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PGCE 2011
- Conference date: 07 Mar 2011 - 08 Mar 2011
- Location: Kuala Lumpur, Malaysia
- Published: 03 July 2011
1 - 50 of 104 results
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Application of 3D Basin Modeling to Address Hydrocarbon Charge Risk in a Frontier Area, Offshore Sarawak Basin, Malaysia
Authors S.R. Iyer, S.K. Bhattacharya, Shahrul Amar Abdullah and P. AbolinsAnalysis of offset wells in a frontier exploratory area located in offshore Sarawak identified hydrocarbon generation, migration timing with respect to trap formation, and migration fairways into the drilled prospects as the key uncertainties in exploration. A semi constrained 3D basin modeling study was undertaken based on regional 2D depth maps and calibration from offset wells to address the uncertainties. Three source rock units viz. Rift, Cycle-I and Cycle-II, from older to younger sequence, below a major regional unconformity were modeled, constraining the boundary conditions with regional geological understanding. Four geological scenarios were run, to account for uncertainties in mapping the top of basement, and also in fixing the duration of erosion for the
unconformity, which has a direct impact on timing of deposition of the regional top seal. Source rock maturity and transformation ratio based on modeling suggest that Cycle-I source is in optimum window in the study area for charging the identified traps. The older Rift source is expended by around 20 Ma, with possibility of charging only the deeper Cycle-I traps. Cycle-II source over major part of the study area is in immature to early oil stage. It can be an effective source in the southern and western parts of the study area where maturity is adequate due to deeper depth of burial. The distribution of hydrocarbon accumulation modeled is validated by two of the offset wells with hydrocarbon discovery. Compositional kinetics indicates dominantly vapor phase for the
accumulation in discovery well location, consistent with samples recovered through MDT. Modeling results suggest significant hydrocarbon generation and expulsion in the study area. However, the total hydrocarbon accumulated is relatively small compared to the quantity expelled, as the peak migration timing predates the major unconformity over which the regional top seal section was deposited. Reducing the duration of erosion and early deposition of top seal has increased the volume accumulated, but the parameter remains a key uncertainty due to limited well control. In the absence of direct evidence from well data, the present study has improved the understanding of the frontier area and aided in preparation of play fairway map to risk leads/prospects. The current base model can be refined by incorporating additional data from future exploratory activities. The present approach is a very useful tool in screening new exploration blocks and their ranking.
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Sequence Stratigraphic Study of Block 16/19 and Zambezi Delta Block , Mozambique Basin, Offshore Mozambique
Authors Dayang Hasspariah Binti Sapri and Othman Ali Bin MahmudBlock 16/19 and Zambezi Delta Block (ZDB) are located in the offshore Mozambique about 350 km to the north of Maputo the capital of Mozambique (Figure 1). Sasol Petroleum International (Pty) Limited is the operator for Block 16/19 and Petronas Carigali Mozambique Exploration and Production (PCMEP) is the partner with 35% working interest. Zambezi Delta Block was operated by PCMEP but relinquished in 2009 due to unsuccessful exploration.
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The Discover Way towards More Realistic Enhanced Resolution Seismic inversion – A Field Test
Authors Dominic Lowden, Bruce Webb, Jennifer Graham and Vincent W.T. KongOptimum seismic inversion requires that the input data have the broadest possible frequency bandwidth coverage. Normal seismic data generally lack the low frequencies, and these are then usually augmented by low frequency models derived through various forms of spatial Well log interpolation. However, the low frequency models do not sufficiently represent in detail localized geological variations. In the pursuit to acquire broader bandwidth seismic data, Hill & Bacon, 2006 [a] wrote about the Over/Under acquisition and processing technology, following which, Özdemir et al, 2008 [b] described the optimized deghosting of Over/Under lowed streamer data in the presence of noise. Krach et al, 2010 [c] further elaborated on the technique for improved resolution and deep imaging. The DISCover method is a new modified Over-Under technique in seismic acquisition to yield a seismic dataset that is richer in the low frequencies without loss of high frequent content. These seismic spatially-sampled low frequencies do carry important smaller scale geological variations within the subsurface, and together with a minor contribution of the ultra-low frequencies from the Well log data, greatly improve the seismic inversion results. The Field test was conducted at the NW Shelf of Australia (Fig 1). The DISCover operation technique is discussed. The seismic data from the DISCover method is compared with that from a conventional survey technique (Fig. 2A and 2B). The implication for seismic inversion is demonstrated, with results for a more consistent pay geobody extraction made possible by using the DISCover dataset (Fig. 3).
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Fan Mode Shooting to Reduce Infill Rates for Marine Seismic Acquisition in Areas of Strong and Unpredictable Sea Currents
Authors Budi Priasati and Stephen ElliottConventional towed marine seismic reflection surveys are typically designed to acquire a uniform surface coverage across the area of interest. However, given that the streamer spread is anywhere between 200 and 1000m wide and generally between 3000 and 10,000m long, sea currents often force the streamer to divert significantly from the vessel path or modify the streamer shape. This results in reduced coverage for some offsets or offset ranges, or in an extreme case, a complete lack of coverage or “hole” in the data. Such coverage holes can vary in size, regularity, and sample density leading to problems in the processing of the seismic data and ultimately degrade the quality of the final image. As a result it is necessary to acquire a program of infill to ensure that the survey is properly sampled. This is typically between 15 and 30% of the total kilometers of the survey, resulting in a proportional increase in costs and survey time. Recent deployments of streamer steering devices have shown great value in mitigating this
effect by maintaining streamer shape and matching adjacent line feather. However, it is also possible to actively steer the streamer to acquire a larger sub-surface swath at the tail. Fan Mode Shooting is a 3D marine acquisition technique where the streamers are deployed with variable separation with offset (Figure 1). Since the high frequencies are attenuated at longer offset and depth, the bin size can be increased with offset and depth, without damaging the quality of the final data. Monk (2010) has recently shown that adopting this methodology dramatically reduces the amount of infill required and produces significant cost savings. This paper will present a regional case example of how 'Fan Mode Shooting' was successfully used to reduce the infill requirement during a marine seismic acquisition in South China Sea between June and August 2010 (Figure 2).
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Analysis of Stress Condition of Faults in Oil-Gas-Bearing Areas Using GIS and Remote Sensing Data
More LessThe lineaments have been determined for the North-East of the European platform (the Timan-Pechora oil-gas-bearing province) using remote sensing data. The obtained data were combined with the geological-geophysical information into the geoinformation system for further processing and analysis. GIS technologies allows integrating all the variety of available data on the structures into a uniform system and enables carrying out of researches in the view of all possible data (DeMers Michael, 1999).
The work used space images taken by satellites Landsat-7, which provided imaging of the Earth’s surface with application of six channels with resolution 30 meters, and one IR-channel with the resolution 60 meters with simultaneous panochromatic imaging with resolution 15 m. The width of the review for all channels made 185 km. The data were geopositioned in Gauss-Kruger projection on Krasovsky ellipsoid in the system of coordinates SK-42, the tenth zone. Then rectilinear sites (lineaments) were determined by the elements of landscape. Lineaments are generally understood as linear heterogeneities of the earth's crust and lithosphere. They can be of a various rank, extent and depth. They can develop on surface directly or as geological and landscape anomalies. Lineaments are caused by latent breaks of basement, fracture zones in sediments, etc. Lineaments and lineament zones are zones (channels) of the raised permeability of the Earth's crust. They serve as transiting ways for solutions and gases, which generally possess higher temperature in comparison to the surface of the Earth (Kats Y.G., 1986). Also in fracture zones, especially sedimentary basins, the fluid system is constantly present and redistributed. It results in intensive deformations in fracture zones, and, hence, in their expression in the landscape attributes reflected on space images in the form of lineaments (Kuzmin Y.O., 2004). Therefore, the shape of lineaments on space images is a generalized reflection on the surface of both deformations and fluid mode of near-surface areas of the Earth's crust. Lineaments are possible to divide into several types by their extent: transcontinental, transregional, regional, local. Lineaments, resulted from various discontinuous dislocations, have characteristic features.
Faults result from stretching of the Earth's crust, incline toward deeper rocks. Lineaments, formed by the given type of dislocation, are characterized by linearity, frequently with offsets, which divide blocks with various geological structure and type of relief.
Thrusts are a little bent, round and formed as a result of literal compression. Shears are characterized by horizontal displacement of rocks. Lineaments near them are developed along unidirectional curvatures of riverbeds, slopes, watersheds and other various forms of relief. Overthrusts are resulted from longitudinal compression with formation of folds. Lineaments in this case are developed in the form of complex scalloped pattern of displaced masses. The form of the lineaments, their pattern can help to define kinematic and geodynamic conditions of formations of faults and conditions of their formation. The intensity and width of lineaments depend on the depth of occurrence of a fault and its activity. The account of all these data by the form, sizes, intensity allows considering faults and geodynamic conditions of the studied area.
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AVO Application for Carbonates Reservoir Characterization in Sarawak Basin
Authors Noreehan Shahud and Yeshpal SinghRecent development in geophysics technology keeps improving to fulfill the need of energy resources. Geoscientists have to think out of box and be creative to come out with ideas on how to fully utilize all available data to find more hydrocarbons within specify budget. In order to provide optimum analysis, a proper feasibility analysis shall be carried out to set some expectation before embarking for full project. In reservoir characterization analysis integration of both geophysical and geological data is a must for quantitative seismic interpretation. This paper will focus on the application of Extended Elastic Impedance (EEI) attributes for characterization of carbonate reservoir heterogeneities in the study area. The study field is located in the Central Luconia Province which forms part of Sarawak Basin of Northwest Borneo. The carbonate build-up in this field overlies Cycle III mixed clastics and carbonates. As a result to the extensional tectonics at the end of Cycle III, submarine topographical highs were formed, where reef growth took place during Cycle IV/V. The middle Miocene Carbonates are hydrocarbon bearing and is the main reservoir interval seismic characterization. In the study area, the major challenge is the very small carbonate interval (~65-95m) and imposes a major
constraint for seismic-well integration for reservoir characterization. Rock physics analysis based regional trends have been utilized for characterization of deeper interval. Prior to EEI feasibility study, all input data are quality checked. In general, both seismic and well data are prone to operational issues, which may affect the data quality and quantity. Nevertheless, with proper planning and better understanding on the technical parameters needed for optimum reservoir characterization, modeling and analysis could benefit in achieving the objectives. A high correlation coefficient of elastic parameters with optimum “chi” angle provides “tuned” results to the desired output. The EEI were used to separate lithology and fluid effects.
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Multi-Disciplinary Pore Pressure Prediction : Reconciliate Geophysics and Basin Modeling to Control Risks and Uncertainties in Drilling Operations
Authors G. Lecante, P. Wojciak and N. BianchiAccording to many operating companies, a very large part of unscheduled downtime during drilling is related to pore pressure and fracture gradients. In that respect, the ultimate objective of pore pressure prediction is to control the risks and uncertainties related to drilling operations. Anomalous pressures in geological formations can originate from many physical phenomena – such as: sedimentation rates, fluid expansion mechanisms, etc. – which can be accurately modeled using advance 3D Basin Modeling Techniques, applied at local scale. Thanks to their ability to rigorously simulate the multiple phenomena occurring within a geological basin (especially compaction disequilibrium, hydrocarbon generation, fluid buoyancy), basin modeling tools can be applied for
modeling the coupling effect of pressure, overburden, effective stress, fracturation gradient, porosity, fluid density, temperature, permeability. On the other hand, pore and confining pressure generally have opposite effects on acoustic elastic properties of the rock (compressional velocity in particular): velocity generally increases with confining pressure and decreases with pore pressure. Consequently the joint analysis of interval velocity variations and compaction trends gives allows assessing pore pressure. Geophysics has therefore been widely used over the past decades for predicting over-pressured zones. Such zones are detected with seismic (interval velocity) and sonic transit time. In most cases the strong increase in transit time in the over-pressured interval indicates the degree of overpressure. This change in the transit time is generally detected in the seismic interval velocity also. In practice, pore pressure predictions are performed using one of these two independent approaches without any attempt to combine them, while their combined used would gives a better confidence in the predicted pore pressure values, despite the high uncertainty due to lack of data. The objective of the study presented in this paper is to reconcile these two complementary
approaches. It shows one way of integrating the two techniques throughout the prediction process.
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Shallow Seismic: An Analog Study of Fluvial Depositional Systems in the Malay Basin
More LessThe study of Major Controls on Deepwater Reservoir Distribution, West Africa was mainly focus on the risk factor associated with reservoir sandstones in the deepwater areas of West Africa covering Cameroon, Equatorial Guinea, Gabon, Congo and Angola. Based on previous unsuccessful exploration results by Petronas up to 2006, it was found that the main factor for this is due to poor understanding of reservoir distribution in the region. This study was carried out to gain a better understanding on the geology of West Africa, particularly with regards to the transport and delivery of sediment from onshore to deepwater areas along the West African margin. This involves a study of the margin evolution both onshore and offshore areas. The primary objective of the study was to improve the understanding of sediment supply to the basins offshore West Africa, with the aim to enhance the prediction of reservoir distribution and quality. Understanding the entire sediment distribution system from source to sink is fundamental to improve models of reservoir distribution and quality. The hinterland analysis allied to a review of offshore data, can significantly enhance the fundamentals of this source to sink sediment distribution system. The main deepwater reservoirs in the West Africa offshore areas are the Cretaceous and Tertiary turbidite channel and fan deposits. Major controls on deepwater reservoir distribution, are a combination or interplays of regional tectonics, eustasy, sediment supply, climates and intra-basin salt tectonism. West Africa experienced a complex tectonic history from Cretaceous to Tertiary and several important events have been identified to play important roles in controlling the reservoir distributions. The connection of the Congo system to the Ogooue is the most significant event in drainage organisation and long term sediment supply evolution as observed in modern geomorphology. The shelf review identified numerous channels and erosion features which further supported the shelf sediment bypass to the deep water. This explains why most deepwater reservoirs in West Africa are found within Late Cretaceous to Tertiary strata. The most prolific basin for hydrocarbon exploration in West Africa margin is Lower Congo Basin which contains the Tertiary Congo Fan deposits, followed by Gabon Basin. Kwanza and Namibe Basins have many potential occurrences which yet to be proven by major discoveries or development.
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Dynamic Modelling of a North Sea Saline formation for Carbon Sequestration
More LessCarbon capture and storage has been proposed as a way of stabilising greenhouse gas emissions in order to meet global greenhouse gas emissions targets. A thorough characterisation of potential CO2 storage sites is required prior to CO2 injection. European Directive 2009/31/EC (European Parliament, 2009) states that this should include dynamic modelling of the proposed storage site. This paper describes the results of the dynamic modelling carried out on a deep saline formation in the UK North Sea. The target formation for CO2 sequestration is the Permian Rotliegend sandstone, Central North Sea, approximately 40 km west of the Central Graben and 200 km north east of the Teeside industrial processing region, northeast England. The seal is the overlying Permian Zechstein salt. Seismic data show that the Rotliegend sandstone dips to the north east and pinches out to the southwest, forming a stratigraphic trap on a regional scale. Local dip closures within the Rotliegend sandstone have also been identified as possible locations for carbon dioxide injection, in addition to the stratigraphic closure. The site is not penetrated by wells but the structure is defined by 2D reconnaissance seismic data tied to adjacent exploration wells. Horizons interpreted from the seismic survey have been used to build a 2D dynamic model. The model consists of a layer of Rotliegend sandstone approximately 100 m thick underneath a layer of Zechstein salt which is approximately 600 m thick. Both the Rotliegend and Zechstein layers are considered to be homogeneous due to the absence of resolvable internal seismic structures. The topography of the interface between the sandstone and the salt has been imported from the seismic interpretation of the top Rotliegend surface. The base of the Rotliegend sandstone has been modelled as both a flat and a dipping planar surface. This takes into account different interpretations of the location of the bottom of the Rotliegend which is difficult to distinguish in the seismic data. The model has been populated with rock and fluid properties using data from literature, sonic logs and results from core flood experiments. Modelling has been performed using TOUGH2-MP (Zhang, K. et al., 2008), the parallel version of the TOUGH2 numerical code for modelling multiphase fluid and heat flow in porous media. It has been used in conjunction with the ECO2N equation of state module (Pruess, K., 2005) which models mixtures of H2O-CO2-NaCl designed specifically to represent conditions applicable to CO2 storage in deep saline formations.
Several models have been developed to explore the effect of different parameters on the behaviour of the injected CO2 and the response of the reservoir to CO2 injection. Best and worst case scenarios with respect to rock and fluid properties and reservoir geometry have been assessed. Also different injection scenarios have been considered for instance different well positions, injection rates and number of wells.
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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.
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Habitat and C-14 Age Dating of Lignitic Terrace Sands – Implications for Uplift on the Borneo Coastline During the Holocene
Authors Franz L. Kessler and John JongQuaternary terrace deposits are very common along the Borneo coastline (H.D. Tjia 1983), often in conjunction with mangrove swamp environments, and these have been preserved on land, where terraces saw uplift in respect to the sea-level (Liechti et al., 1960; Hutchison, 2005). The terrace deposits lie above a marked angular unconformity that may have originated as an intra-tidal abrasion surface (Kessler, 2005). The young terrace deposits lacing the Miri coastline from Miri to Bekenu (Figure 1) are formed by lignitic sands (Figure 2), fossil wood, and conglomeratic beds that contain reworked quartz pebbles derived from the older Tukau Fm below. The only fossils, other than wood, are Callianassastyle burrows (Figure 3), and are indicative for an inter-tidal to estuarine environment. Field observations (in the context of stratigraphy, buried wood and compaction) suggested that the sediments might be young, and possibly younger than 50,000 years, which would bring the sediment into the window of C-14 analysis. Accordingly, ten (10) lignitic sand and fossil wood samples in ten coastal profiles were sent for C-14-based age determination; with the results indicate an age range from Late Pleistocene to Early Holocene of 28,570 to 8,170 years. The presence of Quaternary tectonism is particular interesting from the angle of petroleum geology. Significant Quaternary tectonism would have considerable impact on the trapping of hydrocarbons (breach and spill); hence it is an important question to be resolved. Given the terraces
are block-faulted; implication is that the Miri Hill, in its present form, emerged during the Holocene. So-far, with the Holocene tectonics being confirmed for the Miri Hill, the question remains how much the oilfield below Miri City and undrilled prospects further east of the Miri Hill have been affected by these young movements.
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Characterization of Peat-forming Environments of Miocene Coal Using Biofacies in the Malay Basin, Malaysia
Authors Shamsudin Jirin, R. J. Morley, Mahani Mohamed and Sanatul Salwa HasanCoals are common in many Miocene paralic sedimentary successions in the Malay Basin. Four types of peat-forming environment associated with coal precursors can be recognized by using high resolution biofacies analysis, and each has a different significance in terms of depositional environment and sedimentary facies interpretation. They are ‘basinal’, ‘watershed’ or ‘kerapah’, ‘brackish/marine’ and ‘freshwater alluvial’ peats. Basinal peats occur behind mangrove swamps, and form during the period of stable sea level and everwet climate. They begin as topogeneous peats and develop into domed, ombrotrophic peats at a later stage. Currently, they represent the most widespread type of peat in the Southeast Asian region, occurring widely in Sarawak, Brunei, Malay Peninsula, Sumatra and Kalimantan and frequently form thick coals in Malay Basin successions. Watershed or Kerapah peats form on low lying watersheds and other poorly drained areas where mineral influx minimal. They form when the climate is everwet and rainfall exceeds runoff. Unlike basinal peats, they develop independently of sea level change and thus can form at any time during eustatic sea level cycle provided the climate remains everwet. Today such peats occur locally in Sarawak and Central Kalimantan. In the Malay Basin they were probably more common during periods of sea level lowstand and coals thought to be from Kerapah peats may have occurred commonly on low lying interfluves. ‘Brackish/marine’ peats are very rare at present, but were probably common in the Miocene. Today they form in brackish settings which are subject to sediment starvation and limited nutrient availability, such as on carbonate substrates. However, a thick, and widespread coal formed at the end of Malay Basin Seismic Group E (about 9.0 Ma) on clastic sediments, and biofacies analysis suggests that this formed as a peat on exposed low relief area subject to subtle interaction of brackish water, probably at a time when sea levels fell. Freshwater alluvial peats could occur within alluvial plain settings such as abandoned fluvial channel and flood plains. These peats may be considered as ephemeral compared the previous three types, and thus coals derived from freshwater alluvial peats tend to be much thin and limited areal
distribution. The means of differentiating these four coal types, and their significance to depositional interpretation, will be discussed.
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Criteria for Discriminating Drilling-Induced Tensile Fractures from Natural Fractures in Basement Rocks
Authors Adriaan Bal and Pedram ZarianTo date, a number of reservoir evaluation workflows have been developed and commonly used in exploration and production of fractured basement reservoirs. Identification of fractures from available borehole image logs has often been an integral part of such workflows. There have been, however, few critical analyses of methodology efficacy, especially in view of successful discrimination between natural fractures and drilling induced fractures in borehole image logs. In hard-rock reservoirs all hydrocarbon storage is in the open natural fractures, while drilling induced fractures are also open but do not contribute to the producibility of the reservoirs. Moreover, differentiating between different fracture types is of great importance for correct determination of principal stress orientation as well as for correct assessment of a number of fracture attributes used in reservoir modeling (e.g. fracture density, length and spacing). Therefore, poor fracture interpretation can result in severe errors in total reserves estimates. This study, using examples from basement fractured reservoirs of Southeast Asia, illustrates the problems and pitfalls facing the borehole image interpreter in discriminating between drillinginduced tensile fractures and natural open fractures. Particular attention is given to complex situations where drilling induced tensile fractures resemble natural open fractures because of the significantly inclined fracture traces on the borehole image logs. Different discrimination criteria are thoroughly reevaluated and the validity of automated interpretation routines investigated.
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Impact of Spatial Variability in Microfabrics on the thermal Conductivity of Subis Limestone
Authors Y.S. Lee and E. PadmanabhanThere are several facies in the Subis Limestone Formation. These include the skeletal rudstone, coral boundstone, mudstone and algal bindstone facies. The facies assemblage suggests a shallow biohermal depositional environment. Every facies is characterized by differences in fabric. This suggests also variation in the depositional environment. The resultant variation in microfabrics influences the thermal conductivity for each type of microfacies. Presence of corals, burrows, stylolites including differences in mineralogy between each facies appear to decrease the thermal conductivity values to varying extends. The mudstone facies has the highest thermal conductivity values among all other facies tested. The results of this study also suggest an inverse relationship between porosity and thermal conductivity values. This finding has some important bearing on the reservoir potential and stability of carbonates in general.
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Oroclines and Paleomagnetism in Borneo and South-East Asia
More LessOroclinal bending of Borneo is interpreted to result from indentation and collision by the continental promontory of the Miri Zone–Central Luconia Province of northern Sundaland into southern Sundaland. The collision caused strong compression and uplift of the intervening Sibu Zone Upper Cretaceous–Eocene Rajang-Embaluh Group turbidite basin that was floored by oceanic crust of the Proto South China Sea. Timing of the collision is indicated by uplift of turbidite formations to be overlain by Upper Eocene–Lower Oligocene carbonates [Sebuku and Melinau Limestone] and intrusion of tin-mineralised granites into the turbidites at the south-east maximum inflexion of the orocline, a region of complicated juxtaposition of both shallow and deep water formations. The West
Crocker Formation (Late Oligocene to Early Miocene) post-dates the uplift of the turbidite zone, but the Eocene Trusmadi Formation, at the foothills of Mount Kinabalu, was an integral part of the Rajang Group of the Sibu Zone into Sabah. The oroclinal model, requiring clockwise rotation of the north-west limb, is given no support from the paleomagnetic data that instead demonstrate about 50° of Cenozoic anti-clockwise rotation. Unfortunately not a single outcrop of the strongly oroclinally bent Sibu Zone was measured for paleomagnetism in the north-west limb. Limited support was given for the required anti-clockwise rotation in the north-east limb. Previous syntheses emphasised anti-clockwise rotation, or stable nonrotation of the greater Borneo region (Murphy, 1998) as a coherent entity, without any internal deformation (e.g. Hall, 2002). Dick Murphy rejected the Tertiary paleomagnetic data for Borneo because a stable single entity did not agree with the active Tertiary tectonism that characterises the island. The single entity models have ignored the oroclinal shape defined by the areal geology of the island, known since early Dutch publications [the tectonic zones of Van Bemmelen, (1949)]. “Orocline” was not then in the geological dictionary, and we had to wait for Warren Carey (1955) to coin the term and for Marshak (2004) to define orocline characteristics and origins. The northern Thailand–Myanmar north–south-trending geology fabric results from indentation by a promontory of continental India at the Assam-Yunnan oroclinal syntaxis, resulting in paleomagnetically-determined clockwise rotation. The bend of Peninsular Malaysia and Sumatra, from north–south changing to west–east towards Borneo in the south, has remained difficult to model because of widespread remagnetisation. But this is now demonstrated to be part of the Borneo orocline
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Integrated Petrophysical Evaluation of Thin Bed formation: A Case Study from Field Offshore Malaysia
Authors Diego Maya and Nizam Abu BakarAsset managers generally consider reasonable precise and accurate volumetrics to be important before taking decisions about exploring and producing hydrocarbon reservoirs. One of the many uncertainties that affect volumetrics is the true hydrocarbon saturation of thin bedded sand-shale sequences. Uncertainties related to thin bedded sequences may affect reservoirs by up to 50%, and often even more. Modelling net pay in low-resistivity thin bedded pay zones is challenging. In wells drilled near perpendicular to bedding, conventional resistivity instruments measure the resistivity along bedding, the horizontal resistivity. The horizontal resistivity is dominated by the shale conductivity and consequently the true resistivity, ergo sand saturation, is significantly underestimated. In contrast, the measurement of the resistivity perpendicular to bedding, vertical resistivity is more sensitive to the resistive hydrocarbon bearing sand laminae. Horizontal and vertical resistivity has been recorded in this local case study. A robust petrophysical model is constructed and shale and thin-bed sand volume, and true resistivity, was calculated. When integrated with the conventional Thomas Steiber porosity model, a more accurate computation is obtained. Zones with low resistivity anisotropy may point to disturbed low productivity zones. The borehole resistivity image tool allows the identification and quantification of thin laminations; this information is integrated with petrophysical results in order to have a consistent earth model. This paper discusses the integration of multi-component induction and borehole resistivity images into one enhanced and consistent earth model which allows accurate saturation modelling of thin bedded sand-shale sequences in a local Southeast Asia example. Conventional LWD resistivity showed low resistivity zones, potential misinterpreted as water bearing. The vertical resistivity computed by the multi-component induction tool clearly identified high resistivity intervals interpreted as hydrocarbon bearing zones. The petrophysical model quantified thin bed sand volume and true hydrocarbon saturation. The image data acquired in this well confirmed the laminated model and contributes to net-to-gross calculations. The results show net increase in pay of XX% (with no cut-offs) and XX% when conventional cut-offs are applied.
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Typical Pore Pressure Regimes in the Malay Basin – Insight for Other Basins Globally
Authors Richard Swarbrick, Stephen O’Connor, Rick Lahann, Jamaal Hoesni, Bitrus Pindar, Sam Green and Steve JenkinsThe Malay Basin is a Tertiary trans-tensional rift basin located in offshore Peninsular Malaysia and is one of the most prolific hydrocarbon-producing basins in Southeast Asia. Over 12 km of fine-grained Tertiary sediments were deposited during the last 35 Ma, leading to development of overpressure in the deeper parts of basin (Hoesni et al., 2003). On the Basin Flank (Resak-Beranang – Regime A), reservoir sediments are normally pressured to depths in excess of 3.0km, on account of a high sand/shale ratio. Beneath Regime A sediments, a strong pressure transition zone is expected (e.g. Beranang-1; Mohamad et al., 2006), with attendant challenges for pre-drill prediction and safe well planning. Shale-prone sediments, both shallow (e.g. on continental slopes) and deep (e.g beneath Regime A) which have been isolated from fluid escape by low-permeability shales correspond to Regime B, which is characterised by having high overpressures. Pressure prediction in Regime B characterised by Well LA-3, works satisfactorily if reservoirs are limited in their vertical relief and/or there are no open faults connecting stacked or cross fault reservoirs.
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Appraisal While Development Campaign in the “J” Field, North Malay Basin
Authors Lai Kian Voon, M. Yusof Abdullah, I. Kanok, Fazili Ilias, I. Bukhari, S. Nantawut, C. Puvanat and Liau Min HoeThe conventional approach to develop a field is from Exploration to Appraisal and finally Development Phase. This paper describes a case study for an unconventional approach in the Malaysia – Thailand JDA area where the appraisal program was carried out while the development campaign is ongoing. Once production has commenced, drilling from the well head platform will be ifficult as some production wells needed to be shut-in for safety reason during the drilling operations. This appraisal-while-development approach was carried out in the “J” Field to appraise the hydrocarbon potential of the “J” East fault block. Various strategies and technical justifications had been carried out to convince the management to approve this approach. The appraisal well was
eventually drilled, which discovered 86m of net gas sand and encountered two new depositional sequences based on the seismic re-interpretation. Appraisal-while-development concept allowed CPOC to appraise the upside potential and convert the well to development well, leading to cost optimization and immediate contribution to the total field production.
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Assessing Fault Seal Risk and Fault Seal Retention Capacity in Stacked Clastic Reservoirs
More LessThe prospectivity of structural or combination traps in stacked clastic reservoir settings typical of many of the known hydrocarbon provinces in Southeast Asia such as Baram Delta and Balingian province, often critically hinges on the presence of a working fault side seal. A thorough understanding of the key controls on fault seal risk and retention capacity and from there, a consistent methodology to access these factors across a prospect portfolio, are essential to achieve a balanced prospect ranking and an accurate assessment of prospect success volumes. Faults in a clastic reservoir typically seal through either one of a combination of the following mechanisms: juxtaposition of reservoir against non-reservoir, the development of impermeable gauge within the fault zone either because of clay smear, mixing of sand and shale in the fault gauge, or through grain size reduction within the fault zone (cataclasis). Fault seals can be breached if pressure buildup exceeds retention capacity or in cases of fault movement post hydrocarbon emplacement. The objective of this paper is demonstrate how stochastic simulation of juxtaposition relationships along faults in combination with reference to literature published data on retention capacity of shaly fault gauges (e.g., Yielding et al., 1997; Yielding, 2002; Freeman et al., 2008) can be used to generate quantitative insights in the relationship between measurable reservoir properties such as net-to-gross ratio and typical thickness of reservoir sands and intervening shales, and the chances of fault seal success as well as the likely retainable hydrocarbon column in a success outcome. Quantitative estimates of the chances of success and the expected range of retention potential can be done for a single reservoir-seal pair, but they can easily be expanded to predictions for a series of stacked reservoirs using binomial distribution theorem. The paper will show how a simple but elegant toolkit incorporating these relationships can be used (Figure 1) to successfully replicate the hydrocarbon distribution of known discoveries (Figure2, Figure 3) e.g., in Balingian province. A tool like this can be used to assess the fault seal success Chance Factors, i.e., the chances of fault seals being able to retain a hydrocarbon fill equal or exceeding the P90 area, in a consistent manner across a prospect portfolio. Whilst the methodology and toolkit described here considers the complete “outcome tree” of success and failure cases, it can also be shown that under certain specific circumstances many of the outcomes have extremely low probability of occurrence. For example, the retention capacity of shaly fault gauge should always be in the range of some 50psi or more even if the net-to-gross ratio is relatively high, which means that failure on Shale Gauge seal is unlikely unless there are significant pressure ramps or the fault re-activates post-hydrocarbon emplacement. By removing the low probability outcomes for specific cases under consideration, we can simplify the “outcome tree” to a et of simple rules that can guide an operator to identify leads prospects with a high chance of fault seal success.
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Labuan Outcrop Revisited: New Findings on Belait formation Facies Evolution
The sedimentary successions of the Belait formation exposed across the northern side of the Labuan Island has been studied by various workers such as Hazebroek, 1993; Levell, 1983, 1987; Tate, 1994. Based on his work, Mazlan Madon (1994, 1997) concluded that the basal Belait Formation was deposited in fluvial system developed over an eroded Temburong landscape in an overall transgressive regime. Facies development in the basal Belait reflects a quick change transition from fluvial systems (braided to meandering) to shallow marine successions represented by coarsening-upward offshore shales to shoreface sandstones. The presence of two (2) new outcrops provide the opportunity to further study the lateral continuity and vertical facies succession within the Belait Formation. A total of nine (9) outcrop sites including two (2) new locations were studied and logged and 142 samples were taken and analysed for biostratigraphic information. Results showed that the fluvial succession within the Belait Formation is not presence above the Temburong Formation at the new outcrop and replaced by coastal plain, fresh/brackish water estuarine successions. The fluvial succession thickened away from the new outcrop in the direction of Layang-layangan in the west and Tg. Kubong to the east. Furthermore, the fluvial succession in Tg. Kubong is also thinner than previously reported (Mazlan, 1994). Rapid change form fluvial to estuarine environment was observed based on biostratigraphic data. Interms of vertical facies development, we proposed that there are two (2) incised valleys developed where the fluvial succession was deposited and rapidly overlain by brackish water fluvial-estuarine deposits. The new outcrop area is interpreted as an interfluve and appears to be where the center of the anticline is located. The relatively thin fluvial to shallow marine transition above the sequence boundary, implying rapid deepening due to the steepening depositional surface, coupled with rising sea level and uplifting in the new outcrop area. This finding will help us in understanding the relationship between sea level, tectonic activity and vertical/laterar\l facies development.
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Fabric Anomaly in Mud Clast Distribution in the Lambir Formation (Mid to Late Miocene), Sarawak.
Authors E. Padmanabhan and A.S. Mohd PauziThere is an increasing interest in the anisotropy of mudstone systems mainly due to seismic anisotropy caused by change in wave velocity and polarization with propagation direction. Therefore, the study was to evaluate the variability in the mud clast distribution in the heterolithic sequences present in the Lambir Formation. Mud clasts show differences in size, shape, thickness, continuity and orientation with respect to the general bedding attitude. The clasts are generally ellipsoidal in shape despite some of them being subrounded. It is evident that the amount of energy needed to transport the larger mud clasts was more than that needed to transport the finer sand grains. The origin of mud clasts remains debatable as the energy setting in which it occurs is generally not in favor of the stability of this feature. Results suggest that size variation of mud clasts with increasing distance from the base could be quite erratic in some places despite a general trend of fining upwards. We introduce the term “fabric anomaly” to describe this feature. The Lambir Formation has tremendous variability at various scales of observation. The fabric anomaly exhibited by mud clasts has the potential to impact critical properties of the clastics.
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An Overview of the Proven Pre-Tertiary Karstified and Fractured Carbonate Basement Play-Type in the Offshore Northern Vietnam
Over the past 6 years, PETRONAS Carigali Overseas Sdn Bhd (PETRONAS), through its exploration arm in Vietnam, has explored for the hydrocarbon potential of the Pre-Tertiary karstified and fractured carbonate Basement play-type in offshore northern Vietnam (Figure 1). The first encounter of this play type in the subsurface offshore northern Vietnam was in 2004 when severe mud losses were experienced when the A-1X exploration well penetrated ‘caves’ in the carbonate Basement. Since then, effort was intensified and further technical analysis was carried out until PETRONAS successfully made a commercial discovery in the “D” structure through the D-2X exploration/appraisal well drilled earlier this year. This milestone discovery has proven the prospectivity of the Pre-Tertiary karstified and fractured carbonate Basement play-type, the first of its kind in the offshore northern Vietnam. The reservoir penetrated consists of limestone and dolomitic limestone, which can be closely analogue to the similar carbonate formation exposed as ‘islands’ at Ha Long Bay (Figure 2), located some 100km to the North-Northeast from the discovery. This Carboniferous-Middle Permian dolomitic limestone, interbedded with oolitic limestone and calcaro-cherty shale is referred to as the
Bac Son Formation (C-P2), which is about 1000m thick, monoclinal and undulatedly folded, containing foraminifera beds from Chernyshinella, Dainella, etc. to Cancellina, Neoschwagerina, Werbeekina beds gathered with remains of crinoids, brachiopods, bivalves, bryozoa, etc. and corals, conodonts, radiolarians etc. (Tran Van Tri, et al., 2003). Apart from the cavern system evidence from the outcrop in Ha Long Bay (Figure 3), the carbonate karst-hill and tower karst structures are also fractured, similar to the results from the wells drilled into the Pre-Tertiary carbonate. These faults and fracture sets are believed to have contributed to the increased secondary porosities and permeabilities by acting as the reservoir conduits that connect to the cavern system and matrix (Nelson, 2001). According to Jamin, et al, 2009, successful hydrocarbon exploration in such play-type offshore northern Vietnam is attributed to a working petroleum system defined by the interplay of the following factors: i) presence of porosities and voids in the carbonate reservoir; ii) increased permeability due to the presence of faults and fractures; iii) presence of a thick and mature lacustrine shaly section which acts both as a source rock and top and lateral seal; and iv) structural formation (Pre-Tertiary) predating oil expulsion and migration. Oil expulsion and migration from this lacustrine source rock began during early-mid Miocene. The biggest uncertainties and challenges arise from the poor to marginal quality of the current seismic data at the reservoir level which puts a limitation on accurate fractures/lineament and cavern mapping and prediction and also on mapping the base of the carbonate. A much better data quality and more advanced techniques might help to reduce these associated uncertainties.
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Mapping Regional Sedimentary Horizons in the Onshore Baram Delta, Sarawak, from Magnetic and Graviti Data Using Energy Spectral Analysis
Aeromagnetic and airborne gravity data acquired over the onshore Baram Delta, Sarawak, Malaysia, was used to estimate depth to economic basement that is the Top Cretaceous (Horizon-1), and depth to three intra-sedimentary horizons: Top and Base of Carbonates (Horizon-2 and Horizon- 3), and the top of an additional shallower interface (Horizon-4). Depths to these horizons were calculated through the analysis of energy spectra of the observed magnetic and gravity fields, while faults and magnetic lineaments were derived through the application of an automatic curve matching (ACM) method based on the Naudy technique. The project involved the application of a new spectral technique, termed the Multi-Window- Test (MWT). The application of the MWT allowed quick estimation of depth to multiple horizons (skeleton maps) and also provided a set of optimal window sizes used for detailed mapping. The potential field derived results correlate well with both seismic and well data. Spectral methods have been successfully applied in the study area, and the MWT has proved itself a valuable tool in producing a robust interpretation of potential field data.
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Efficiency of TDEM and EM-IP Methods Application for Reservoirs Exploration in South East Asia
Application of electromagnetic methods for oil and gas exploration is developing world-wide. Two main types of EM methods are applied: natural source (MT) and methods with artificial source of EM field (TDEM, FDEM) [2]. For hydrocarbon exploration on land high efficiency has transient electromagnetic method in frequency or time domain mode. The role of EM methods is increasing at the areas with poor seismic data quality, non-structural fields and zones with complicated structure of sedimentary cover. Joint interpretation of EM data with seismic or other geological data is a way to reduce the risks and optimize the process of geophysical investigation. For oil and gas exploration it is possible to study sedimentary layers resistivity at the depth interval from surface to basement and also a lot of information can be received from induced polarization (IP) parameters. The paper is devoted to technique of EM methods combination – TEM and EM-IP for oil and gas exploration, and possible ways of its effective application. Forward modeling results for geoelectric models are shown.
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Rotation of Borneo Revisited – New Inferences from Gravity Data and Plate Reconstructions
Authors Stan Mazur, Christopher Green, Matthew Stewart, Rkia Bouatmani and Paul MarkwickBorneo has commonly been considered to have undergone two stages of major anti-clockwise rigid-block plate rotation - 50° between 80 and 30 Ma and 40° between 30 and 10 Ma (e.g. Fuller et al., (1999) and Hall (2002), based on interpretations of palaeomagnetic data from Kalimantan and Sarawak). These interpretations have recently been challenged (Cullen, 2010). Considerations based on gravity data and plate modelling add further concerns. Cullen (2010) pointed out that the earlier authors had rejected those palaeomagnetic data that did not match their model, using the argument of young re-magnetisation. If those data are taken into account, the 30-10 Ma anti-clockwise rotation must have been restricted to smaller tectonic blocks, with no rigid-plate rotation of Borneo as a whole. It should also be noted that the palaeomagnetic data from Borneo provide similar results to those for the Malay Peninsula, Sulawesi, the Celebes Sea and parts of the Philippines; this suggests that any rotation should be applied to a block much larger in extent than just Borneo (Fuller et al., 1999).
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Determination of Avo Attributes for Hydrocarbon Resources Region of Malay Basin: the Fluid Factors
Authors T.L. Goh., Uzir Alimat, Shaidin Arshad and M. Izzuljad Ahmad FuadFluid factor is one of the most important AVO attributes in seismic for reservoir hydrocarbon prediction. The typical published fluid factor, F =1.252A+0.580B was derived based on Castagna’s mudrock equation (Castagna et al. 1985), Vp=1.16Vs+1360 and Gardner’s relation (Gardner el al.1974), =0.23Vp0.25 and was developed based on brine saturated siliciclastics data obtained from Gulf of Mexico. These are true as hydrocarbon indicator for reservoirs of Gulf of Mexico. Since the geological settings for Malay basin are different with Gulf of Mexico, therefore the determination of fluid factor for Malay Basin is very crucial. The respective values of A and B were the intercept and the gradient attribute of reflection amplitude versus sin2 plot. Castagna and Smith (1994) reported that the respective value of fluid factors for background (nonpay) and shale/gas-sand interfaces are zero and negative. In this paper, the fluid factor equations based on local mud rock equations as outlined in Table 1 (Vp versus Vs and density versus Vp plot), which were obtained from brine saturated siliciclastics data of 48 wells, were established for respective six petroleum resources regions, Malay Basin. The six petroleum resources regions as illustrated in Figure 1 were divided based on geographical locations and play types, namely region 1 - North Malay Region; region 2 - West Malay Region; region 3 - South Malay Region; region 4 - Southeast Malay Region; region 5 - Northeast Malay Region and region 6 - Central Malay Region. The rock physical trend lines for region 1, 2, 3, 4, 5 and 6 were established based on 7, 3, 7, 5, 14 and 12 wells data respectively. The respective fluid factor equations for six petroleum resources region 1, 2, 3, 4, 5 and 6 were F=1.235A+0.568B, F=1.219A+0.563B, F=1.238A+0.586B, F=1.222A+0.608B, F=1.228A+0.573B and F=1.263A+0.536B.
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Soft Shale Complication in Avo Interpretation in Sabah Basin
Authors Alex Tarang and Yeshpal SinghField A is a faulted EW trending anticline which has been produced for more than two decades from early Miocene sand. It is very important to understand the rock elastic properties for the purpose of near field wildcat exploration. In Field A, the shale which capped sands is called ‘A’ shale and roughly 70-100m thick across the field. The upper part of the ‘A’ shale has Acoustic Impedance(AI) higher than that of the shale, however, the lower portion of the shale is the opposite. Therefore, such a response imposed a challenge to differentiate the sand and shale responses on seismic data set. Detailed rock physics modeling on petrophysically conditioned logs is a must in order to quantify the elastic properties of the shales with reference to underlying sand reservoir. Figure 1 shows the representative well log response and histograms for shales and sand. Our analysis revealed that soft shale seismic amplitude response is similar to that of the gas sand. The proper AVO/rock physics modeling of the soft and hard shale and the various fluid fill sands responses are necessary in order for us to do correct AVO analysis and thus to be used correctly in the prospect de-risking process. It has been observed that elastic properties like Elastic Impedances, LambdaRho-MuRho are necessary in order to distinguish among them. In addition, proper conditioning of the pre-stack gather is also necessary in order to improve the data quality and enhance the subtle contrast.
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An Integrated Approach to Reservoir Appraisal and Monitoring Using Well Log, Seismic and CSEM Data.
Authors Lucy MacGregor, James Tomlinson and Skander HiliThe controlled source EM method has developed into a tool that is often used in de-risking the exploration process. In this paper we demonstrate how the intrinsic sensitivity of the CSEM method to hydrocarbon saturation can be utilised within a framework of well and seismic data in prospect appraisal and reservoir monitoring applications. This will be illustrated with examples of the H71 rock physics linking elastic and electrical properties along with recent case studies. CSEM methods use a high powered marine source to generate an electro-magnetic field within the earth.. The detected response of the earth to this electro-magnetic field is recorded by an array of receivers located on the sea-floor. By interpreting the recorded response using forward modelling and inversion approaches, the resistivity structure of the subsurface can be determined. In many situations electrical resistivity is driven by the properties and distribution of fluids in the earth. Resistivity measurements in well logs often show that commercial hydrocarbon deposits may be many times more resistive than surrounding lithologies. In principal, such variations should be readily detected using CSEM receivers. In contrast, seismic data are sensitive to boundaries between lithologic units but are less sensitive to fluid changes within these units. Given high quality seismic data, well logs, sophisticated seismic inversion and rock physics tools, we have the potential to relate changes in seismic rock properties to saturation effects. Nevertheless, the change in resistivity caused by variations in saturation should be much easier to detect. However, despite the increased sensitivity of resistivity data over seismic data for the determination of saturation, there are two inherent challenges to interpreting CSEM data. Firstly, the structural resolution of CSEM data is poor. Secondly, the cause of resistivity variations “anomalies” (particularly high resistivity features) cannot be uniquely linked to the presence of hydrocarbons in the subsurface when taken in isolation. In many situations these are equally likely to be caused by other highly resistivite material (for example, tight carbonates, salt bodies or volcanics). Both of these limitations must be addressed when considering the applicability of CSEM to answer a specific geophysical question, and as far as possible mitigated by the interpretation approach adopted. CSEM data can, of course, be interpreted in isolation, and if there were no seismic data or wells in the vicinity of the CSEM dataset (for example if a survey were performed in a frontier area), then this would be necessary. However, with no constraints on this interpretation, the result will suffer from the non-uniqueness and ambiguity which blight unconstrained interpretation approaches. Although resistivity is imaged, the poor structural resolution of the method means that such images are diffuse and difficult to interpret. The uncertainty in the depth of features is large, so that they cannot be unambiguously attributed to a particular stratum. If there are multiple resistive features, these cannot be easily separated, and small resistive bodies are likely to be lost or smoothed into surrounding strata during the inversion process. Even assuming that localized resistivity anomalies can be found, the cause of these anomalies cannot be unambiguously linked to the presence of hydrocarbon. In the presence of seismic and well information, the question that we are trying to answer with the CSEM data becomes significantly better posed. The question is no longer one addressed at finding a reservoir, but rather one of determining the content of a defined structure. Using seismic information the reservoir structure is known (but potentially not its content or extent), and we have independent constraints on the surrounding strata within which it is embedded. This is therefore a well constrained interpretation problem and one that the CSEM data are in a much better position to answer. It is clear that a careful combination of all three data types can supply information that is not available, or is unreliable, from any one data type alone. By integrating complementary sources of information and exploiting the strengths of each, estimates of rock and fluid properties such as gas saturation and porosity can be obtained with greater confidence than from any one data type alone. As we step from an exploration setting though to appraisal and monitoring of a reservoir the level of constraint on the geological model increases, and therefore so does our confidence in the CSEM interpretation. This increased confidence in the result transforms CSEM into a tool that can quantitatively map hydrocarbon distribution and time lapse changes in hydrocarbon saturation away from the well bore.
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Pore Pressure Prediction of a Field in Southwestern Part of the Malay Basin: A Basin Modeling Approach
Authors Ismatul Hani Shada Binti Idris, Peter Abolins and M. Jamaal HoesniPore pressure prediction has become crucial in various stages of frontier exploration, development, exploitation and drilling. Various methods are commonly used in predicting formation pore pressure, for example by using seismic velocity, wireline log-based pore pressure prediction, and geomechanics study. Basin modeling is an emerging approach in predicting pore pressure. Thus the development of a pore pressure prediction workflow using basin modeling provides an alternative approach. This project demonstrates a case study on the application of basin modeling for pore pressure prediction in the southwestern part of the Malay Basin. This study involves 1D, 2D and 3D basin modeling to evaluate the pressure distribution and behaviour. This study also considers the role of faults in controlling pressure distribution. Therefore, several faults have been incorporated into the 3D model. Lithology variations also occur, perhaps controlling the various pressure profiles. It is believed that both faults and facies control the pressure distribution. The pressure evaluation in this project was carried out mainly from 2D simulation. Porosity and permeability calibration was carried out to match the measured pressure data to the model. The final results of 2D simulation show a good
calibration between the measured data and the model.
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Seismic Facies Analysis of Group L and M Reservoirs, Southeast of Malay Basin
Authors Noor Iryani Jumari, Hamdan Mohamad and Nasaruddin AhmadSince PETRONAS Carigali Sdn Bhd (PCSB) has taken over Block XYZ in 2003, 3010 sq km of 3D seismic data were acquired and merged with existing 3D data acquired earlier over the producing fields. Currently, almost 80% of the block XYZ acreage is covered by 3D seismic data. The new data provides an outstanding opportunity to integrate the geology interpreted separately over the producing fields. From the available data on these groups, Group L and M has been identified as a potential new play and enhancing the stratigraphic trap in the south of Malay basin. PCSB has drilled eight wells deep down into the lower Group M, M110 and discovered oil and gas. The new oil and gas discovery in the southeast area of Block XYZ has proved that valid petroleum system is present in the deeper groups. Group L & M reservoirs have been identified as potential hydrocarbon play in Block XYZ. Seismic facies interpretation is very useful to investigate this concept. Group L and M are deposited in the earlier stage of the basin formation (synrift), which is in fluvial lacustrine environment (EPIC report, 1994). A seismic facies project have been conducted with the aim to describe the seismic facies in the study area and to interpret the depositional setting of these deeper groups in Block XYZ by integrating seismic facies characteristics on 3D seismic data, well log and core data from key wells. It also aims to provide an improved understanding of the local and basin scale distribution of potential reservoir sands in the southeastern part of the Malay basin.
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The Karap Mud Volcano Imaged on New 2D Seismic – Implications for Basin Analysis
Authors Franz L. Kessler, John Jong, Tran Quoc Tan and Hajime KusakaMud volcanoes can be seen in sedimentary basins, where clay and sand are accumulating within a “geological” short period of time. Several of them were mapped in the NW Borneo Basin, both Sarawak and Sabah (Liechti et al, 1960). In young clastic basins, following rapid burial, clay is liquefied. It moves upwards, intrudes sediment layers, and at times, reaches the surface. The plastic clay extrusions produce volcano-shaped cones than can reach a height of 20 m above area level in Sarawak (Kessler, 2008). The Karap mud volcano (Figure 1) is currently the largest active mud volcano in Northern Sarawak, and located in a hinge area of the “Baram Line”. This complex lineament system separates the “Baram Delta”, an area of poorly consolidated Mid-Miocene-to-
Recent clastic deposits (Kessler 2010), from the more consolidated “Central Luconia” (Figure 2). Mud volcanoes are complex features. Recent 2D seismic data acquired by JX NOEX, give for the first time insight into the structure of the volcano (Figures 3). The volcano's caldera is asymmetrical, and has formed as a collapse graben array on the tip of a major regional strike-slip fault zone (Figure 4). In the proposed model, the mud-volcanic activity stems from an interaction of surface waters with underlying overpressurized rock. In the funnel-shaped caldera, large quantities of meteoric water are collected, leading to a rise of hydrostatic pressure to a level in the order of 1200 psi. With increasing pressure, water penetrates deeper semi-permeable levels, and interacts with semimobile overpressurized pore-space gas. As the water mud rises, and de-gasses on the way up, gas bubbles are forming that later detonate on the volcano's surface. Arguably, the presence of mud volcanoes points towards compressive tectonism in the sub-surface, strike-slip combined with reverse faulting in the Karap case. Since mud volcanoes depend on overpressured rock, they point towards basin areas that are under-compacted. However, a direct link to charge and gas-bearing reservoir can currently not be made. Mud volcanoes also constitute an area of increased drilling risk.
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Low Relief Structure, A Favorable HC Accumulation Trap in Malay Basin
Authors Ji Ping and Norhafizah MohdMalay Basin had undergone three major vertical structure movements: extension, thermal subsidence and basin inversion. The important result of the inversion is the compressional anticline, include the low relief structure. Exploration activities in recent years demonstrate that low relief structure is a favorable HC accumulation trap. The discovered low relief structure HC accumulations have the following characters: 4 way dip structures (associated with deep seated faults) Low HC column (50 to 100 m) Large area (up to 60 km2), and HC filled near to spill point Very thick total net pay (over 200 meters) Multi layers with different contact systems. Low CO2 content comparing to high relief trap. Coastal plain and deltaic environment deposits match with the low relief structures make them excellent hydrocarbon accumulation traps in Malay Basin. The possible low relief traps lies between high relief structures or beneath the major gas fields which may be overlooked because they are not obvious in time domain or affected by gas sagging. Hence the comprehensive seismic analysis is needed, especially the 3D seismic velocity model.
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Conventional Approach Seems to Be the Best!
Authors Hijreen Ismail, M. Izham Kassim and Khairul Hamidi KhalidLateral and vertical velocity variations are among the key concerns for time to depth conversion especially in carbonate regime. A reliable velocity model should take account of these issues. The K prospect area is well known of its geophysical and geological complexity. The targeted and proven reservoirs are believed to be a type of platform carbonate. Furthermore, the existence of channel filled by shale throughout the whole K block, in the shallower horizon, i.e. at W level had caused pull down effects until the basement level. The poor seismic data quality and the unavailability of stacking velocities have developed more challenges to the study. There were three methods had been identified in order to produce a reliable velocity model meant for time to depth conversion purposes. The three methods are; average velocity model, 3D velocity model and conventional layer cake model. The first model is an application of well average velocity with main focus on the targeted reservoirs. The 3D velocity model had used a 3D grid as a platform to incorporate all TWT surfaces, well and DMO velocities. A statistical concept of modeling had been applied to populate the well (primary trend) and DMO velocities (secondary trend) in a single 3D model. Then, an anisotropy function
({well velocity / DMO velocities} X DMO velocities) had been generated as to integrate the anisotropy factor into this model.The third model is a conventional method which was generated based on observed velocity changes in sonic data vertically. Whilst, the TWT surfaces had been used as to control for lateral variations. Later, both well velocities and TWT surfaces had been incorporated with utilizing the Vo- K method as the basis of generating this model. Based on the statistical report of residual errors, the third model turns up to provide the least amount of erroneous.
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Regional Rock Physics Application for Improved Understanding of Thief Sands in Offshore Sarawak Basin
More LessSeismic data play a crucial role for hydrocarbon exploration. The seal integrity analysis is required for carbonate prospects ranking in Sarawak basin. The overlying capping shale has intercalated sands, which are termed as thief sands. The fluid content of these sands indicates seal breaching. Therefore, fluid characterization of thief sands may help to characterize reservoir seal and in-turn for prospect ranking. . These sands are quite shallow with depth range from 800-1500m. The recorded well logs are quite scarce and never analysed petrophysically in past. Reliable density and sonic( P&S) well logs along with relative amplitude preserved pre-stack data is very crucial to understand the seismic character of thief sands. The shale abundant columns at shallow depth drilled with overbalanced mud weight, induced large washouts and affected recorded well log curves. The density correction for washout zones is a must otherwise misinterpretation of seismic reflectivity may give an AVO pitfall. In general, conventional petrophysical analysis targeted for reservoir interval. However, to characterize shallower shale sections, a re-look on well logs conditioning is necessary before any further analysis. More than 25 wells widely distributed in Sarawak basin were selected for regional understanding of capping shale characteristics in terms of rock physics analysis. Input logs were quality checked for consistency and necessary corrections applied before putting them as input for rock physics modelling. Suitable rock physics model constructed to synthesized missing logs and poor quality logged interval. Gassmann fluid substitution modelling applied to understand the fluid effect on rock properties. Rock physical analysis for elastic and density logs indicates that brine and
hydrocarbon bearing sands are harder than shales in the Sarawak basin. The well log based forward modelling indicates that the sands always have high P-impedance than shales. The forward modelling results conform to the seismic amplitude variation in sands and shales. The seismic responses of sand tops are represented with positive reflectivity contrast and with dimming amplitudes of angle/offsets. The rock physics modelling and seismic well calibration helped us to delineate thief sands using pre-stack seismic analysis. The workflow and seismic analysis results will be presented in the paper.
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Delineation Stratigraphic Features Using Spectral Decomposition and AVO in B Field, Malay Basin
Authors Khairool Anwar Laksaman, Nguyen Huu Nghi and Goh Sing ThuIn the search for new hydrocarbon resources to optimize field development plan, delineation of stratigraphic features is becoming an important objective in the oil and gas industry. In the Malay Basin, most of the stratigraphic features are the channel systems which are filled up with either shales or sandstones (Mazlan B.M. et al., 1999). The sand-filled channels are potential targets of hydrocarbon accumulations, while the shale-filled channels can act as trap seal or barriers to fluid flow among reservoirs during field development. Their impacts on exploration and development have been observed from several fields in both northern and southern parts of the basin. Therefore the degree of accuracy in mapping the channel system is crucial to a proper evaluation of the reservoirs, which in turn will help improve the reserves base during the various stages of the field development. In this case study, a suitable methodology and workflow have been applied to address the above challenges for B field development.
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Integrated Approach to Identify Stratigraphic Prospect from Sparse 2D Seismic Attributes (AVO), Well Correlation and Geological Model – A Success Case from Genale B-2X in Blocks 3&4, Ogaden Basin, Ethiopia
Authors Eadie Noor Fadzly, Dodik Suprapto and Amri Shahril SaadudinGenale B-2X is a vertical wildcat exploration well drilled in Blocks 3 & 4 (Genale), Ogaden Basin onshore Ethiopia, 590m above sea level. The well is located approximately 800 km to the southwest of capital Addis Ababa, 15 km northwest of Genale-1 and 40 km southeast of El Kuran-1. It was drilled to evaluate the hydrocarbon potential in the Gumburo and Calub reservoirs. Geometrically, Ogaden Basin is divided into two sub-basins namely Western sub-basin which was relatively sagged during post Triassic period and Eastern sub-basin which was tectonically active throughout Permian to Tertiary period (as shown in the Figure 1). Prior to drilling, prospect Genale B was identified by bright seismic anomalies, extraction of seismic impedance and AVO seismic attributes from sparse 2D seismic data shot by PETRONAS Carigali Overseas Sdn Bhd (PCOSB) in 2006. The prospect is situated at the western flank of Ogaden Basin that experienced minimal structuration due to its close proximity to Negele Basement which shielded the blocks from intensely being further rifted. The well was successfully penetrated the Gumburo and Calub reservoirs respectively. Based on the petrophysical evaluation, three gas bearing reservoirs are identified in the Gumburo formation namely Upper Gumburo, Lower Gumburo and Middle Gumburo (Figure 2). High gas reading during drilling was observed in these reservoirs.
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Sequence Stratigraphic Study Paves the Way to the Discovery of Kinabalu A-1 Well
Kinabalu field is located in Sub-Block 6S-23 offshore Sabah, about 61 km to the northeast of Labuan (Figure-1). The field is subdivided into Kinabalu East (East Fault Block), Kinabalu Deep and Kinabalu Ultra Deep (West Fault Block). The Kinabalu field was discovered in 1990 and started production in 1993 (Kinabalu Field Development Plan, 2008). In late 2008 a regional sequence stratigraphic study of Kinabalu and surrounding areas was carried out to establish correlation of Kinabalu field within the Sabah regional Stratigraphic Framework with emphasis on understanding the stratigraphic location of the reservoir sections. In addition, the study was also aimed to identify upside potential for hydrocarbon exploration for the area. This is the first kind of this study since discovered in 1990 (Othman et al., 2008). Kinabalu A prospect is located on the upthrown side of Kinabalu East fault (Figure 2). The presence of Kinabalu A prospect was previously reported by the previous operator, but there was no further investigation made to evaluate the potentiality of this prospect (SHELL unpublished report, 2000). The present sequence stratigraphic study has managed to identify and verified the presence of Kinabalu A prospect in the Stage IV C at the 10A reservoir level and deeper section. In the area, where a petroleum system is proven by many discoveries, this potential subtle trap offered an attractive target. Further investigation with detailed structural mapping, resource assessment and seismic attributes studies indicated positive results on the presence of commercial hydrocarbon at Kinabalu A accumulations. As a follow up to the above studies and findings, Kinabalu A-1 well (KNA-1) was spud on 15 December 2009. The well was drilled to a total depth (TD) of 15, 423 ft MD/10, 023 ft TVD. The well has successfully penetrated hydrocarbon at 10A and 11A reservoir levels and declared as discovery. The KNA-1 well has been suspended for future development. This paper will discuss the workflow used for regional sequence stratigraphic study, which includes the integration of seismic stratigraphy, well log analysis, seismic attributes studies, core analysis and 2D geological modeling leading to the successful discovery of Kinabalu A-1 well.
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Azimuthal Anisotropic NMO Analysis for Amplitude Stripping Removal in Sumandak 3D Reprocessing
Authors Mazlan Ghazali, Edgardo Padron and Mehmet FerruhExploration and Production seismic interpretation relies on accurate seismic processing to make a good well proposal. The removal of amplitude stripping and large vertical discontinuities artifacts, observed in the previous processing (Figure 1), in the crossline direction at the Morris fault down thrown in Sumandak 3D Block, was one of the main objectives of the current PSTM/PSDM reprocessing project. In this paper, we present a reprocessing case study that applied the Azimuthal anisotropic concept to get a practical solution to this task. In seismic, Azimuthal anisotropic is referred to the apparent velocity dependence upon the azimuth of the shot and receiver geometry (Figure 3). The study area is in Samarang/Sumandak development block; in a zone with a oderate complex tectonic led by a remarkable normal fault which split two different geological environments. We will show, how using Azimuthal anisotropic NMO analysis helped to determine the appropriate parameters to correct the velocity field affected by azimuthal velocity anomaly.
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Multiple, Diffractions and Diffracted Multiples in the South China Sea: How Dense Does Our Acquisition Geometry Need to Be?
Authors Rosemary K. Quinn and Lynn B. ComeauxMultiples, diffractions and their multiples are a common feature of marine seismic data. In some areas of the South China Sea, the residual multiples are a significant problem as they are coincident with the reservoir section. In this instance, we need to devote significant resources to further attenuate the multiples, particularly the diffracted multiples. The challenge is to assess how much effort is sufficient and is that effort required during data acquisition, data processing, or both?
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An Integrated Geoscience and Engineering Efforts Leading to Increased Development Planning Confidence
Successful field development planning requires effective mitigation of geological uncertainties through integration of available G&G data and this has been the case for Jambu Liang faulted anticline (figure 1) which is currently operated by Petrofac Malaysia. Jambu Liang faulted anticline initiated by Cendor development in 2006 has been very prolific despite initially thought to be marginal. Following the success of Cendor, in 2008/2009 Petrofac resume the appraisal of fault blocks to the west and this appraisal campaign has lead to a potential new development of the West D fault block. For an effective development of the fault block, understanding reservoir characters and distribution especially in the prolific Group H reservoir which is geologically complex, is crucial.
Amongst the challenges inherent in the block is how to effectively delineate reservoir quality and sand continuity especially at poor seismic quality areas where most seismic response has been attenuated by presence of shallow gas (figure 2).
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Deghost + Denoise + Demultiple + Velocity & Q inversion + Depropagate = Seismic Imaging
More LessThe recent advances in seismic acquisition and processing have made it possible to obtain more accurate representations of subsurface geology than ever before. More accurate and advanced implementations of deghosting, denoise, demultiple and anisotropic velocity inversion and Qattenuation- factor determination techniques are the fundamentals of high resolution seismic imaging. Receiver-side deghosting through dual-sensor streamer (PGS), over/under single-sensor streamer (WesternGeco), single-streamer Broadseis (CGGV) or 2C/4C OBC acquisition & processing has become common practice whereby extending usable frequency bandwidth of seismic data. Denoising through filtering in a variety of data domains (shot, receiver, offset, cdp) through XT, FK,
TauP, FX, Wavelet-Transform based techniques are very successful and available from all vendors. Effective demultipling through short-period and long-period 2D/3D surface & interbed multiple attenuation techniques are essential for the success of the next steps namely: (1) Velocity & Q inversion and (2) Depropagation (Backpropagation) + Imaging Condition = Seismic Imaging (Migration). The best subsurface imaging approach PreStack Depth Migration method has to rely on highfrequency accurate background models as compared to earlier approaches which use smooth background models with some hard-boundaries as needed i.e. salt or carbonates. Otherwise, it is unlikely that reservoir imaging below challenging overburden settings will be resolved. To realize the
goal of high-frequency accurate background model building, direct-arrival tomography and reflection travel-time tomography, acoustic/elastic inversion, Q-tomography, full-waveform inversion techniques are being utilized to set up the appropriate background model for final imaging.
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Dip-Dependent Corrections for Data Reconstruction in Trueazimuth 3D SRME
Authors Peter Aaron, Roald van Borselen, Rob Hegge, Simon Barnes and Maz FaroukiThis paper presents a method to apply dip-dependent azimuth, midpoint and offset corrections during the data reconstruction in True-azimuth (TA) 3D Surface-related Multiple Elimination (SRME). The method is applied to synthetic examples and a field dataset. Comparisons are made with a TA 3D SRME which uses a more conventional differential NMO reconstruction, with no additional corrections. Results show that the new method is capable of correcting for primaries, diffractions, multiples and diffracted multiples. It is demonstrated that correcting for azimuth, midpoint and offset effects using geological constraints, during the data reconstruction can significantly improve the prediction of multiples in the presence of complex 3D events, such as diffracted multiples.
TA 3D SRME has already been shown to deliver a significant uplift in de-multiple when compared with 2D SRME and other zero-azimuth forms of 3D SRME (Aaron et al 2008). This is the result of honoring the azimuth of input traces by predicting multiples at the exact input source and receiver locations. However, in order to predict multiples with TA 3D SRME, a large number of traces are needed with a wide array of midpoint, offset and azimuth values. Since it is not feasible to acquire all of the required offsets and azimuths needed at each location, they must be reconstructed from the data that is available. While the differential NMO in the data reconstruction part of the SRME process attempts to correct for the offset difference between the desired trace and the best fitting trace, it does not correct for the differences in midpoint and azimuth. Our method corrects for the azimuth, midpoint and offset differences between the desired and best fitting trace. The dip-dependent TA 3D SRME was applied to an offshore field dataset and showed improvement in attenuation of the complex diffracted multiples when the dip-dependent corrections are applied during data reconstruction.
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Seismic Imaging Near and Within the Basement Offshore Malaysia; Including Comparisons of Imaging Algorithms
Authors Nabil El Kady, M. Shah Sulaiman, Zabidi M. Dom, Tang Wai Hoong, Lee Mei Lu, Pavel Vasilyev and Martin BaylyBetter 3D acquisition and better imaging have made it possible to explore complex basement plays in Vietnam, Indonesia, and the Malay Basin with some success. It is postulated that oil from adjacent formations may get trapped (under favourable conditions) in vughs and fractures within the basement. Imaging the basement architecture is a key issue (Deva Ghosh et al., TLE, April 2010, also; Areshev, 1992, Reservoirs in Fractured Basement on the continental shelf of Southern Vietnam, Journal of Petroleum Geology, Vol 15, Issue 3, pp 451–464). In this paper we describe the data preparation; velocity model building and migration methods applied to successfully image the data. The basement fractures are present at a variety of scales but to aid interpretation the larger, seismic scale fractures and faults need to be clearly imaged. In addition to imaging the basement, the seismic data processing flow also was designed to resolve and image shallower clastic horizons. Pre-processing of this data followed a generally industry standard marine data processing flow, however, particular attention was paid to the deep basement events and to the application of multiple attenuation type processes. This data exhibits a strong vertical compressional acoustic velocity change between the younger clastics and the harder, older basement, with the possibility of intermediate velocity metasediments. Due to the extreme spatial changes in depth of the basement and regional scale faulting there are strong and rapid lateral velocity changes within the dataset. This necessitates the application of pre stack depth migration techniques that can comprehend the lateral changes.
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Broadband Marine Seismic – Breaking the Limits
Authors Robert Soubaras and Carl NotforsThe importance of recording the full range of frequencies (low as well as high) is widely accepted. High-fidelity, low-frequency data provides better penetration for the clear imaging of deep targets, as well as providing greater stability in seismic inversion. Broader bandwidths produce sharper wavelets and both low and high frequencies are required for high-resolution imaging of important features such as thin beds and stratigraphic traps. The industry has been facing many issues that have limited the performance of marine seismic surveys with respect to bandwidth. Among them, we find mechanical and acoustic noise, source and receiver ghosts and attenuation with depth. Until recently, conventional de-ghosting was found to be sub-optimal. Thanks to recent advances in technology and also in operational capabilities, we have seen several improvements, in particular with the use of solid streamers, deep towing and notch diversity. We describe a different technique to achieve broadband marine streamer data. The proposed
solution is a new combination of streamer equipment, novel streamer towing techniques, and a new de-ghosting and imaging technology. It uses receiver notch diversity to yield a broadband spectrum and takes full advantage of the low noise and low-frequency response of the new generation of solid streamers. As a result, the method creates an exceptionally sharp and clean wavelet for interpretation. It can be tuned for different water depths, target depths and desired output spectra.
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Seismic Imaging Below Shallow Gas Cloud – A Comparison Between PSTM, PSDM & 4C OBC Datasets
Authors Tan Boon Hua, Amy Mawarni M. Yusoff and Gunawan TaslimSeismic data degradation due to shallow gas cloud is a common occurrence in the Malay Basin. As with many fields with large structures located in the central axis of the Malay basin, the field under study in this paper is also beset with this issue. This field, which is currently in the development stage, is a 30km long by 10km wide E-W trending elongated four way dip closure intersected by N-S & E-W striking normal faults. Two main structural culminations can be observed on the field. The major culmination lies to the eastern side of the field while a smaller one lies to the western side. The field is found to contain both oil and gas accumulation. A marine streamer 3D seismic survey was acquired over the field in 2002. The survey was acquired with an E-W line
orientation. This 3D survey data was originally processed using Pre-Stack Time Migration (PSTM) in 2002. Amplitude and frequency attenuation of reflectors were particularly severe on the two crestal culminations from approximately 800ms onwards. This problem was attributed to the presence of shallow gas and is further compounded by the presence of multiply stacked gas zones below the shallow gas. As a result, a number of key problems were inherent in the dataset, namely depth uncertainties especially at the crestal zones, fault imaging uncertainties within the gas cloud and also vertical resolution issues. The 2002 dataset was reprocessed using Pre-Stack Depth Migration (PSDM) in 2009. The aim of this exercise was to improve seismic imaging within the gas cloud, to improve vertical resolution via increased sampling rate, to increase the signal to noise ratio via new processing technologies such as SRME & model based Q and also to reduce depth uncertainty by deriving a high resolution velocity model representative of the changes in geology. Overall, the PSDM data did demonstrate improvements in terms of reflector continuity and frequency content within the gas cloud area. Fault imaging uncertainty, even though still present, has also improved as the fault interpretation within the gas cloud was carried out with greater confidence. Depth prediction at wells based on the PSDM has also shown improvements over the PSTM based prediction. Despite these improvements, the fundamental uncertainties in the dataset remain present as they were inherent to the acquisition process itself. Also in 2009, a 4-Component Ocean Bottom Cable (4COBC) test line was acquired over the gas cloud zone on the eastern culmination of the field. This operation was carried out to demonstrate two key points. The first was to demonstrate the feasibility of carrying out an OBC acquisition in the studied field while the second and more important point was to demonstrate the data quality improvements of the OBC data over conventional streamer data. The 4COBC test line was acquired in a N-S orientation as opposed to the E-W orientation of the streamer acquisition with the intention to undershoot the gas cloud, and thus give better imaging. Preliminary results from the 4COBC data has shown marked improvements over the streamer data on the particular test line in all imaging and structural aspects which were noted earlier. These results suggest that 4COBC seismic acquisition is feasible in this field and is probably the methodology that will give the best imaging of the field under today’s technology. In summary, this paper has demonstrated that the 2009 PSDM has managed to improve the seismic data processed via PSTM in 2002. However, the problems faced by the 2002 PSTM attributed
to shallow gas cloud are still present in the 2009 PSDM dataset as they are inherent to the acquisition process. In order to break away from these problems, a 4COBC survey may be the way to go. Such a survey dataset can potentially enable the many structural & imaging issues of the seismic dataset to be resolved within the development phase of the field.
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4D Seismic Analysis of Reservoir Sands Overlying a Salt Structure
PETRONAS Research has recently embarked on a study to determine and understand
pressure-saturation variations in a field through the use of 4D seismic technology. Changes in
hydrocarbon pressure and saturation due to production produce noticeable changes in amplitude
response. 4D seismic or the use of repeated time-lapse 2D/3D seismic surveys enables detection of
4D signal indicative of pressure or saturation changes.
The C field is located some 80 km due east of the coastline of West Africa. Water depth
ranges from 739.3 to 823.6 m with area of 60km2. The oil and gas in the field are trapped in Early to
Mid-Miocene reservoir sands above a faulted dome caused by underlying salt intrusion. The dome is
faulted by low angle (45-60°) radial faults. A dominant east-west fault set subdivides the structure
into an uplifted area in the north and a downthrown area to the south, which is itself separated into
east and west fault blocks by a large north-south fault. Hence, the faults compartmentalize the field
and hydrocarbons into three main fault blocks. The reservoir represents mid-slope turbidites which
consist of a series of fining upwards sequences.
Conducting 4D seismic analysis and understanding pressure-saturation variations involve
integrating several geophysical technologies. These technologies include well-synthetic-seismic
correlation, Rock Physics, Production Scenario Seismic Modeling at selected injector/producer wells, 2D/3D seismic modeling, 4D AVO Modelling/Interpretation and correlating seismic attributes with
engineering data, pressure history and saturation measurements.
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4D Seismic Interpretation in Angsi Field
Authors Tan Chin Kiang, Wahyudin Suwarlan, Kartina Ali and Fariz FahmiSome brown fields have the 4D seismic technology applied successfully to optimize reservoir production and recovery. This paper describes a case study on Angsi field where by the 4D seismic has contributed significantly as input to the reservoir dynamic model as well as for a deeper understanding of the reservoir behavior. This paper illustrates key lessons that we have learnt from the 4D application, focusing on feasibility study, QC during interpretation phase and 4D information on the reservoir management.
The Angsi field is located 167kms NNE from Kerteh, offshore of Peninsular Malaysia with average water depth 69m. The depositional environment of Angsi field is fluvial coastal plain environment. The field was discovered in 1974 with exploration Angsi-1 and subsequently followed by 7 appraisal wells. Oil and gas have been produced since 2001. Water injection was the chosen technique to manage the reservoir pressure during depletion. Understanding the water movement and response is the concern in the water injected field. The base seismic survey was acquired in 1995 while monitor survey in 2006 after 5 years of production. The primary objective of the 4D was to monitor the water movement from the injector wells. The success story of the technique in Angsi field is the ability to map the water movement in I35L reservoir, understanding the reservoir compartmentalization issues, pattern of preferred water movement and reducing the reservoir quality uncertainty.
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Major Controls on Deepwater Reservoir Distribution, West Africa
The study of Major Controls on Deepwater Reservoir Distribution, West Africa was mainly focus on the risk factor associated with reservoir sandstones in the deepwater areas of West Africa covering Cameroon, Equatorial Guinea, Gabon, Congo and Angola. Based on previous unsuccessful exploration results by Petronas up to 2006, it was found that the main factor for this is due to poor understanding of reservoir distribution in the region. This study was carried out to gain a better understanding on the geology of West Africa, particularly with regards to the transport and delivery of sediment from onshore to deepwater areas along the West African margin. This involves a study of the margin evolution both onshore and offshore areas. The primary objective of the study was to improve the understanding of sediment supply to the basins offshore West Africa, with the aim to enhance the prediction of reservoir distribution and quality. Understanding the entire sediment distribution system from source to sink is fundamental to improve models of reservoir distribution and quality. The hinterland analysis allied to a review of offshore data, can significantly enhance the fundamentals of this source to sink sediment distribution system.
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Transgressive-Regressive Cycles in the Malay Basin: the Interplay of Tectonics and Sea Level Changes in a Silled Basin
By Mazlan MadonUnderstanding the interplay of tectonics versus sea level changes in sedimentary basins has important economic implications. In rift/extensional basins, stratigraphic onlaps and pinchouts can form important hydrocarbon traps. Onlap plays develop on the basin margins during transgressions, whereas reworked/re-deposited shallow water sands and turbidites deposited during regressive events may form basinal plays. Transgressive-regressive cycles in a deforming rift (extensional) basin are strongly influenced by both eustatic sea level changes and tectonic subsidence/uplift. To explore for such plays it is important to understand how these major factors control sedimentation.
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From Depofacies to Lithofacies: A Way to Integrate Facies and Rock Types into 3D Geocellular Models
More Less3D geological facies modeling has been confused in the past with 3D petrophysical rock types (PRT) modeling. The efforts made by sedimentologists trying to understand the 3D geometry of facies and their distribution in the reservoir, sometimes are not well used by modelers who base their facies definition on petrophysical cutoffs which normally don’t follow sedimentological concepts. There are many important implications when determining facies using petrophysical cutoffs: 1. Even though petrophysical properties are initially delineated by sedimentation processes, they are normally altered by diagenetic processes (Morad, et al 2010). This causes mismatches between core described facies and facies based on petrophysical cutoffs. 2. It is not possible to capture the log signature of the facies which is linked directly with their 3D shapes (Serra, 1986). This causes, for example, that sandstones deposited in canalized systems which normally exhibits a bell or cylinder GR signature can be treated as those deposited in fan shapes which exhibit funnel log signatures. 3. There is a bias when selecting core plug for determining petrophysical properties (Terzaghi, 1965). Normally the sampling is concentrated in medium to high quality reservoir rocks and shales are not sampled. This causes that during clustering in crossplots for defining facies, data is not representative of the bad rock quality facies. This paper presents a methodology for facies modeling integrating core facies definition, conceptual geological models (depofacies and petrophysical rock types. Two field cases, one in South America and the other in South East Asia are used to apply this methodology.
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