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PGCE 2011
- Conference date: 07 Mar 2011 - 08 Mar 2011
- Location: Kuala Lumpur, Malaysia
- Published: 03 July 2011
51 - 100 of 104 results
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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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An Organic Geochemical Approach to Address Stratigraphic Issues: A Case Study of the Layang-Layangan Beds, Labuan Island, Nw Sabah Basin
Authors Patrick Gou and Wan Hasiah AbdullahThe three main geological units on Labuan Island which is located within the NW Sabah Basin include the Temburong, Setap Shale and Belait Formations. The Temburong Formation (deep marine turbidites) is the oldest, followed by Setap Shale (outer neritic to littoral) and Belait Formations (fluvial and shallow marine). The sediments are generally divided into two phases of sediment deposition by a major unconformity known as the Lower Miocene Te5 unconformity (after Brondijk, 1962), or more popularly referred to in the petroleum industry as the Deep Regional Unconformity, or DRU (Levell, 1987). This study is centred on the Layang-Layangan Beds that lie beneath the sandstone and conglomerate ridge of the fluvial Lower Belait Formation. Previous authors have assigned the Layang-Layangan Beds to all of the three major geological formations on Labuan Island; Belait Formation (Wilson & Wong, 1964; Lee, 1977; Albaghdady et al., 2003), Setap Shale Formation (Liechti et al., 1960), and Temburong Formation (Madon, 1994). This confusion is not surprising as the Tertiary sediments in the NW Borneo region can be very difficult to tell apart based on field observations or conventional geological methods alone. Geochemical results from the analyses of the Labuan sediments, which included thermal maturity related-data derived from Source Rock Analyzer (SRA), organic petrography and gas chromatography-mass spectrometry (GC-MS) were able characterise the different sediments as each of them have significant differences in their geochemical properties to produce unique geochemical profiles. The Layang-Layangan Beds display similarities in its geochemical profile with the overlying Belait Formation, while the Temburong Formation has a different and distinct geochemical profile
compared to the Layang-Layangan Beds and Belait Formation. However, the Setap Shale and Temburong Formations are geochemically quite similar to a certain extent. Consequently, the existence of the DRU on Labuan Island that is thought to separate the
Layang-Layangan Beds and the Lower Belait Formation is put into question since this regional unconformity surface is supposed to represent a drastic change in depositional environment (deep marine to fluvial), which appears to be a lot more subtle and gradual as indicated by the geochemistry data. The geochemical analysis workflow to characterise outcrop geology as demonstrated in this study is relatively cheap and simple, and should be considered when other geological methods do not give convincing results. In addition to that, it serves as a good and reliable independent method to verify ambiguous geological interpretations.
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Sedimentology of Laayoune-Dakhla Area Western Sahara Desert, South Morocco
Authors Zulfiqar Ali and Zainal Abidin B. JuniDirection des Resources Hydrauliques (DRH) drilled water well in Boujdour N° ANGER 1181/120, located at approximately 2.7 km in the North-East of Boujdour and at 50-100 m in the east of the Laâyoune-Boujdour road; Western Sahara Desert, Morocco. On test oil was encountered along with water, as a direct result PETRONAS Carigali Morocco Sdn Bhd. in collaboration with state owned oil company ONHYM decided to evaluate this area geologically for its hydrocarbon potential. The aims and objectives of the study were to carryout detailed sedimentological and basin modelling study to determine the depositional environment of expected reservoirs, hydrocarbon generation, migration and accumulation within reservoir horizons. But here we will discuss only
sedimentology of the basin that will explain reservoir characterisation, distribution and geometry within the study area. Sedimentological investigation was planned in onshore Laayoune-Tarfaya area, in-order to understand the reservoir distribution, facies interpretation and depositional environment of major synrift and post rift mega sequences.
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Echinoderm Palaeoecology from Fragments: A tool for Facies Recognition in Mesozoic Carbonate Sequences
More LessEchinoderms such as crinoids (sea lilies), are a major component of the marine benthos from the late Palaeozoic onwards, where they occurred in such high number so as to be rock forming. On death echinoderms will typically disarticulate into many thousands of ossicles which are considered by many palaeontologists to be indeterminate (Benton and Simms 1995). Research into Mesozoic fossil crinoids has demonstrated that there is currently a lack of understanding of their environmental palaeoecology. This is in part due to taxonomy based soley on exceptionally preserved whole specimens. Thus it has become necessary to consider fragmentary ossicles in defining a more representative palaeoecology. Bulk sampling (10 to 40 kg) of Middle Jurassic (Bathonian) carbonate and muddy sediments of England, where marine environments ranging from open shelf to lagoon are represented, has yielded numerous crinoid ossicles. Extensive work on exceptionally preserved Middle Jurassic crinoids from northern Switzerland and British Lower Jurassic has enabled identification of crinoid ossicles from the English Bathonian to generic level (Hess 1975). Results indicate that the colonisation patterns of crinoids are strongly influenced by facies type, allowing the community structure of the crinoids to be clearly defined in ecosystems delineated by substrate type and degree of marine connection. Thus distinct crinoid communities, based on the presence and absence of generic indicators, can be deduced (Hunter & Underwood 2009). After being successfully developed, the ‘crinoid model’ was taken a stage further, with its application to three more echinoderm groups: echinoids (sea urchins), asteroids (starfish) and ophiuroids (brittlestars). Previously it was noted that lack of homology in the ossicles made identification beyond family level problematic within these groups. As with the crinoids, examination of complete specimens in museum collections has allowed the recognition of diagnostic ossicles that can identify tests, spines and marginal plates to generic level. These new data has allowed the construction of a model for echinoderm palaeoecology across marginal marine environments. The application of this model to marine environments outside the British Jurassic, such as the Middle Jurassic of France and the Western Interior, USA, has demonstrated that factors such as substrate and marine connection (salinity) have a greater bias than palaeogeographical and stratigraphic controls. I propose that the small size of these echinoderm micro-fragments and the large number found preserved, means that they can be used as tool for facies recognition alongside other more traditional fossil groups, such as foraminifera and ostracods and are far more informative than many other macrofossils currently used.
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A Geochemical Overview of Selected Palaeozoic and Mesozoic Petroleum Source Rock Analogues from Outcrop Studies, Peninsular Malaysia
More LessWith petroleum resources on the decline, oil and gas companies worldwide including Malaysia are on the lookout for unconventional petroleum accumulations. Part of this effort includes looking at older and deeper petroleum source rock intervals that could have generated hydrocarbons earlier that subsequently accumulated in older and deeper reservoir intervals. In Peninsular Malaysia, two main Tertiary petroleum systems exist (Madon et al., 2006; Tan, 2009). Madon et al. (1999) identified the Groups L and K lacustrine shales (Upper Oligocene-Lower Miocene), and Groups I and H fluvio-deltaic shales and carbonaceous/coaly shales (Lower-Middle Miocene) as the main petroleum source rock intervals for the Malay Basin. Deeper units such as sediments from Group M and pre-Group M (syn-rift) sediments are also believed to contribute to the petroleum system. The 2005 discovery in the south western part of the Malay Basin by the exploration well Anding Utara-1 penetrated a 220 m oil column in metamorphic rocks (Shahar, 2005). This is significant as it indicates the possibility of having hydrocarbon accumulations in older rocks. Such play is commonly referred to as the fractured basement play. It is believed that the Penyu Basin, which lies to the south of the Malay Basin, could potentially have similar plays as the basement there mainly consists of metamorphosed basalts and weathered tuffs (Fanani et al., 2006). However, the hydrocarbons for these fractured reservoirs, which are on basement highs are thought to be sourced from younger sedimentary rocks that are positioned lower/deeper in grabens. This study will evaluate the potential of older (i.e. Mesozoic and Palaeozoic) petroleum source rocks based on geochemical analysis of outcrop samples from Peninsular Malaysia. As the fractured basement play involves reservoir rocks that are of Cretaceous age or older, it is interesting to see if any organic-rich intervals from the Palaeozoic or Lower Mesozoic in Peninsular Malaysia could have contributed to earlier hydrocarbon generation.
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A New Approach and Prospectivity of Sand Injectite in Malaysia
Authors Askury Abd Kadir and Tengku Amran Bin Tengku MohdIn recent years, there has been increased interest in sandstone injectite features as a significant source for reserve calculation. Sand injectites are classified into ‘intrusive’ bodies, which result from the remobilization and injection of sand into fractures due to factors such as overpressure, hydrocarbon migration, diagenesis and seismicity. Their occurrences are in the form of sandstone dykes (discordant to bedding) and sills (concordant to bedding) structures. Typically, such fractures are in sedimentary strata. The development of technology and knowledge led the recognition of injectites as an attractive exploration targets with huge significance when planning and optimizing hydrocarbon recovery. They have long been considered mere geological oddities and often being
misinterpreted (Figure 1) for insignificant features as their thickness is beyond the resolution of conventional seismic data. Outcrop observation and subsurface exploration including cores, wellbore image logs and seismic sections (Figure 2) are typically utilized to recognize their assemblages and features. The objective of the study is to gain better understanding on the features and characteristics of injected sands as a new prospective fluid conduit in reservoirs as well as their mechanics, implications and challenges. This preliminary study has been conducted based on literature review of published papers, journals, books and other resources, which are gathered, analyzed and revised in accordance to the relevance of the project. Three case studies were analyzed on Gryphon, Volund and Alba Fields highlighting their successful explorations in terms of injectite styles and significance for exploration and production. The results provide better understanding on injectite features which contribute additional reserves, improve the connectivity between reservoir layers and are characterized by chaotically distributed, unconsolidated sands with high porosity and permeability, forming excellent pay zone. Injectite explorations in Gryphon, Volund and Alba fields showed their characteristics as good quality reservoirs which may not be simply ignored for future exploration targets. Do we have sand injectites in Malaysia? Perhaps, we need to re-examine an oil-prune formations in Malaysia which is more emphasis on sand injectite conceptual.
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Basin Modeling of Malay Basin Eastern Flank for Prediction of Source Rock Potential
Authors Ku Rafidah Ku Shafie and Lakhdar BenchillaThe offshore eastern flank of Malay Basin is considered a challenging phenomenon for petroleum exploration in the synrift plays. The large amount of quality data from Petronas provides an opportunity to reduce the uncertainty in geological risks to exploration success in these deep plays. The application of basin modeling technique such as PetroMod in petroleum exploration giving us the ability to illustrate petroleum generation history of potential source rocks in our study area. The 1-D basin modeling was carried out on 12 calibration wells in the eastern flank of Malay Basin with an objective to investigate the presence of mature source rock and hydrocarbon charging in the study area. The red-dotted box in Figure 1 shows the location of the study area where the
structural setting is severely affected by the tectonic evolution of the basin. Temperature data for calibration of present-day temperatures in the wells were obtained from the log header and the data were generally of good quality. Those data were corrected using
published methods, and results were generally consistent and reasonable. Most of the wells drilled in this block have penetrated the K and L groups and a few wells have penetrated the basement. Models were constructed within the PetroMod software program in the stan¬dard ways. The stratigraphy within each well was constructed as burial history by using the top formation depth and age. The deposition of all the stratigraphy in this area is based on the Regional Malay Basin Stratigraphic Chart (Figure 2).
Two source rocks were considered in this study: the Group L-Shale deposited during synrift episodes are widely interpreted as offshore lacustrine and the Group I that was deposited in the fluvial-deltaic environments (Madon et al., 1999). Hydrocarbon generation in Group L-Shale source rocks was modeled using Pepper and Corvi (1995) _TI(C), which should be appropriate for these source rocks. The Group L-Shale source rock was generated at 12.5Ma and significant oil generation was initiated at around 10.5Ma. The expulsion of large amounts of oil began at about the same time of the oil generation. This has allowed the oil to be trapped in the entire formation group (Epic Study, 1994).
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Prospectivity in the Slope Break Belts of Malay Basin Western Margin
Authors Ji Ping and Zuliyana IbrarimMalay Basin Western margin covers about 5000 km2, mainly with the steep monocline (up to 6 degree) tectonic background, which is different from other area of Malay Basin. In the Late Oligocene to Early Miocene syn-rift extension phase, Groups M, L and K were deposited in an alluvial-lacustrine setting. The slope break belts associated with fan system deposits make them a promising exploration area. The slope break belt consists of three main parts: slope, slope break and slope-toe. It can be originally because of tectonic, deposition and erosion. There are multi belts in the Western margin. And the results of the deposition are the basin floor fan, slope fan, subaqueous fan and other gravity flow fans. Lacustrine shales of M, L and K Groups are the main source rock in the area. The sandy fan bodies consist the high quality reservoirs. Lacustrine shales provide the top seal. Up-dip seal can be controlled by juxtaposition of sand against incised valley, palaeo-cliff, fault and sand pinch out. The key element and the risk is the up-dip sealing of the trap. Exploration history demonstrates the slope break belt is a good prospective area in Malay Basin. The exploration approach is also discussed, especially the geophysical studies.
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Some Differentiating Field Characteristics between the Belait & Lambir formations, North Sarawak.
Authors Mohd Syamim Ramli and E. PadmanabhanSimilarities between the general appearances of the Belait and Lambir Formation in the field have led to difficulties in distinguishing one from another. This differentiation is important as there is an ongoing E&P in this part of Sarawak. Selected outcrops from the northern and central Sarawak have been analyzed in the field to evaluate the difference between these Formations. Field observation suggested that there are at least eight differentiating characteristics between these Formations. In terms of sedimentary features, presence of asymmetrical ripple marks on the Belait Formation indicates a fluviatile environment whereas on the Lambir Formation, symmetrical ripple marks are much more common features. Cross-beddings on the Lambir Formation are also
abundantly found but it is not encountered in the Belait Formation. Fossil burrows of Ophiomorpha Nodosa are also common in the Lambir Formation but to a lesser extend in the Belait. Flow patterns features such as mud- and/or sand-filled channels are also a characteristics of the Belait Formation. Conglomerates of the Belait Formation can be found on the southern part of Sarawak. In terms of bedding and stratigraphy, heterolithics sequences are widely encountered in the Belait Formation outcrops, but rarely in the Lambir Formations. Observations on the proportions of sand and clay in these heterolithics sequences between the two Formations suggest that the Belait Formation possess a much sandier sequence. Presence of carbonaceous shales are also common in the Belait Formation whereas massive sandstones are more often encountered in the Lambir Formation. Despite these general differentitating characteristics, distinguishing some of the outcrops are still difficult as these features may not be present in all outcrops.
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Deep Overpressured Play: Second Lifeline for West Baram Delta, East Malaysia
Authors M. Hafizan Abdul Wahab and Jennifer Chin Li YenYear 2010 marks 100 years of exploration activities in the West Baram Delta offshore Sarawak, one of the most prolific deltas in Southeast Asia. Ever since, a total of more than 50 exploration wells have been drilled targeting the conventional Middle Miocene Topset Clastic Play. The declining trend in both exploration success and production rates in recent years is alarming, hence the increased urgency of testing a new play concept. The deepest well drilled recently entered an overpresurred zone at depth of about 4km, with hydrocarbons still being encountered at the last penetrated reservoir. This success has triggered numerous ideas for the new potential hydrocarbon play type in the much deeper and severe overpressured reservoirs. At these depths reservoir quality is the main risk associated with this new play. The biggest challenge for the exploration is associated with predicting the onset and magnitude of the overpressures as these have direct impact on in-place gas volumes, well design, and well deliverability.
This paper will discuss the new ideas behind evaluating the trap effectiveness, seal capacity, and reservoir quality of this overpressured play. With a renewed exploration campaign targeting the deep overpressured play it is believed the West Baram Delta HC province can be rejuvenated.
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Structural Styles of the North West Sabah and West Sulawesi Fold Thrust Belt Regions and its Implication to the Petroleum System – A Comparison
Authors Nor Farhana Nor Azidin, Allagu Balaguru and Nasaruddin AhmadOffshore North West (NW) Sabah and West Sulawesi are located in highly complex fold and thrust belts within the Sundaland plate. NW Sabah hydrocarbon exploration started in 1897 with the drilling of the Menombok-1 well. The first seismic data in the West Sulawesi were acquired in 1968. In term of geological structural evolutions in NW Sabah and West Sulawesi both areas have experienced several phases of deformation from Paleocene until Pleistocene.
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Study of Upscaling Permeability from Thin Sections Using 3D Pore Space Image and Pore Network Modeling
Authors Luluan A. Lubis and Zuhar Zahir Tuan HarithDigital rock physics technology has effectively proved in reducing time and cost to predict physical properties of reservoir rocks. However, most of the predictions are at pore-scale level. In this study we address our research on predicting permeability at core-scale. The study carries out numerical simulation on three-dimensional (3D) pore space images to predict permeability at porescale. A digital volume required for this numerical simulation is obtained from thin section images. From these images we reconstruct 3D pore space images using multiple-point statistics (MPS). Permeability from several pore space images are used to predict permeability at core-scale by using upscaling methods (arithmetic, geometric and harmonic method). The results from these predictions are expected to match well with the experiment.
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Characterizing and Modeling Natural Fracture Networks in a Tight Carbonate Reservoir in the Middle East
Fractured reservoirs are challenging to handle because of a high level of heterogeneity (Nelson, R., 2001; Bourbiaux, B. et al., 2005). In particular, natural fracture networks have a significant impact on the reservoir performance as they affect well productivity (Narr, W. et al., 2006). Therefore, understanding their significance through fracture characterization is helpful in well placement and field development. This paper presents an overview of efforts in building a 3D stochastic fracture model for reservoir characterization of a Middle Eastern tight carbonate field. This model is generated in FracaFlowTM through the analysis and integration of well data pertaining to fractures like cores (including oriented core), bore hole images (BHI), well logs, mud losses, production logging and well test data together with 3D Q-Seismic data [structural and seismic attributes and seismic facies analyses (Abdul, J.A. et al., 2010)]. The impact of lithology on fracture occurrence was quantified based on rock-typing and
distributed in a 3D geological model using a high resolution sequence stratigraphic framework. The length, dip angle and orientation of fractures as well as the shale content of the facies where they are present were defined to sort the tectonic fractures from the non-tectonic ones. It was found that multiple sub-vertical sets of diffuse fractures are generally associated with cleaner limestone units. Altogether, three sets of diffuse fractures were identified from borehole image data: N20°E, EW and N170°E. Large-scale fracture corridors, including sub-seismic faults identified from seismic analysis, were calibrated with core and BHI fractures through fracture data analysis workflows. The model finally incorporates two scales of tectonic fractures: diffuse fractures and large-scale fractures that have a direct bearing on well and field production behavior. The fracture calibration was also performed using the dynamic data set such as production log and well production data. Permeability at wells was computed in the DFN (Discrete Fracture
Network) model and matched with the real build-up data. These data were then used to propagate 3D fracture properties (fracture porosity, fracture permeability and equivalent block size or shape factor) in the upscaled geological model for constructing a full reservoir simulation model. The model proved to be very reliable as few changes of the fracture properties were needed to obtain a good history match.
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Kerogen Kinetics in Petroleum Systems Analysis: A Case Study Using Coaly Source Rocks from Malaysian Onshore Basins
Authors Peter Abolins and Wan Hasiah AbdullahKerogen kinetics, when incorporated into a petroleum systems model, play a key role in defined the timing of hydrocarbon generation, the composition of hydrocarbons generated, and hence the phase of hydrocarbons in the subsurface. Such roles and applications are discussed in various papers such as Pepper and Corvi (1995), di Primio and Horsfield (2006), and Stainforth (2009). In this study, bulk kerogen kinetics were derived for a selection of coal samples from the Malaysian onshore Tertiary basins of Batu Arang, Bintulu, Merit-Pila and Mukah-Balingian. These coals possess % vitrinite reflectance (%Ro) in the range of 0.42-0.60% thus are thermally immature to early mature for hydrocarbon generation. These coals are expected to have fair to good petroleum generating potential based on the HI values that ranges from about 100 to 500 mgHc/gTOC. Petrographically, these coals are observed to be dominated by vitrinite macerals with common occurrence of liptinitic kerogen (10-40% by volume).
The aim of this study is twofold. Firstly to compare the personalised bulk kinetics acquired here with those currently available from published literature. Secondly is to illustrate the impact of different kerogen kinetics and geochemical parameters in the context of petroleum system analysis that is commonly used in oil and gas exploration, specifically on the timing, quantity and type of hydrocarbon generated. This is achieved by incorporating the personalised kinetics and other geochemical parameters acquired here into simple generic 1D and 2D basin models constructed using the PetroMod software suite.
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Continuous Isotope Logging in Real Time While Drilling
Authors Martin Niemann, Jerome Breviere and Shell FEAST TeamStable carbon isotope (δ13C) values for light hydrocarbons (HC) are routinely used to characterise both the geochemical and geological systems encountered in the sub-surface; providing information on the HC source, thermal maturity and the occurrence of in-reservoir secondary processes (Whiticar, 1994) . Until now δ13C ratios of light HC’s are obtained from spot samples collected at the well site (Isotubes, gas bags, Vaccutainers, etc.) and analyzed off line. Depending on the geographic location of the well the reporting of gas isotope data might occur either weeks or months after samples are collected. In the latter instance the usefulness of the data for field development decisions is significantly reduced. Recent improvements in mud logging techniques now provide a tool for the continuous logging of methane (C1) stable carbon isotope values in real time while drilling. Such data provides a much higher vertical resolution with measurements every second with a typical accuracy of ±1‰. It is anticipated that δ13C measurements of ethane (C2) and propane (C3), as well as δD-C1 in real time will follow in the near future. Geoservices Isotope Logging is coupled with the Geoservices FLAIR system that provides quantitative analyses of C1 to C5 (HC’s from formation) and semi-quantitative analyses of HC’s up to octane and light aromatics (Breviere et al., 2002; McKinney et al., 2007) in order to enhance the interpretational potential of stable isotope values . The extraction of gaseous HC’s from the drilling fluid takes place as close to the bell nipple as possible under fully controlled conditions, including stable mud and air flows, stable temperature and stable pressure. The compositional analysis (FLAIR) is performed with a gas chromatographmass spectrometer (GC-MS), whereas the isotopic analysis is performed simultaneously by near infrared absorption spectroscopy. The application of this technology on a drilling site is new and field tests have shown that this technology is extremely robust and stable and performs well under
the harsh conditions on an offshore drilling site. Field tests have been performed throughout the world in order to test performance for different geological systems and especially different drilling conditions (encompassing variations for both oil and water based drilling muds, as well as differences in drill bit types). Results were compared with both Isotube data and WFT/DST gas samples. Comparison of Isotube and WFT/DST data revealed a good match, within the accuracy limitations of the Isotope Logging equipment. Further comparison indicated that the continuous character of Isotope Logging data reveals a much higher variability and complexity of δ13C-C1 depth profiles than previously observed with Isotube or Vaccutainer samples. These latter samples are only spot samples with an insufficient depth resolution to detect small scale variations and features. The high resolution of Isotope Logging real time data provides the means for in depth analysis of encountered fluids and their geological habitat, but also represents an interpretational challenge. Isotope Logging was successfully applied to delineate reservoir connectivity and compartmentalization, provided information about possible biodegradation processes within an oilcolumn and provided successfully real time information to decipher the nature of HC’s encountered in the subsurface. This presentation will provide an overview about this new well site service and discusses case studies focussing on reservoir compartmentalization and fluid separation based on
δ13C-C1 where compositional data are inconclusive.
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Litho-Facies Mapping for Qualitative Evaluation of Caprock Seal Capacity in Northeast Central Luconia Province, Offshore, Sarawak
Authors Shakila Mustaffa, Che Shaari Abdullah and Hamdan MohamadThe Miocene age Cycle IV equivalent carbonate pinnacles in Central Luconia Province Offshore Sarawak are very prolific hydrocarbon play type. However the petroleum system elements effectiveness for such play type proved highly variable for different pinnacles. The caprock facies identification and mapping highlighted in this project is an attempt to relate qualitatively the sealing rock facies type to the hydrocarbon column length preservation within the pinnacles. Interpreting seismic reflection pattern and calibrating with the well lithology profile are techniques used to classify the facies types and delineate the area of occurrence. The interval defined as caprock in this project is restricted to the stratigraphic interval spanning Cycle IV to Cycle VI (Figure 1.1). The
relative spatial distribution of the pinnacles encapsulated by distal pro-delta facies of hemi pelagic fine detritus indicated high likeliness of having hydrocarbon pool with significant column height compared with the pinnacles encapsulated by proximal delta facies.
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Integration of Fluid Inclusion Stratigraphy (FIS) in the Petroleum System Analysis of a Frontier Area in Sarawak Offshore Basin, Malaysia
More LessThe present study integrates the results of FIS into the petroleum system analysis of the North Luconia province and brings out a better understanding of the hydrocarbon generation and migration. FIS results also serves as a calibration to supplement the 3D geochemical basin modeling of the frontier deepwater offshore Sarawak basin. FIS technology is a rapid geochemical analytical technique that involves the automated analysis of volatile compounds trapped within micron-sized cavities in rock material taken from well cuttings, core or outcrop samples. These “fluid inclusions” are representative samples of subsurface fluids and are not subjected to fractionation during sampling or evaporative loss during sample storage for any length of time. Drilled cutting samples at equally spaced intervals from five offset wells analyzed to identify for any hydrocarbon presence. The FIS results in general indicate dry gas and some intermittent wet gas response anomalies in most of the wells. Anomalies are stronger in the pre-MMU section compared to the weak anomalies observed in post-MMU sequence in the wells. Well B shows gas-range hydrocarbon through most of the section with some intermittent wet gas spectra at several intervals. Thin sections show rare, blue-fluorescent, moderate gravity light oil inclusions in carbonate. Well C data reveals hydrocarbon anomalies in several zones with dry to wet gas responses, which is also proven by analysis of MDT gas samples. Well D indicates notable wet gas spectra near the bottom of the section with no visible liquid hydrocarbon inclusions or stain. Well E shows dry gas responses through most of the section with intermittent thin wet gas. Thin section of rare, blue blue-fluorescent, moderate gravity light oil inclusions is identified in sandstones. Well A contains very scarce low gas anomalies throughout the whole section and thin sections contain no visible liquid hydrocarbon inclusions or stain.
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Effective Reservoir Fluid Sampling Supports Reservoir Characterization
Authors Rahimah Abd Karim, Pedro Elias Paris Acuna, Wa Wee Wei and Sammy HaddadGood quality reservoir fluid samples are critical to ensure the accuracy of the captured fluid composition and thus accurate key reservoir fluid properties’ description, namely GOR, saturation pressure, density, and viscosity. Reliable characterization of reservoir fluid properties during the early stages of exploration and development is critical for understanding fluid composition, estimating reserves, and optimizing production or completion strategies.
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Geochemistry of Gas and Condensate in the Surma Basin, Bangladesh
The Surma basin, which contains very thick Cenozoic sediments more than 20km, produces more than 95% of gases and condensates in Bangladesh. The producing reservoirs of gases and condensates are fluvial deltaic to estuarine sandstones in the Middle to Late Miocene Bokabil and Bhuban Formations of the Surma Group, which are located below the regional seal in anticlinal structures formed in the late Pliocene and Pleistocene age. To understand the petroleum system in the Surma basin more clearly, we performed geochemical analysis for condensate and gas samples which are taken from wells in the major fields in the Surma basin.
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Representative Fluid Samples for Reservoir Fluid Evaluation and Flow Assurance Analyses: South East Asia Field
Authors Michael Tighe, Sammy Haddad and Lee Chin LimRepresentative fluid samples are essential to achieving high quality PVT and flow assurance lab analyses. This is especially important when downhole samples are acquired in an oil base mud (OBM) environment. These high quality samples are also needed to better understand reservoir and fluid behavior throughout the field life. This work presents a case study of an offshore field in East Asia that required high quality reservoir oil fluid samples for detailed PVT and flow assurance analyses. An oil bearing sand was
discovered during the development drilling phase of a predominantly gas bearing reservoir environment. It was required to take low contamination samples from this zone during the development drilling phase without compromising the primary well objective of completion as a gas producer. As such, samples had to be taken on wireline in an oil based mud (OBM) environment. Accordingly a carefully planned methodology and technology was planned and used to achieve the goal of obtaining reservoir fluid samples.
Samples acquired from a previous well in the field using traditional openhole wireline formation testing technology and methods resulted in relatively high contamination levels. High levels of OBM filtrate contamination typically have detrimental effects on the PVT analyses quality for both gas and oil samples. Rig time, cost and sticking risk also limited the time allowed for the wireline formation tester to stay stationary at a sampling depth. As a result, a decision was made to utilize a new sampling technology that allows the obtaining of low level contamination while minimizing sampling station and rig time. To achieve this goal, the job was carefully designed and monitored by operating company and service company experts in real time to ensure the required results. The sampling technology, method and field and laboratory results are presented in this work [1, 2, 3].
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A Comparison Between 1D and 3D Basin Simulations of Thermal Evolution and Hydrocarbon Generation - A Case Study in the South Malay Basin, Offshore Peninsular Malaysia
Authors Azlina Anuar and M. Jamaal HoesniOne of the first steps when undertaking a basin modeling project is to define the thermal evolution of the study area via 1D thermal calibration. The resulting thermal model, often defined by heat flow maps, is then applied to subsequent 2D and 3D simulations. This study offers a comparison between 1D and 3D thermal modelling of the South Malay Basin and illustrates the need to recalibrate the 1D thermal model before its application to a full 3D block simulation. A systematic approach towards determining the top-of basement heat flow in the South Malay Basin was adopted, taking into account the three main heat sources of the basin: asthenospheric heat (-factor dependent in rift settings) and radiogenic heat production from the crust as well as the sediments. Using basin modeling software, the heat flow variations through geologic time were determined by means of vitrinite reflectance (from standard measurement and FAMM methods) and measured present-day temperature data (from drill stem and production tests)
as the main calibration points. Three top-of-basement heat flow maps for the different stages of the South Malay Basin development, namely the pre-rift, post rift, and the pre-inversion and folding phases were initially defined via 1D thermal calibration (Anuar et al, 2009). Having established the 1D-heat flow distribution patterns through time by incorporating the relevant stretching factors as determined by Madon & Watts (1998), these maps were then used as input for the 3D maturity modeling.
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4D Effect from Saturation Variation Due to Fluid Movement Using 4D Seismic Acoustic Impedance Inversion Methods for Reservoir Monitoring
Authors Shuhadah Basaharudin, Nor Azhar Ibrahim and M. Firdaus A. HalimInversion method is the process of extracting the acoustic impedance (AI) profile for each seismic trace. The AI property is related to the layer properties of the reservoir-density and velocity. Meanwhile, velocity and density data can be obtained from well logs. Therefore the impedance inversion relates the seismic data with the well log data. The purpose of this study is to understand the changes in reservoir properties that could be predicted from the changes in P-impedance between the two surveys (base and monitor) and to obtain a time-lapse impedance model that can predict changes in fluid distribution that is due to production of hydrocarbons and also due to water injection (EOR) over the well X. All inversion algorithms suffer from non-uniqueness because there could be more than one possible geological model consistent with the seismic data. However, we can include the low frequency model (LFM) to constrain the final result and give a reliable and accurate inversion output. Low frequency information can be derived from well logs information or from the stacking velocities. The benefits of seismic inversion are numerous such as the broader bandwidth of the impedance data maximizes the vertical resolution and minimizes the tuning effects, interpreting volumes rather than surfaces is geologically more meaningful, removes the effects of the wavelet from the seismic bandwidth, reservoir properties are separated from the overburden, may provide quantitative predictions on the reservoir properties and possibility of extending the layer features beyond the seismic bandwidth.
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Channel Thickness Estimation Using Spectral Decomposition
The Spectral Decomposition provides a new, non-traditional approach to seismic interpretation and attributes analysis. This technique is used for imaging and mapping temporal bed thickness, channel and geological features over 3D volumes where the samples are subdivided into different frequencies ie; 10 Hz, 15 Hz, 20 Hz, etc (Kishore, 2006) . Different materials in the rock strata resonate at different frequencies, and therefore can be distinguished from one another by their frequency response. The Spectral Decomposition techniques is widely used and successfully done for channel thickness estimation in a field scale (Partyka et al., 1999, Hall, 2004). However, channel thickness estimation in a regional scale has not been widely done. This study is the first attempt in applying this technique in the Malay Basin with regards to the I group channel. This study covers an area of 40,000 km2 located in the southern half of the Malay Basin. As a control parameter the top I and top J were interpreted and 20 proportional slices were defined by using stratal slicing technique. For each interval the RMS amplitude was carried out to produce a channel map. The spectral decomposition technique was performed to estimate the channel thickness. 20 Spectral decomposition volume attributes were generated at each interval to estimate the channel thickness for I010 to I140 channels. The frequency range from zero to Nyquist frequency (125 Hz) was generated. In addition the frequency slice animator was used to review the Frequency tuning map to determine the Optimum Frequency (Fo). Subsequently, average velocity was utilized to calculate the channel thickness. As the conclusion it can be deduced that the Spectral Decomposition technique worked well in the study area where the results were found to be quite matched with the channel thickness value stated in the well information. For that reason, this technique was confidently applied to some areas that do not have any well control in order to perform the channel thickness estimation.
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The Onshore to Offshore Dent Group, Eastern Sabah from Sequence Stratigraphic Perspective: Implication to Petroleum Exploration
The prospective Sandakan sub-basin has been less explored even though some oil and gas discoveries has been made in addition to the numerous thermogenic gas show encountered in most of the exploration wells in the offshore Eastern Sabah. The gas and condensate was tested with flow rate as high as 15mmcfg and 500 bc/d in one of the wells, however the discovery of commercial size has yet to be made. The probable reason for this lack of success is insufficient seal integrity due to very high percentages of sand vs. shale. Field observation of the Dent Group outcropping in Dent Peninsula shows the occurrence of thick shale belonging to Sebahat Formation, the equivalent to the main reservoirs in the offshore. This formation together with younger Ganduman and Togopi Formations are collectively known as the Dent Group of Middle Mioecene to Pleistocene. The Group consists of post-rift sedimentary packages, overlying the older syn-rift Segama Group. It consists of fluviodeltaic to marine sediments, characterized by strong southeastward progradation into the offshore area. The onshore to the offshore correlation of the Dent Group is achieved through application of sequence stratigraphy. The group can be divided into 2 mega-sequences that consist of several higher
order composite sequences, namely Composite-Sequence 1 and 2. The older Composite-Sequence 1, consists of lithological units that has been described as Sebahat and Ganduman formations, while the younger, Composite-Sequence 2 consists of the Togopi Formation. The occurrences and distribution of the lithofacies of the Dent Group can be explained through subdivision of the sequence into composite systems tracts. The lowstand sequence set of Composite-Sequence 1 mostly sub-cropping in the offshore area, while the Sebahat Formation in the onshore represents the transgressive sequence set. The Ganduman Formation is interpreted as the highstand sequence set of the sequence. The transgressive Sebahat Formation offers a new look for its sealing capacity as well as reservoir potentials. The thick Sebahat shale outcropping on the Dent Peninsula is occurring in the offshore as well, and potentially sealing. On the offshore seismic sections, this shale is observed overlying the transgressive carbonate and thick lowstand sequence set of Composite-Sequence 1, which contain good reservoir facies. The facies of the lowstand sequence set is interpreted to consist of turbidites forming the fan-system and stacks of shoreface deposits forming the lowstand set of prograding wedges.
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Estimating Poisson’s Ratio from Elastic Impedance: A Case Study for Hydrocarbon Plays in Malay Basin
Authors Ang Chin Tee and Shaidin ArshadIt is now common for a 3D datasets to be processed as partial offset volumes to exploit the AVO information in the data. The amplitudes of near-offset stack relate to changes in acoustic impedance (AI) and can be tied to well logs using synthetics. Unfortunately, there have been no simple equivalent processes for far-offset stacks. However, the symmetry can be recovered using the elastic impedance (EI). EI provides a consistent and absolute framework to calibrate and invert nonzero offset seismic data just as AI does for zero-offset data (Connolly, 1999). An EI log acts as a platform to calibrate the inverted data to any desired rock property (SI, σ, μ, λ etc) with which it correlates (Connolly, 2010). Many studies on EI have been done on Gulf of Mexico, and a strong correlation was found between EI at 30° and hydrocarbon pore volume. This relationship was then used to estimate the in-place volumes for the field from the inverted 30° seismic volume. EI is also widely used to discriminate lithology and to distinguish fizz water from commercial gas concentrations (Gonzalez, 2004). Estimating the Poisson’s ratio from seismic is also crucial. Theoretically, one can invert a 90° angle stack which has amplitude that is proportional to changes in Poisson’s ratio. However, this
approach is difficult due to the sensitivity to residual moveout and bandwidth variations. On the other hand (refer to the equation above), EI has values equal to AI at normal incidence. If K = 0.25, then EI is equal to (Vp/Vs)2 at 90° which is closely related to Poisson’s ratio. This allows the construction of high angle stack, and then being calibrated and inverted using the equivalent EI log. Since the absolute level of EI(90°) is depending on the value of K being used, one should study for the optimum angle of EI that correlates with Poisson’s ratio at well locations. In this paper, we will perform this study for hydrocarbon plays in Malay Basin and validate the result by estimating the correlation coefficient. With the known optimum angle, we can estimate Poisson’s ratio from
seismic with the information from EI.
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Challenging Views towards Minimization of Multi-Component Data Complexities
Authors Amar Ghaziah, Riaz Alai and Hafizal M. ZahirThe acquisition of seismic multi-component data and the application of various multicomponent processing technologies have shown observable benefits in more accurate imaging of the earth’s subsurface. Although many successful and advanced technologies have been applied in the oil and gas industry with compressional waves alone, the help of shear waves in addition to existing methodologies has opened new opportunities to many oil and gas companies in finding new reserves. In addition to improved subsurface imaging using shear wave information, they are also inevitable in optimal characterization of reservoirs. Complexities in multi-component data occur when the wave front suddenly gets distorted due to sudden subsurface velocity changes. An increase of velocities corresponds to waves reaching subsurface salt bodies or hard volcanic rocks. On the other hand, lower velocities are directly related to waves passing through gas clouds, which is characteristic in Malay Basin environments. In this abstract, some challenging views will be discussed for waves passing through gas clouds and some examples will be shown on field data from the Malay Basin. The critical observations include lower amplitude reflections and minimal propagation of compressional waves, which create serious complexities and challenges in optimal illumination and imaging within these environments. In this abstract, we review existing efforts and important characteristics of compressional waves as well as shear waves related to data from the Malay Basin emphasizing the added value of shear wave energy towards enhanced understanding and characterization of oil and gas reservoirs.
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A Shallow Water CSEM Case Study: Qualitative and Quantitative Analysis
Authors Mazlan Md Tahir, Azani Abd Manaf and Siti Hassulaini Abdul RahmanControlled Source ElectroMagnetic (CSEM) has been proven to be a valuable tool for remotely detecting and mapping offshore hydrocarbon reservoirs. The method, described by Eidesmo et al. (2002), measures the electrical properties of the subsurface where replacement of saline pore fluids by hydrocarbons influences the resistivity of reservoir rocks. A CSEM survey was conducted in shallow water area (~90 m depth) where is located at the depocenter of the late tertiary west Luconia delta (Rajang delta), west of the Central Luconia Province, Offshore Sarawak, Malaysia. Generally, geological setting of the area is a regressive, prograding deltaic sequence interrupted by regional transgressive events Earliest Pliocene, Late Early Pliocene and Early to Mid-Pleistocene (Robertson Research, 1989). The basin deepened to the northwestern part of the survey area, where thick marine sequences were deposited during Neogene to recent. Receivers were deployed in two 3D grids to allow for inline and wide azimuth data covering
two main prospects which are 12 km apart. In addition, a single receiver line was deployed almost perpendicular to these grids to cover an elongated target not covered by the grids. The first pass analysis of the resistivity distribution was obtained through a qualitative approach (attribute analysis). This approach is limited to denoting one area more resistive than another, excluding actual resistivity values and accurate depth investigation. In shallow water, the measured data is dominated by an electromagnetic (EM) signal that has propagated along the air/water interface, commonly known as the airwave effect. The airwave effect in the data was reduced by decomposing the EM field into down going and up going component and removing the latter (Amundsen et al., 2006). After the airwave removal, the attributes obtained anomalous features over the prospect area, however this analysis is inconclusive. A quantitative (inversion) approach was later adopted, which can both account for the airwave and assign resistivity values in depth where sensitivity is provided. Anisotropic 2.5D and 3D inversion was applied and supported that the anomalous features observed in the qualitative approach coincide with high resistivity within the seismic prospect outlines. Even though both inversion
schemes (2.5D and 3D) reconstructed the resistive features, it is important to recognize the limitation of 2D data. A 2.5D inversion relies on a 2D approximation of the subsurface, rendering geometry changes orthogonally to the towline unresolved. A grid survey resolves 3D effects and anisotropy by combining inline and azimuth data, i.e. data from receivers both on and off the source towline (Morten et al., 2009).
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Methods in Estimating Visco-Elastic Properties for Gas Cloud Imaging : A Multicomponent Seismic and Rock Properties Analysis
Authors Ang Chin Tee and M. Hafizal Mad ZahirThe presence of gas cloud in the Malay Basin has always been a topic to be discussed when it comes to imaging the subsurface. Gas cloud has caused compression (P-waves) data acquired to suffer from poor data quality due to higher attenuation of P-waves, wavefront distortion which caused by low velocity distribution within the gas bodies and transmission losses. Converted shear wave (P-S waves) data from multicomponent acquisition allows images to be obtained that are unobstructed by the gas and/or fluids (Thomsen et. al 1997, Granli et. al 1999). In addition, rock properties can be uniquely determined from the compressional and shear data, allowing for improved reservoir characterization and lithologic prediction. This paper will discuss method for determining the optimal parameters of the velocity (V) and density (ρ) within the gas cloud for further input into P-S waves imaging.
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Integrating Sedimentological Core Study and Seismic Attributes to Define Fluvial Channel Characteristics in the Malay Basin
The integration of sedimentological core study and seismic attributes to define the fluvial channel characteristics has been carried out within the 3D seismic megamerge, in the seismic Group I, Malay Basin. The main objective of the study is to characterise the geometries, heterogeneities, properties, and classification of fluvial channel reservoirs in Group I. The study were carried out by utilizing the available cored intervals, biofacies analysis, wireline logs, seismic, and well data. The method used in this study is based on the core review program by evaluating the core-based results and integrating with the RMS seismic attributes results. The core review program utilizes both previous investigations as well as conducting new study on the cored sections. The cored interval included cores taken from the I-25, I-50, I-68, I-80, I-85, I-90, I- 100, and I-110 reservoirs, which were discovered from year 1978 to 2002. The depositional environments of the cored intervals were then interpreted based on the core lithofacies associations
integrated with biofacies characters from palynological and foraminiferal analyses.From the results of the core study, only cores from 3 wells have been identified as potential fluvial channel sandbody. The identified potential fluvial channels core data were later validated and verified with the available seismic data. The study has established new insights with implications on the understanding of the paleogeography of the Malay Basin for the I group. Based on the core facies analysis there are five main sandstone lithofacies identified from the fluvial channel facies of I25, I80, and I100 in Group I, Malay Basin. These are trough cross-bedded sandstone, massive sandstone, cross laminated sandstone, parallel laminated sandstone, and ripple laminated sandstone lithofacies. The best reservoir characteristics for the fluvial channels are shown by trough cross-bedded sandstone lithofacies. The core based characterization and classification of Group I have identified three key wells from reservoir I25, reservoir I80, and reservoir I100 as potential fluvial channel sand bodies. Specifically, comparisons are made as to properly integrating the core-based and seismic-basedinformation from horizon strata slice of RMS amplitude maps. The integrated study approach concludes that only two cored wells have been interpreted to penetrate fluvial channel sand bodies while other cores from Group I which were thought to be fluvial in nature based on previous work or their log profiles however indicate that they were deposited in more marine environments. The integration of sedimentological core study and seismic attributes has defined the fluvial channel classification in the Group I in the Malay Basin, capable of improving reservoir understanding.
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An Appraisal Well, from Geophysical Point of View: Do Not Simply Call it a Failure!
Authors Hijreen Ismail, Prama Arta and Bernato ViratnoThe field is located around 148 km from Bintulu, Offshore Sarawak. This field was discovered in March 2006 by Z-1 exploration well. The type of reservoir is a carbonate pinnacle. The recently drilled appraisal well X-ST1, has opened various perspectives. The production tests in the three different zones failed to prove the availability of a significant amount of hydrocarbon in the northern part of the field structure. However the successful VSP operation, manage to provide a new time depth relationship at the well location. The success also offered velocity control at the northern area and allowed reinterpretation works. The latest well correlation sets a new geological marker, whereby the Top of carbonate was found to be ~26 m shallower when compared to prognoses. Five horizons were reinterpreted. They are Top of carbonate and Top of zone 4, 5, 6, and 7. Using the new generated 3D velocity model, all the TWT maps were then converted to depth structure maps. When the generated depth structure map of Top of zone 6 was overlaid with gas water contact as found in Z-1 well, a saddle, which separates the southern pinnacle from the northern area carbonate platform in this zone, appeared to be suggested. Hence new resource assessment exercises had been conducted based on the new gross bulk volume (GBV). Consequently, it was gladly found out that there are 69% increase of volume in terms of calculated 2P GIIP. The drilled X-ST1 well also provided input on the quality of the carbonate in the northern area. The porosity bserved in this well is totally different from the Z-1 exploration well. In conclusion the X-ST1 appraisal well did provide noteworthy inputs to the understanding of the field structure and economic values to the company.
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Fit for Purpose Seismic Reservoir Characterisation
Authors Troy Thompson, Matthew Lamont, Carlo Bevilacqua and Natasha HendrickQuantitative seismic interpretation utilises seismic amplitude behaviour in conjunction with well log data, petrophysics and rock physics to make quantitative predictions about lithology and fluid away from well locations. Seismic reservoir characterisation in general cannot follow a one-size-fitsall approach – it is critical to consider local geological insight. It is also essential to determine the appropriate quantitative interpretation (QI) workflow based on available seismic and well data, and the desired outcome. Together, this will ensure robust and reliable characterisation of the hydrocarbon reservoir is achieved.
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Application of Seismic Attribute for Channel Imaging in the Malay Basin
A seismic attributes is any measure of seismic data that help us visually enhance or quantify features of interpretation interest (Chopra and Marfurt, 2007). Amplitude, Frequency and Phase represents different aspect of a seismic reflection that brings outs different aspects of geologic features.The purpose of this paper is to document the application of seismic attributes for channel imaging in the Malay basin at basin wide scale. Presently, channel characteristic in the I-Group has not been fully understood. Therefore, the utilization of mega merged data for this project is to help us better understand of channel morphology/characteristics in the Malay basin through the application of seismic attributes. The area coverage of this study is approximately 40,000km2 which includes the 3D mega merged volume in the southern half of the Malay basin and fifteen (15) individual 3D seismic volumes. Two (2) major horizons, I-TOP and J-TOP were interpreted for basin-wide interpretation of I-Group interval as shown in Figure 1. From this, twenty (20) strata/proportional slices were generated using stratal slicing techniques that were associated to I010 to I140 sands of the I-Group. Seismic attributes analysis on a small volume was carried out to identify the best attribute for channel imaging. The result shows that Root Mean Square (RMS) attributes reveals the anomalous amplitudes which represent channels outline (Figure 2) while frequency volume created from Spectral Decomposition has further enhanced the channel images (Figure 3). Future similar works could be expedited using this methodology and better define the channel outline.
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Gravity and Magnetic Signatures, Derived Crustal Structre and Tectonics of Sirt Basin, Northern Central Part of Libya
Authors Ahmed. S. Saheel, Abdul Rahim Bin Samsudin and Umar Bin HamzahThe Sirt basin is located in the north central part of Libya within the bounder's 270N-330N and 160E-220E. This study involves analysis of gravity and magnetic data to delineate structures and faults and to locate any major structures. The produced Bouguer gravity map shows prominent NW-SE and N-NW trends. Isostatic residual map is characterized by a dominant NW– SE trend in the study area. This is clearly evident in the isostatic residual. The main trending anomalies are in the northern and southeastern parts of the study area with NW-SE orientation. A strong NW-SE trend is truncated by E-W trending in the southeastern and southwestern parts of the area. This is consistent with change of tectonic zones (Duronio and Colombi, 1983). The magnetic expression in the northern part of Ajdabiya trough is characterized by NW-SE trending structures which coincide with late Cretaceous structures of the Sirt basin, while the southern part is characterised by NE-SW trending features which coincide with a late Paleozoic trend (Goudarzi, 1970, 1980). The northern part of the Ajdabiya trough is separated from the southern part by a prominent NE-SW lineament that is expressed in both the gravity and magnetic data. It is interpreted as a basement fault, which separates a thicker southern crust from a thinner northern crust. The high gravity anomaly within the northern part of the Ajdabiya trough is interpreted as a result of mantle upwelling which caused thinning of the continental crust beneath the northern part of the Ajdabiya trough. The Total horizontal derivative results of Gravity and Magnetic data (Cordell, 1979) ,(Cordell and Grauch, 1985), 3D Euler Deconvolution of gravity and magnetic data magnetic anomalies produced features trending similar to the positions of tectonic and geological information from the Sirt basin. High gradient values delineate NNW-SSE to N-S and NW-SE trends which mark the faulted southwestern, southern, northern and central boundaries of the basin, respectively. New faults with orientations NNW-SSE trends along the southwestern flank of the Sirt basin and is truncated by E-W faults dividing it into segments. Strong N-S lineaments occur over the southern and central part of study area and are well indicated by the 3D Euler Deconvolution. From this study the 3D Euler Deconvolution provides very useful information of the rift structures. Predictive modelling (2-1/2D) of gravity profiles was carried out for northern and southern parts of Sirt basin. Two profiles were controlled by wells. The deepest part of the northern profile is in the Ajdabiya and Al Jahamah platform and approximately depth from 3-6km. The deepest part along the southern profile is approximately 4.88 km in the Zallah and Hameimat trough.
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Seismic Imaging and Velocity Modelling Offshore Myanmar (Andaman Sea Basin).
More LessAll Geophysical Data Analysis/Processes are basically solving the inverse problem. One of the inversion methodologies is to derive Structure & Velocity via Seismic Imaging. The proper seismic imaging workflow is crucial in attenuating multiples and optimally images the seismic feature. This will further enhance the confidence level during interpretation and mapping and might all the way lead toward seeing flares. From pre-analysis/data preparation/data stabilization, analysis/data processing to deliverable of Pre-Stack Time Migrated Gathers require detail and precise technical analysis. The testing of 2D seismic line no. A, Offshore Myanmar, Andaman Sea Basin through PSTM has shown optimized subsurface imaging and better attenuation of multiples, which
can be seen in target zone from 3000ms to 4000ms TWT.
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Source of Coal Bed Methane
Authors Swapan Kumar Bhattacharya and Saleem Qadir TunioCommercial viability of a coal bed methane project exclusively depends on the available source of methane. By default it is expected that the source of methane is bacterial / thermal actions on organic biomass during coalification process. Carbon isotope signatures and chemical composition of the produced gases are not always favourable supports to the coal origin of the available methane. Moreover, all the major successful coal bed methane projects are geographically located over one or the other petroliferous basins. Does it mean that the coal bed methane has some intricate source relation with occurrence of petroleum?
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Post-Stack Cross Equalization for Time-Lapse Seismic
Authors Tan Chin Kiang, Wahyudin Suwarlan-PCSB, Kartina Ali and Fariz FahmiSuccessful 4D imaging requires high repeatability. Repeatability is a measure of similarity of two or more vintages of seismic data and is a function of acquisition geometry, ambient conditions and processing similarity. This paper illustrates a case study to cross equalize two 3D datasets acquired in 1995 (base) and 2006 (monitor) in a field with pressure maintenance support to analyze whether technology can be used for reservoir monitoring purposes. Prior to the cross equalization effort, the base and monitor surveys were processed together using a 4D co-processing workflow. Co-processing is done with careful choice of parameters to maximize repeatability and optimize production-related 4D responses. The cross-equalization process is done after co-processing to minimize any seismic differences unrelated to production (improving repeatability) and enhancing the interpretability of the real 4D signal. This is also the process that generates the final 4D volumes and 4D attributes for the interpretation analysis. The key steps in the cross equalization workflow include residual phase matching, static time shift, matching filter, amplitude normalization and time varying time shift. The accuracy of co-processing and consistent acquisition minimized the level of required cross qualization. Appropriate QC at each stage of cross equalization ensures that the desired 4D effect is preserved as the two datasets become increasingly comparable and look alike in the non-reservoir zones where ideally no change is expected. The final differences after cross equalization clearly shows high amplitude 4D anomalies around injector wells. The overall improvement of 4% repeatability was achieved through the cross equalization process. The 4D data successfully imaged both water and gas movement throughout the major reservoir and results are currently being used to update the geologic and reservoir simulation models as well as to support a drilling campaign.
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Seismic Facies Characterization of the Central Northwest Sabah Basin
The presence of reservoirs especially at the outboard of NW Sabah Basin is one of the major issues for the explorationist. Some of the wells were drilled targeting turbidites were unfortunately not successful. A total 15 regional 2D seismic lines from different vintages have been chosen as key lines for seismic facies description and facies mapping in order to established regional correlation from inboard to outboard Sabah and identify new hydrocarbon play, leads & prospects. The study area is located at the centre of NW Sabah Basin, which covered from inboard to outboard area. Generally the basin is bounded to the west by the West Baram Line & to the east by the Balabac Strait Fault. The Sabah Basin is a structurally complex basin that was form on the southern
margin of a foreland basin that resulted from the collision between the NW Sabah Platform and western Sabah during the early Middle Miocene. Its complex syn-tectonic sedimentary history resulted in the recognition of major unconformity-bounded sedimentary packages Stages IVA to IVF (Mazlan Hj. Madon et al., 1999). There are 4 major seismic facies characters had been identified, which displayed strong amplitude with wormy reflector, weak amplitude with wormy reflector, strong amplitude with parallel
reflector and weak amplitude with parallel reflector. Turbidite environment can be interpreted by identifying wormy reflector which usually represents channelized activity and also deepwater evidence such as gull wing character. Parallel reflector represents more quite and calm environment. (Walker and James, 1992). Integration of seismic characters with sequence stratigraphy approach will facilitate to interpret DOE and to produce paleo-environment map (Emery and Myers, 1996). This paleo-environment map will contribute to the petroleum system analysis within the area especially in term of presence and reservoir distribution prediction. Ultimately, this map would be able to explain why certain well is successful or vice versa.
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Geological Mapping Using Remote Sensing and Magnetic Data
In this project, Thematic Mapper (TM) and Digital Elevation Model (DEM) images, as well as magnetic data, were used to study the geological features of Kuh-e-Djahan Bin in Iran. Scanned geological map which was geometrically corrected was then used with TM and DEM images to extract geological information. Several analyses have been done to the images such as colour composite, principal component analysis, ratio and supervised classification. In order to evaluate the classification process, accuracy assessment was done to the classified images. The accuracy statistics was the measuring scale of the classification. In addition, contour and drainage patterns analyses were also done to extract elevation, flow direction and flow accumulation data to provide further information. Magnetic modelling with a small degree of unsuitability (misfit) between the model and the geological data was employed in order to compensate the subsurface interpretation. In a nutshell, these few named analyses were flawlessly facilitated in interpreting lithologic and structural geological features which was the interest of this study.
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Seismic Attributes for Reservoir Property Prediction - A Review
Authors Muhammad Sajid and Zuhar Zahir Bin Tuan HarithSeismic attributes are extensively used in prediction of reservoir property, such as morphology Properties and petrophysical properties of the reservoir. There is no direct relation exist between most of the calculated attributes and the measured reservoir property but still we can use these seismic attributes by statistically correlating them with the measured reservoir property at the well location. In this paper we will review the correlation of some of the important properties of the reservoir with the seismic attributes and how these attribute should be used to predict the reservoir desired property of investigation. We will describe how to select the different attributes to produce a meta-attribute (hybrid attribute) and how to use THESE META-ATTRIBUTES to map the reservoir property. We will discuss how other branches of geophysics (AVO, Rock-Physics) help us in more reliable reservoir property prediction.
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A Low Frequency Seismic Survey in an Exploration Environment
Spectraseis and PETRONAS acquired a low frequency (LF) passive seismic survey over a producing field and a series of leads and prospects in south-Asia. Efficient field operations and close coordination among all involved parties provided a good quality dataset with minimal environmental impact and HSE exposure in only 9 days of recording. Despite the presence of high levels of noise from exploitation activities and interference from a strong near surface effect, detailed analysis and careful processing returned results that are reliable and consistent. The LF results show a good correlation to well results, with both productive and dry areas correctly identified. The survey also extended over undrilled prospects. Good quality results over the known areas extends the usefulness of the survey, adding information to the body of geophysical and geological knowledge for ranking further exploration and appraisal prospects in the area.
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3D Coil Shooting Survey on Tulip Field: Data Processing Overview – Planning, Challenges and Opportunities
The Tulip 3D survey is a single-vessel Coil Shooting project east of Kalimantan, offshore Indonesia. The coil geometry is very different to the conventional race-track towed streamer approach. Whilst it results in many acquisition and imaging benefits, the circular geometry introduces several differences, a number of new challenges and opportunities in data processing. A fit for purpose processing workflow was tailored to address the challenges, and at the same time taking advantage of the opportunities provided by the circular geometry. The Tulip survey area is geophysically very complex due to the presence of several unfavourable geological factors, especially in the near surface. In particular the rough sea bottom and very bright Bottom Simulating Reflectors (BSR) below the seabed generate several orders of multiples and degrade the subsurface illumination. The presence of free gas below the BSR causes a sudden frequency and amplitude decay of primary reflections. Complex subsurface geology further complicates the scenario. All these conditions when combined result in very strong and high orders of surface multiple reflections, diffracted multiples, absorption, scattering and poor transmission of seismic signal energy. The consequences of these complexities is overall poor seismic response, very low acoustic impedance contrast at the reservoir level and therefore extremely low amplitude or near invisible target reflections, very low signal-to-noise ratio (S/N), poor imaging and poor illumination of the reservoirs. In order to achieve a better imaging of the zone of interest and for the appraisal campaign, eni successfully acquired a Coil shooting (French, Cole, 1984; Durrani et al, 1987) survey on the Tulip discovery. The acquired data was processed through to depth imaging utilizing multiazimuth tomography velocity model building. The circular geometry introduces several differences and new challenges in survey design, modeling, acquisition and processing workflow (Reilly, Hird, 1994; Reilly, 1995). For Tulip survey, a careful pre-survey modeling and processing simulation was critical to evaluate the feasibility of future post-acquisition processing of the survey, with respect to both the geophysical challenges and the geometry induced constraints and opportunities. Prior to the commencement of the acquisition, a subset volume of 3D synthetic data with coil geometry was generated to assess the application of 3D processing algorithms. When processing a Coil shooting survey, the first difference, compared to the conventional data, is the presence of the turn noise due to acquiring data while the vessel and cables were tracking continuously in circles. The level of noise is inversely proportional to the curvature radius of the circles being acquired and proportionally related to any apparent crossflow of currents.
The second aspect and very different to the conventional processing is related to the spatial sampling, with the Coil shooting geometry, the trace offset distances are not regularly spaced in the shot or midpoint domain. This result in the midpoint/offset clustering inside the circles and inducing some apparent geometrical or moveout distortion in the seismic reflections, which makes the application of conventional straight sail line based processing methods unsuitable. The third and perhaps the main
challenge related to the Tulip's geometry is the although very high, but irregular fold of coverage, resulting in amplitude footprints, which change position as a function of the incidence angle, and require proper treatment in order to avoid amplitude inconsistencies and migration artifacts. On the advantages and opportunities aspects, the circular geometry allows the full 3D processing algorithms to work at their best. The true-azimuth 3D demultiple tools work very well for the Tulip survey. The same conclusion is valid for velocity model building and migration algorithms due to the large azimuthal content. This paper will discuss some of the pre-emptive measures taken during the survey design stage prior to both acquisition and processing as well as the overview of the processing experience of the Tulip project and some relevant results.
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