is probably the methodology that will give the best imaging of the field under today’s technology. In summary, this paper has demonstrated that the 2009 PSDM has managed to improve the seismic data processed via PSTM in 2002. However, the problems faced by the 2002 PSTM attributed
to shallow gas cloud are still present in the 2009 PSDM dataset as they are inherent to the acquisition process. In order to break away from these problems, a 4COBC survey may be the way to go. Such a survey dataset can potentially enable the many structural & imaging issues of the seismic dataset to be resolved within the development phase of the field.
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4D Seismic Analysis of Reservoir Sands Overlying a Salt Structure
PETRONAS Research has recently embarked on a study to determine and understand
pressure-saturation variations in a field through the use of 4D seismic technology. Changes in
hydrocarbon pressure and saturation due to production produce noticeable changes in amplitude
response. 4D seismic or the use of repeated time-lapse 2D/3D seismic surveys enables detection of
4D signal indicative of pressure or saturation changes.
The C field is located some 80 km due east of the coastline of West Africa. Water depth
ranges from 739.3 to 823.6 m with area of 60km2. The oil and gas in the field are trapped in Early to
Mid-Miocene reservoir sands above a faulted dome caused by underlying salt intrusion. The dome is
faulted by low angle (45-60°) radial faults. A dominant east-west fault set subdivides the structure
into an uplifted area in the north and a downthrown area to the south, which is itself separated into
east and west fault blocks by a large north-south fault. Hence, the faults compartmentalize the field
and hydrocarbons into three main fault blocks. The reservoir represents mid-slope turbidites which
consist of a series of fining upwards sequences.
Conducting 4D seismic analysis and understanding pressure-saturation variations involve
integrating several geophysical technologies. These technologies include well-synthetic-seismic
correlation, Rock Physics, Production Scenario Seismic Modeling at selected injector/producer wells, 2D/3D seismic modeling, 4D AVO Modelling/Interpretation and correlating seismic attributes with
engineering data, pressure history and saturation measurements.
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4D Seismic Interpretation in Angsi Field
Authors Tan Chin Kiang, Wahyudin Suwarlan, Kartina Ali and Fariz FahmiSome brown fields have the 4D seismic technology applied successfully to optimize reservoir production and recovery. This paper describes a case study on Angsi field where by the 4D seismic has contributed significantly as input to the reservoir dynamic model as well as for a deeper understanding of the reservoir behavior. This paper illustrates key lessons that we have learnt from the 4D application, focusing on feasibility study, QC during interpretation phase and 4D information on the reservoir management.
The Angsi field is located 167kms NNE from Kerteh, offshore of Peninsular Malaysia with average water depth 69m. The depositional environment of Angsi field is fluvial coastal plain environment. The field was discovered in 1974 with exploration Angsi-1 and subsequently followed by 7 appraisal wells. Oil and gas have been produced since 2001. Water injection was the chosen technique to manage the reservoir pressure during depletion. Understanding the water movement and response is the concern in the water injected field. The base seismic survey was acquired in 1995 while monitor survey in 2006 after 5 years of production. The primary objective of the 4D was to monitor the water movement from the injector wells. The success story of the technique in Angsi field is the ability to map the water movement in I35L reservoir, understanding the reservoir compartmentalization issues, pattern of preferred water movement and reducing the reservoir quality uncertainty.
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Major Controls on Deepwater Reservoir Distribution, West Africa
The study of Major Controls on Deepwater Reservoir Distribution, West Africa was mainly focus on the risk factor associated with reservoir sandstones in the deepwater areas of West Africa covering Cameroon, Equatorial Guinea, Gabon, Congo and Angola. Based on previous unsuccessful exploration results by Petronas up to 2006, it was found that the main factor for this is due to poor understanding of reservoir distribution in the region. This study was carried out to gain a better understanding on the geology of West Africa, particularly with regards to the transport and delivery of sediment from onshore to deepwater areas along the West African margin. This involves a study of the margin evolution both onshore and offshore areas. The primary objective of the study was to improve the understanding of sediment supply to the basins offshore West Africa, with the aim to enhance the prediction of reservoir distribution and quality. Understanding the entire sediment distribution system from source to sink is fundamental to improve models of reservoir distribution and quality. The hinterland analysis allied to a review of offshore data, can significantly enhance the fundamentals of this source to sink sediment distribution system.
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Transgressive-Regressive Cycles in the Malay Basin: the Interplay of Tectonics and Sea Level Changes in a Silled Basin
By Mazlan MadonUnderstanding the interplay of tectonics versus sea level changes in sedimentary basins has important economic implications. In rift/extensional basins, stratigraphic onlaps and pinchouts can form important hydrocarbon traps. Onlap plays develop on the basin margins during transgressions, whereas reworked/re-deposited shallow water sands and turbidites deposited during regressive events may form basinal plays. Transgressive-regressive cycles in a deforming rift (extensional) basin are strongly influenced by both eustatic sea level changes and tectonic subsidence/uplift. To explore for such plays it is important to understand how these major factors control sedimentation.
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From Depofacies to Lithofacies: A Way to Integrate Facies and Rock Types into 3D Geocellular Models
More Less3D geological facies modeling has been confused in the past with 3D petrophysical rock types (PRT) modeling. The efforts made by sedimentologists trying to understand the 3D geometry of facies and their distribution in the reservoir, sometimes are not well used by modelers who base their facies definition on petrophysical cutoffs which normally don’t follow sedimentological concepts. There are many important implications when determining facies using petrophysical cutoffs: 1. Even though petrophysical properties are initially delineated by sedimentation processes, they are normally altered by diagenetic processes (Morad, et al 2010). This causes mismatches between core described facies and facies based on petrophysical cutoffs. 2. It is not possible to capture the log signature of the facies which is linked directly with their 3D shapes (Serra, 1986). This causes, for example, that sandstones deposited in canalized systems which normally exhibits a bell or cylinder GR signature can be treated as those deposited in fan shapes which exhibit funnel log signatures. 3. There is a bias when selecting core plug for determining petrophysical properties (Terzaghi, 1965). Normally the sampling is concentrated in medium to high quality reservoir rocks and shales are not sampled. This causes that during clustering in crossplots for defining facies, data is not representative of the bad rock quality facies. This paper presents a methodology for facies modeling integrating core facies definition, conceptual geological models (depofacies and petrophysical rock types. Two field cases, one in South America and the other in South East Asia are used to apply this methodology.
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High Resolution Biomarker Technique for Source Facies Interpretation of Malaysian Oils
Malaysian crude oils discovered in the relatively young Tertiary Malay, Sabah and Sarawak basins are generated by variable source facies (PETRONAS, 1999). This is shown by the wide spectrum of biomarkers derived from different precursors present in the oils. Nevertheless, the two main source facies are the fluvial-deltaic, found in great abundance in the Baram Delta and offshore northwest Sabah, and the mixed fluvial-lacustrine found mainly in the Malay Basin. All these oils show presence of, albeit in varied abundance, terrigenous derived biomarkers such as oleanane and bicadinanes, indicating variable contribution from high land plant organic matter into the depositional environments (Awang Sapawi et al., 1991; McCaffrey et al., 1998; Peters et al., 2005). Characterising these oils into oil families based on their biomarker fingerprints is rather time consuming, simply due to the numerous biomarkers present in the samples and extracting the biomarker parameters. Thus, it was thought that a simple, but accurate method is needed to determine their source facies and classify them into oil families. In this study, an attempt is made to develop a high resolution biomarker technique to provide a quick and accurate method to determine the source facies of oils. This geochemical interpretation tool was developed using a combination of significant biomarker parameters plotted in the form of cross- or ternary-plots. For this purpose, a total of 38 crude oil samples collected from various petroleum basins were selected for this study. Some of these oils were used as end-members for three main source facies, namely, fluvial-deltaic, lacustrine and marine. End-member oils are those oils whose biomarker fingerprints represent a specific source facies mentioned above. From the numerous biomarker parameters or ratios generated, selected ones were statistically treated using hierarchical cluster analysis (HCA) and principal component analysis (PCA). Parameters with high PCA loadings were then further selected and tested using cross- and ternary-plots to determine the usefulness of the parameters and subsequently select the most significant parameters to be used as source facies interpretation. Results show that only a few biomarker parameters are essentially needed to distinguish the different source facies into fluvial-deltaic, lacustrine, marine and carbonate when used in appropriate combinations. These parameters are:
Oleanane Index
Homohopane Index
Hopane/Sterane ratio
100*(Ta+Tb)/C27 steranes ratio
C26/C25 tricyclics ratio
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Correlation of the Subis Limestones with Equivalent Limestone Bodies in Offshore Balingian Province, Sarawak, and Prupuh Limestones in Java
By Foo Yuan HanDetailed micropalaeontological studies of the foraminiferal assemblages were carried out to resolve the biostratigraphy correlation and depositional environment of the Subis limestone, the limestone from offshore Balingian Province and the Prupuh limestone.
Most of the foraminifera examined in the samples is consisted of larger benthic foraminifera. Larger benthic foraminifera are important contributors to modern and ancient tropical, shallow-marine sediments. The modern ecological studies of larger benthic foraminifera such as their environmentally sensitive depth distribution, reproductive strategy and morphology and the symbiotic relationship between many larger foraminifera and photosynthetic algae is a powerful tool to develop palaeoecological models of the studied areas. The Balingian Province lays mainly offshore central Sarawak and is bounded by the west Balingian Line to the west, the Central Luconia Province to the north, and the Tinjar Province to the South. Samples from wells offshore Balingian such as Sompotan-1, Rebab-1, Serunai-1 were studied and can be tied to the Subis location. (Mazlan, 1999). Subis limestone is a member of the Tangap Formation at Niah. The Tangap formation is composed of calcareous shale, marl, calcareous sandstone and limestone. Limestone is either interbedded with calcareous shale or forms a massive sequence (Haile, 1962). Prupuh limestone is a member of the Kujung formation. It is located in north-east Java. The Kujung formation is the oldest formation exposed in the East Java area. The age of Kujung Formation has been established as latest Early Oligocene to Early Miocene. (Duyfjes 1941; Najoan 1972; cited in Lunt et al. 2000). The foraminifera observed in the Subis area and offshore Balingian are free living taxa which
are indicative of high energy environment. Miogypsina sp., Nephrolepidina sp. and Amphistegina sp. are mostly confined to shallow warm waters of normal oceanic salinities. Amphistegina in particular are more abundant in shallow, warm, clear waters of high carbonate contents. The calcareous algal assemblage is mostly composed of encrusting forms. Such forms are known to be found in shallow turbulent water, of normal marine salinity and penetrated by sunlight. Thus the foraminiferal and algal assemblages found in the studied area indicate that the Subis limestone and offshore Balingian limestone was formed in a shallow water turbulent environment. The study of the seismic data of the offshore Balingian also indicates that the clastic sediments likely to vary over small distances reflecting changes in depositional energy that occur around coastal to shallow marine settings. The Subis limestone, limestone bodies from offshore Balingian Province and the Prupuh limestone, Java were developed on various parts of the Sunda plate. The Prupuh limestone is similar in age to the Subis limestone. The limestone from offshore Balingian was the extension of the Subis limestone. The ages of the Java samples have determined by strontium dating.
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Salinity Stratification and its Effects on the Malay Basin Biofacies Assemblages
Authors Mahani Mohamed, Shamsudin Jirin and Sanatul Salwa HasanSalinity stratification usually occurs when tidal currents and waves are not strong enough to mix the water column (e.g. in wave-dominated estuary). Such situation can lead to an anoxic condition because bottom waters can become isolated from dissolved oxygen (source: www.ozcoasts.org.au). Stratified salinity is a feature of partially enclosed seas and paralic environment (Debenay et al., 2000). In a stratified water column, the exchange of water and nutrients between layers is restricted, therefore there can be quite different water quality between the stratified layers; which has direct effect on the biofacies assemblages and distribution. (Debenay and Guillou, 2002). This biofacies event provides a possible explanation that for much of the Miocene, the Malay Basin might have been an enclosed sea, with a limited marine connection at the south to let saline water in.
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Development of New Correlations for Predicting Bubble Point Pressure and Bubble Point Oil formation Volume Factor of Malaysian Crude Oils
Authors B. Moradi, S.J. Hosseini, Birol M.R. Demiral and M. AmaniOne of the most crucial parts of the input data in petroleum engineering calculations is fluid properties data. From the exploration stage, these properties should be determined either by laboratory experiments or using some empirical correlations. Although, no one can underestimate the accuracy of the experimental results but these results are highly tied to the quality of the sample taken from the reservoir fluid and also, the condition of the reservoir can affect the quality of the sample. In addition, sometimes laboratory data is not available or maybe for double checking and comparison purposes, we need another source of dataset rather than experimental data. In this situation, empirical correlations can be a relatively reliable alternative. These correlations can predict physical properties of reservoir fluid under a wide range of pressure and temperature1. Among the properties of the reservoir fluids, Bubble point pressure (Pb) and oil formation volume factor (Bo) at Pb ,are essential in reservoir engineering calculations, since in improved oil recovery(IOR), if the reservoir pressure reaches to the Pb , the gas will start to evolve in the reservoir and due to the gas bubbles, the oil relative permeability will drastically decrease. Also, estimating Bo at Pb is quite challenging because this point is a inflection point in the curve of Bo vs. pressure and Bo is in its maximum value at Pb .So, it is very important to correctly predict it at Pb 2 . In this study, the new correlations has been developed to estimate bubble point pressure and oil formation volume factor of Malaysian crude oils. This correlation is applicable for crude oils of ranging between 26 to 54 ºAPI. The comparison of this new correlation with other published ones shows that it is much more accurate than the other ones.
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Sedimentology of Carbonate Buildup in Central Luconia, Sarawak, Malaysia
Authors Noor Alyani Binti Ishak, Zulfiqar Ali, Richard Bray and Eswaran PadmanabhanCarbonate rocks are usually complex and difficult to understand, because of the heterogeneity of fabric and depositional setup. Even though the carbonate platforms in the Luconia province contain numerous gas reservoirs; little is published about their geological evolution, lithofacies, depofacies, depositional environment and stratigraphy (Gartner, 2000; Epting, 1980, 1989; Vahrenkamp, 1996, 1998). Alpha and Beta field that are located in Luconia Province are appraisals cum development fields that need a geological study as an input data for the 3D static model. Hence, Alpha and Beta field were proposed by PETRONAS Carigali Sdn Bhd for detailed sedimentological and stratigraphic study based on conventional cores and wireline data.
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Sedimentary Facies, Depositional Environment and Sequence Stratigraphy of Miocene West Baram Delta Core, Offshore Sarawak.
More LessSedimentological and high resolution sequence stratigraphy analysis was conducted on Cycle V Miocene sediment from West Baram Delta, Offshore Sarawak. The analysis focuses on characterizing the different sediment types, investigates the different depositional processes and environments which includes application of high resolution sequence stratigraphy. Seven lithofacies were identified based on the distinct characteristics shown in each facies. Using this lithofacies scheme, eight facies association were interpreted namely upper shoreface, middle to lower shoreface, lower shoreface, offshore, prodelta to delta front, lower estuary, distributary mouth bar and lagoon. It is interpreted that the cored intervals were deposited within a shallow water marginal marine to nearshore setting. Trace fossils are described as it forms an integral part of the main facies scheme and used as an aid to the characterization and interpretation of individual facies. Two parasequence sets were identified: (1) retrogradational parasequence set defined by eight coarsening and fining upwards parasequences; (2) a progradational parasequence set characterized by seven coarsening and fining upwards parasequences. The reservoir quality in the sediment is affected by factors such as clay content, bioturbation, sedimentological controls (lithology and grain size), thin laminations and also diagenetic factor such as siderite and calcite cementation. These factors can highly affect the reservoir properties and may increase or decrease the reservoir quality. Understanding the factors that control the reservoir quality and the heterogeneity of the facies, depositional environment and petrophysical properties is important in assessing the reservoir quality and distribution. This is to ensure a more
accurate evaluation of the reservoir architecture, more precise modeling of the reservoirs and better prediction for future development of the field.
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A Natural Laboratory for Fractured Granitoid and Metasediment Reservoirs at Redang Island, Terengganu
Authors Adriaan Bal, Hamdan Mohamad, Zulkifli A. Hamid, Garry Malo-Paul and Askury A. KadirThere are many classic outcrops that serve as example analogues for clastic and carbonate fields (e.g. Book Cliffs Utah USA or, locally, the Miri to Bintulu road-cut). But in our region there are very few documented fractured basement rock analogues. The Redang archipelago, Terengganu, Malaysia, with excellent granitoid and metasediment coastal outcrops (Khoo et al, 1988), is proposed as a natural laboratory providing excellent examples of meso- and macroscopic scale structural features. This archipelago offers a variety of fracture types of different genesis within a relatively small easily accessible space (45 min flying from KL) located 45km off the coast of Kuala Terengganu (Figure 1). This poster documents the learning from outcrops recently visited by a
multidisciplinary team comprising geologists, petrophysicists, reservoir engineers, asset managers, and drillers.
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The Possible Significances of Coals Encountered in Cored Sections from the Central Malay Basin; Implications for Sequence Stratigraphic Interpretation and Basin Character
Cores recently acquired from E Group sections from the central Malay Basin, have been the subject of detailed and integrated sedimentological and palaeontogical studies in order to provide the basis for improved understanding of reservoir sequences. These studies have included detailed core description and dense sampling for combined micropalaeontological and palynological analysis. The results of these programs have revealed significant results that allow the coals to be confidently assigned to a particular phase of relative sea level and, furthermore, shed light on the nature of the overall receiving basin. Models have been developed to account for the sequences observed. These may apply more generally to the Malay Basin sections, although variations on this basic theme may occur. The coals studied have been shown to be of both freshwater and brackish origin, based on the palynological and micropalaeontological content. In all cases they represent phases of drying out of the basin, some being correlatable over wide areas. They are usually underlain by variably welldeveloped seat earths which show high levels of bioturbation/pedoturbation and also contain marine to brackish microfaunas. As such these seat earths often represent the most saline/marine sediments
in a given sequence. This is a feature of many seat earths in the Malay Basin that we have been able to study in addition to those from Sepat. The coals are generally rootleted, and the seat earths are pale grey in colour indicative of the soil zone leaching that creates such deposits. Peat accumulation is invariably terminated by a flooding event, although this may be freshwater, or brackish, based on the palaeontology and level of bioturbation. One of the coals studied occurs as a split seam, with an enigmatic conglomeratic lithology present in the intervening interval. The conclusion drawn from these observations is that at various stages of the fill of the Malay basin the areas was prone to regular drying out, with the establishment of widespread coal forming peats. River channels formed at the same time as these peats and dissected the area, which is thought to have been low relief, but occasionally flood events breached the channel margins and killing the peat mires, at least locally. Peat accumulation was brought to a close by flooding of the basin, either with fresh or brackish water. This suggests there to have been some form of barrier to the basin, preventing or restricting the ingress of saline water. The presence of brackish water coals may approximately locate the palaeo coastal belt for a given cycle and the upward change in coal character indicates increasingly freshwater conditions. This in turn suggests that peat facies belts may have been migrating basin-wards during phases of falling sea levels, resulting in the
establishment of more widespread peats. Reservoir sandstones in the cored sections were most probably deposited within fluvially dominated shallow water deltas or sub deltas in a lacustrine setting. These observations can be combined to allow a simplified cycle to be developed for the coal bearing intervals in the fill of the Malay Basin. Given that the seat earths appear to be the most marine parts of the section it is considered that the coal forming peats began to form with the onset of falling sea levels, with both the brackish and freshwater peats migrating basin-wards with the coastal belt. Basin-wards migration would have halted at the onset of transgression and thus the S.E. limit of a given coal would delineate the regressive maximum for a particular cycle. Thus the bases of coal beds are likely to be significantly diachronous. The tops of coal beds may also be diachronous. Variations in the make up of sequences occur, probably as a result of subtle interactions between sea level, subsidence in the receiving basin, and the tectonic or sedimentary factors creating a barrier at the S.E. end of the basin. Such short term changes in sea level, and consequently in the geomorphology of the Sunda Shelf, are unsurprising. Recent research (Sathiamurthy and Voris,2006) using Digital Elevation Models has shown the possible response of the area to glacioeustatic fall in sea level during the Last Glacial Maximum, some 21ka BP, when sea levels were some 116m lower than at present, with the development of former low-lying, potential lake, areas on the exposed shelf which formed Sundaland. Repetition of such changes is considered likely to have resulted in the accumulation of the strongly cyclical sequences typical of parts of the Malay Basin succession.
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Calibrating Carbonate Core Data to Wireline Data: Searching for a Relationship Between Petrophysical Properties and Mappable Depositional Trends
A common carbonate formation evaluation objective is to define a relationship between petrophysical properties and mappable depositional trends. If such a relationship exists, reservoir simulations and full field development plans are easier to formulate because we can infer petrophysical properties beyond the borehole using the depositional maps as a proxy. This poster focuses on describing the heuristic process of calibrating wireline logs from an offshore Borneo well that cored carbonate rocks. The process describes the different blind, but necessary, avenues followed to arrive at an optimal facies and petrophysical relationship. One lesson learned in this case study is that multiple methods of inquiry and the integration of different datasets and disciplines are paramount for a more effective understanding of results and the best way forward. A comprehensive data set was acquired including cores, NMR, full waveform acoustics, borehole images logs, and pressure tests. After data acquisition, a first-pass analysis of reservoir productivity was undertaken using methods outlined in Altunbay, et al (2007). These initial results provided a dataset for work by reservoir engineers. Concurrently, cores are described, plugged for porosity and permeability measurements, acquisition of mini-permeametry data, special core analysis, and thin sections are described. Borehole image logs suggest there are widely varying facies despite the core being largely uniform skeletal packestone (Figure 1). The resistivity image was unitized according to motif, for example predominately massive conductive or massive resistive, layered, or convoluted (Figure 2). The acoustic image logs were similarly unitized into facies largely reflecting acoustic impedance (Figure 3). Variations in resistivity and acoustic
fabrics were expected to relate to vuggy porosity distribution in the core. These image facies were later compared with core facies, logging petrophysical parameters, and when available, the core petrophysical parameters. Surprisingly, resistivity image
variation did not reflect vuggy porosity distribution. Acoustic images reflected variations in permeability. The core was mostly packestone with little variation. Thin section work showed that there was a heavy diagenetic overprint. Consequently, core petrophysical properties largely followed diagenetic trends rather than depositional trends. Ultimately, the first-pass analysis proved to be the best way forward. This is not to say that searching for mappable units is invalid. Ideally, we need mappable units to determine the 3D geometry of the reservoir and must search for these possibilities is a necessary requirement.
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Methodology in Surface Evaluation of the Fold and Thrust Belt Region
Authors W. Suraya Alssendra, M. Hilman, B. Roslan and Suhaileen ShaharFolded-belt is a distinctively challenging area for all type of E&P activities. Majority of folded-belts on earth are known non- working petroleum system. However some folded-belts are distinctively proven prolific hydrocarbon zone and active E&P area, for example in the Middle East. In areas where accessibility is a challenge, be it geographically or politically, a new method of geological evaluation is needed. There are also times where subsurface data is acquired but due to its low sampling and poor quality this could be a challenge to interpret therefore, a different method is required to assess the area of interest. Moreover, present-day challenging global E&P environment, forced us to look beyond our comfort zone and identify exploration opportunity in areas where we
are limited in capability. This presentation will discuss briefly on workflow and methodology used in evaluation and hydrocarbon prospecting of a folded belt surface evaluation.
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