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PGCE 2008
- Conference date: 14 Jan 2008 - 15 Jan 2008
- Location: Kuala Lumpur, Malaysia
- Published: 14 January 2008
21 - 40 of 79 results
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Sarawak Malaysia Deepwater New Turbidite Play
Authors Fauzil Fanani B. Radilas and Sheh Yackop Abdol KarimBlocks 2A and 2B, located offshore Sarawak in east Malaysia, covers 9000 square kilometers in water depth 150 – 1500 m. Two dry wells were drilled both of which lack post-Middle Miocene Unconformity (MMU) reservoir. Mulu-1 was drilled in 1995 on Block-2B to Cycle 1 at a total depth 5,029 m, and Jelawat-1 drilled 60km SW of Mulu-1 on Block-F encountered significant C1 to C5 gas from MMU sequences. Gas was interpreted from mature post-MMU deep marine sources. Thousands kilometers of fair to good 2D seismic data over the area indicate the presence of strong, continuous events near top MMU sequence boundary. Post-MMU seismic data is characterized by weak, bluer discontinuous reflectors interpreted as massive deep marine shales. Several strong seismic anomalies in Post-MMU sequences have been delineated and are interpreted to be sourced from reworked Pre-MMU sequences. Strong amplitude seismic attribute analysis are wide spread and interpreted to be clastic basin floor fan sediments originating from several feeder channel systems. Amplitudes weaken at the fan edges. Basin floor fans exist in lows and on the flanks of lows. These stratigraphically discontinuous units are enveloped within thick post MMU shales. Sourcing is not considered a problem due to local charging. Risked resources calculated indicate significant hydrocarbon potential is believed to be located in the area.
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Play Types and Hydrocarbon Prospectivity in Petronas’ Blocks N44, N45, N50 and N51 Offshore Northwest Cuba
More LessIn late 2006, PETRONAS Carigali Overseas Sdn Bhd (PCOSB) was awarded the Cuba’s Exclusive Economic Zone (EEZ) offshore blocks N44, N45, N50 and N51. These blocks located to the North West of Cuba are in water depths ranging from 1000 m to 2800 m (Figure-1). The first three-year sub-exploration period calls for a minimal work commitment of 4000 line-km of 2D and 1000 sq km of 3D seismic data. About 3968 line-km of existing 2D seismic data from the Compagnie Générale de Géophysique (CGG) spec survey and Russian / CubaPetróleo (CUPET) survey were available for PCOSB. Consistent interpretation on the existing seismic data, with proper scientific explanations to the tectonic history of the opening events of the Gulf of Mexico and its sedimentary occurrence have identified various potential playtypes in this area (Figure-2). Remarkable similarities have been found in depositional environments and stratigraphic units between the continental areas from the East Gulf of Mexico and North West of Cuba. An integral knowledge of the geological context is fundamental in order to infer the main analogies in successful hydrocarbon producing areas in the Mexican part of the Gulf of Mexico and the location of potentially new highly productive petroleum systems in the area. The recently acquired 2D seismic data and the future to be acquired 3D seismic data will further confirm and mature the identified plays and are also crucial to reduce uncertainty and economic risks in this new exploration challenge.
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The Evolution of Geological Thinking and Depositional Framework Interpretation through the Life of a Complex Reservoir, D35 Field, Offshore Sarawak
The D35 field is a sizeable hydrocarbon accumulation discovered by Shell in 1983, located 135 km north from Bintulu, within the Balingian Province of Offshore Sarawak. Hydrocarbons are contained within the stratigraphically complex Early to Middle Miocene clastic sediments, principally in Cycle II and to a lesser extent in the lower part of Cycle III. Its main hydrocarbon-bearing reservoirs comprise thick, stacked, cross-bedded sandstones, pebbly cross-bedded sandstones, sandy conglomerate and wavy-to-irregularly laminated sandstone. These sediments were initially interpreted by Shell as fluvial channel deposits, a model which was maintained until the relinquishment of the field in 2004.
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More Oil From an Old Field
More LessBaram field is located in Sarawak Basin, East Malaysia. The field was discovered in 1963 by Baram-1 well in the down-thrown side of the main growth fault. Six additional appraisal wells including the discovery well for Baram South Fault Block were drilled prior to formulating development plans. (Figure 1) The depositional environment is predominantly fluviomarine-coastal inner nerritic reservoirs from Late Miocene to Early Pliocene in age (Upper Cycle V to Lower Cycle VI). Oil bearing reservoirs occur at depth 2500 to 9000 ft tvdss in the sand-shale intercalation settings. In recent years, a systematic detail re-evaluation of the field was carried out to identify further development opportunities. For the G&G aspect it covered the re-analysis of the well correlation, seismic
interpretation, hydrocarbon fluid distribution, and uncertainties analysis. 3D static model has been used and developed for the analysis. (Figure 2). Dealing with the multi-stacked with various thicknesses; range around 10 ft to 60 ft tvdss is challenging. But with the effectiveness use of 3D static modeling, state of art drilling technology, challenging the past assumption and maximizing the development of the minor reservoirs have resulted in identification of upside potential and new reserves. (Figure 3). In 2005 until 2007, 15 wells were drilled from two drilling platforms to further appraise and develop Baram South field, while 4 sidetracks wells, 1 workover & 3 wells were drilled to develop Baram A area, which gave very encouraging results. The overall production of the field has reached the same level as in 1974, i.e 32 years after first field production. (Figure 4).
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Pre-Tertiary Carbonate Play, Offshore Peninsula Malaysia, a Revival of Forgotten Play
Authors Ogail A. Salam and Sahalan A. Aziz and M. Yamin AliThe exploration activities in offshore Peninsular Malaysia have started as early as 1960’s. The first well was drilled in 1969 and the oil discovery had made the area as a new petroleum province in Malaysia beside those in the Sarawak and Sabah Basins. It was then followed by several exploration cycles in 1970’s and 1980’s with many significant discoveries.
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Marine Acquisition and Processing Using Dual Sensor Towed Streamer
PGS has been developing an entirely new towed marine streamer concept for about five years. The project objective was to engineer a streamer that is capable of recording both the scalar pressure field and the vertical component of the vector particle velocity field. PGS’ Next Generation Streamer has accomplished these objectives, and is a step change in streamer technology. This technology overcomes the limitations of hydrophone-only acquisition systems, and allows PGS to separate the up-going wavefield incident upon the streamer from the down-going-wavefield that is reflected from the sea surface. It is thus possible to remove the receiver ghost from the data, at all depths, and thereby recover significant low and high frequency amplitudes normally missing from marine seismic data. It is no longer the case that E&P decision makers must parameterize streamer surveys to maximize data quality at one target depth, whilst sacrificing image quality at shallower or deeper targets. The PGS Next Generation Streamer uses an extremely quiet, ruggedized solid streamer design to provide enhanced resolution, better penetration, and improved operational efficiency. In fact, the towing depth is typically quite deep, thus increasing the operational window in poor weather or environmental conditions that no other system can handle. PGS experience demonstrates that the technology can deliver deghosted data not just for one depth, but for all depths – in one pass, using one streamer depth. It is also a no-risk technology – PGS can use the dual-sensor information to duplicate the parameters of any existing survey, thus allowing 4D matching plus the benefits of improved image clarity. PGS has assembled a full acquisition and data processing product range for the Next Generation
Streamer. 2D commercial operations are planned to begin in late-2007, followed by 3D commercial operations in 2008.
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Sub-Basalt Imaging Offshore India
Authors Tim Bunting, Tim Brice and Sean Murray and Chris KoeningerThe Deccan Trap consists of multiple episodes of lava flows covering large areas onshore and off the West coast of India overlying a number of potential hydro-carbon plays. Due to the high reflectivity of the top-basalt, and the high absorption of the basalt layer, the seismic signal returning from the sub-basalt events is very low amplitude resulting in poor reservoir imaging, with conventional seismic acquisition. This paper describes a test survey acquired by WesternGeco, to use over-under seismic acquisition to
improve image of the intra-basalt and sub-basalt layers. Over-Under acquisition in which sources and or streamers are towed at different depths. Post acquisition wave-field combination techniques take advantage of the change in ghost response, resulting from the different tow depth, to fill of shift the notch resulting in a higher bandwidth image.
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Widening the Acquisition Time Window with Swell Noise Attenuation Capability
Authors George McKinley and Wayne ZanussiSeasonal timing is a critical factor in the acquisition planning stages of a seismic survey. Once vessel availability has been secured for the desired period, the predicted weather conditions must be considered. In Peninsular Malaysia it is widely accepted that March through October is the optimum time window for seismic acquisition, as beyond that period monsoon activity causing rough seas can negatively impact the data quality. Despite the risks associated with the monsoon season it is not uncommon to see seismic vessels operating in West Malaysian waters well into November, as past history has shown periods of breaks in the poor weather allowing for data to be acquired. The survey which forms the basis of this study actually commenced in November and continued to acquire data until the end of January, potentially experiencing the most undesirable of annual weather conditions as it progressed. The purpose of this paper is to illustrate that despite the adverse affects of harsh monsoonal weather on the dataset acquired, seismic processing efforts were capable of attenuating the resultant noise to a level which was considered acceptable for further processing.
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Time-Domain High-Resolution Radon Transform
Authors Michel Schonewille and Peter Aaron and Carl NotforsMultiple attenuation may be classified in two main methodologies; 1) Prediction of multiples from the data itself, and 2) utilizing moveout separation between multiples and primaries. A commonly used version of the prediction approach is the so called SRME technique, where surface related multiples are predicted from the data itself, and at least in principle, does not require any further information. The SRME approach, certainly in its 3D implementation is very computationally intensive, but in recent years with the advent of commodity priced Linux clusters, has become very popular. However, the SRME technique does not work well in shallow marine environments and does not handle interbed multiples, thus there is still a need for approaches based on separation. In this paper we present the method utilizing multiple-primary separation in a tutorial fashion and show its progression from its simplest form in FK space to the latest time-domain Radon high-resolution demultiple.
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Imaging of Fractures and Faults Inside Granite Basement Using Controlled Beam Migration
Authors Don Pham, Jason Sun, James Sun, Qingbing Tang and Graeme Bone and Nguyen Truong GiangIn this paper, we present a reprocessing case study that applied the latest processing technologies to improve the seismic imaging inside the granite basement reservoir. The highlight of this effort is the application of the latest Controlled Beam Migration (CBM) technology, and a stack sweep method for updating velocity inside the basement.
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NMO Application in VTI Media: Effective and Intrinsic Eta
Authors Joel Starr and Maz FaroukiNMO or normal move-out is the time shift needed to correct for the effect of offset and velocity in a CMP gather. NMO equations approximate the time shift which would be computed by tracing a ray through a horizontally layered Earth. A few years ago the 2nd order NMO equation, or hyperbolic NMO, was considered adequate in most cases. Today there are many options in the industry to apply higher order NMO which reduces the error in the approximation to the ray traced solution for longer offsets. There are two
characteristics which are important when considering the application of a given NMO curve: 1) accuracy, how well the NMO curve approximates the ray traced solution, and 2) stability, how well the curve can tolerate small errors in the estimated velocity field (one would not want small errors in the estimated velocity field to cause large errors in the move-out time calculated). If the data being processed is isotropic in nature, then the NMO equation will be dependent on velocity, v and offset x. If the data exhibits VTI (transverse isotropy with a vertical axis of symmetry) behavior, where the velocity of acoustic waves traveling horizontally is different from the velocity of acoustic waves traveling vertically, then the parameter η is used in the NMO equation in addition to v and x. Effective η in the NMO equation expressed by Alkhalifah and Tsvankin (1995) is required to correct for both longoffset (non-hyperbolic) and VTI effects in seismic data. Since two effects are being handled by a single parameter, it is difficult to determine if a dataset exhibits VTI behavior solely on the need for an effective η (ηeff) parameter to NMO correct the cdp gathers. This leads to ambiguity in the interpretation of ηeff when performing velocity analysis and time imaging. An optimized 6th order NMO equation separates the longoffset terms from the VTI term. The η parameter in this equation is needed only to correct the VTI effects and as such it represents intrinsic η (ηint). The use of these two equations has been compared in two case histories. In the first case history, ηeff is required but ηint is not required. As such, the data exhibits long-offset isotropic behavior. In the second case history, both ηeff and ηint are required in their respective NMO equations; therefore, the data exhibits VTI.
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Geophysical Issues and Challenges In Malay and Adjacent Basins
More LessAlthough seismic method has been successfully in the Malay, Sarawak and Sabah basins for quite sometime, there are many geophysical issues that are not well understood or fully resolved. Some of the problems are structurally related whereas the rest are related to interpretation of amplitudes. Of the most complex problem is the gas wipe out issues. Many of our reservoirs suffer from shallow gas leakage and are difficult to image. The easiest way to resolve this problem is the use of shear wave through Ocean Bottom Cable (OBC) technology. However it is quite expensive and most of operators are reluctant to use the technology. An alternative but less effective way is to better focus the P-wave energy by considering approaches like a. Compensation for absorption and or b. Internal scattering within the gas body Another imaging issue is the fault shadowing problem in many tectonically disturbed areas (Sabah) which gives poor imaging in key zones below the fault. Seismic wave propagation in Malay basin is complicated. In the most cases pay-beds are thin in the seismic tuning range so the earth behaves as an “effective media”. Wave propagation in this “media” is different and needs to be understood better. In terms of relationship between amplitude to hydrocarbon prediction certain ambiguities arise from amplitude response caused by lithology or those by pore fill. Further spurious amplitude and AVO responses may come from 1. Soft shales and hard shales 2. Coal layers 3. Brine soft sands Ambiguity of equivalent response in seismic inversion is a very common pitfall. For example: A poor quality sand with gas might give similar response as high quality sand with brine within errors of uncertainties and noise. Some of these issues will be addressed and certain solution suggested.
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Exeter Mutineer – Case Study of an Integrated Project from Seismic Survey Design to Inversion
Authors Tim Bunting and Richard Patternall and Frazer BarclayIn 2006 WesternGeco acquired a seismic survey for Santos, to image the Exeter Mutineer field on the North West Shelf of Australia. Although the field has been in production since 2003, the understanding of the reservoir is limited. Existing seismic was of marginal quality and did not deliver the subtle detail required to understand the complexities of the Exeter Mutineer reservoir. The new seismic has delivered significant uplift in resolution over the existing seismic. This case study will initially discuss the background and drivers for the new acquisition and then look into how the combination of high end acquisition technology and the integrated approach delivered value to the oil company.
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Comparative Analysis of Simultaneous Inversion Result with Elastic Inversion and AVO Envelope in Sumandak Field
More LessDirect hydrocarbon indicators play a very important role for prospect identification. The seismic amplitude based hydrocarbon indicators derived only from seismic information are qualitative and inherited with the tuning and other noise artifacts. There are several techniques to derive hydrocarbon indicators from the integration of well and seismic amplitude information. In the present study, a comparative analysis of Amplitude Variation with Offsets (AVO) envelope, Elastic inversion and Simultaneous inversion results has
been carried out in the Sumandak field. The interpretative analysis of simultaneous inversion results indicates that the reservoir can be predicted more accurately with LambdaRho-Vp/Vs attributes volumes in comparison to AVO envelope and EI results. It has been concluded that some of the AVO features are unconformable with structure; however, the simultaneous inversion results are conformable to geological structures which boosts the confidence to use the simultaneous inversion result instead of AVO envelope and Elastic inversion for quantitative interpretation.
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3D Close-the-Loop: Reconnecting Reservoir Modeling to the Seismic Data
More LessIntegrated reservoir modeling is a challenging task and in order to ensure the best possible model(s) it must honor all available subsurface data. Successful modeling studies require that all subsurface disciplines are involved throughout the whole process and are QCing the model in the context of all available data. Good quality seismic data is available for many fields and should be fully used in reservoir modeling. We are proficient in incorporating the interpretation of horizons and faults from the seismic data into the
model framework. On many occasions seismic inversion products (for example, acoustic impedance volumes) are used to guide the distribution of reservoir properties, like Porosity or Net-to-Gross, throughout the model. Care is taken to QC the model to ensure consistency with the petrophysical data at the well locations and the geologic concept (distribution of facies, properties, and shapes). But the seismic response of a model was not compared to the actual seismic data.
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Elastic Impedance Inversion for Reservoir Delineation– A Quantitative Interpretation Case Study in the Malay Basin
Authors N. Cheng, I. Bukhari, I. Kanok and S. Awirut and C.VitoonThis case study focuses on development well targeting using the methodology of elastic impedance inversion to identify effective seismic attributes for delineating thin gas sands formed in a tidal environment with massive coal-beds. The study area is located in the Malaysia-Thailand Joint Development Area (MTJDA) to the north of the Malay Basin. The reservoir sands, statistically are less than 10 meters and inter-bedded with coals (Fig-1). Seismically, the reservoir sands are below seismic tuning thickness resolution and strong coal reflections interfere with the conventional post-stack seismic data. A comprehensive workflow based on pre-stack elastic impedance inversion was developed to address the aforementioned effects and gain more value from the seismic data. The workflow includes three key steps: modeling, processing and interpretation.
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Integrated Geological and Geophysical Analysis by Hierarchical Classification: Combining Seismic Stratigraphic and AVO Attributes
Seismic attributes analysis and classification for exploration and reservoir characterization have been widely published. Applications vary from standard horizon-based facies classification maps to more recent 3D multi-attribute facies classification volumes. The approach is usually the same and run in a two-step procedure. First, an unsupervised classification aims at revealing the natural clustering of the data, and second, a supervised scheme is applied where training and validation data are used to redefine the class cloud point centers based on well log data flagging a specific fluid or lithology. The limitations of these approaches are that they are focused on one aspect of the seismic response, usually fluid, and tend to neglect the geological framework. In these workflows, more attention is put on the reservoir facies for fluid and potential lithology detection, while the seismic seismostratigraphic signature is overlooked or not used as a constrain in the attribute analysis. We present a case study in which both texture facies and fluid prediction are linked by performing a hierarchical classification and estimation scheme whereby a multiattributes volume, which captures seismic stratigraphy and texture information, is combined with AVO attributes to map fluid response into a single,
coherent seismostratigraphic and reservoir facies volume. This methodology is applied for exploration data screening in offshore Borneo in the Greater Samarang sub-block (East Baram Delta, offshore Sabah, Malaysia). In this case study, geological framework, seismic geomorphology, seismic stratigraphy, and combined fluid response from AVO data calibrated with well data facilitate the development of new play concepts in the highstand system tracts and in the morphology generated by incisions in the shoreface deposits during the low stands.
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Volume Blending with Directional Seismic Attributes
Authors Arthur E. Barnes and Surender S. ManralMulti-attribute analysis through volume blending is a powerful but under-utilized tool for revealing details in seismic data. It is most effective when a seismic attribute that highlights geologic structure, such as discontinuity or lightscape (shaded relief), is displayed in grayscale and combined with an attribute that highlights an element of stratigraphy, such as reflection strength (trace envelope) or average frequency, displayed in color. The directional attributes, lightscape, azimuth, and amplitude gradients, are particularly effective for volume blending. Filtering the structural attributes often greatly improves them for blending.
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Application of Rock Physics Modelling and Seismic Attribute in Developing the Geological Model - An Example from Eocene Deepwater Turbidite in Block 21/23A, CNS, UK.
Block 21/23a is a sub-block of UKCS Block 21/23, which is located within Quadrant 21, Central North Sea, UK. A total of three fields were discovered in Block 21/23, namely the Pict, Saxon and Sheryl fields. The Pict and Saxon fields are located in Block 21/23b and operated by PetroCanada. The Sheryl field is located in Block 21/23a and operated by Oilexco. The Sheryl field was discovered in year 2006 based on Elastic Impedance anomaly. The discovery was made in the Eocene Tay deepwater turbidite reservoir. This study is based on an integrated approach of utilising the rock physics forward modelling, seismic attribute and geological data in constructing a robust conceptual geological model for the purpose of further prospect evaluations and static model building. Rock physics forward modelling was conducted prior to seismic data interpretation to build a geophysical database comprising the analogues of seismic responses under different rock properties and pore fluid contents. This database was used to enhance the accuracy in seismic data interpretation. The forward modelling results concluded that the MuRho (μρ) dataset can be used as a lithology indicator, while the LambdaRho (λρ) dataset is a fluid type indicator. The AVO modelling showed that brine, oil and gas saturated sands are characterised by Class I, Class II to IIp and Class III AVO responses respectively. The palaeogeographic map clearly demonstrated that the study area can be divided into four main depositional environments, namely shelf edge, slope, proximal and distal basin floors with increasing relative palaeo-water depth from SW to NE. The shelf edge setting was interpreted based on its thicker Tay stratigraphic unit observed at the proximal part of the canyon system identified on the slope setting. The proximal and distal basin floor settings were differentiated based on the sand geometries, where the former is characterised by channelised sand and the latter contained sheet-like sand geometry that was interpreted to be basin floor fans. Eventually, a conceptual geological model was developed based on the interpretation of all the available geological and geophysical data.
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The First Megamerged Seismic Data Processing Project in Malaysia
More LessThis paper looks into the method by which the then Veritas team used to re-grid the surveys to a common ‘master’ grid. This so-called master grid was set up such that future 3D surveys could be incorporated relatively easily into this dataset. The discussion shows how each volume was matched to be of common amplitude, bandwidth and phase and then finishes off by viewing the philosophy behind the merging of the volumes which culminated in a single output dataset.
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