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PGCE 2011
- Conference date: 07 Mar 2011 - 08 Mar 2011
- Location: Kuala Lumpur, Malaysia
- Published: 03 July 2011
1 - 20 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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