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PGCE 2008
- Conference date: 14 Jan 2008 - 15 Jan 2008
- Location: Kuala Lumpur, Malaysia
- Published: 14 January 2008
79 results
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Structural Controls on Hydrocarbon Migration & Accumulation: An Example Form the Muglad Basin, Sudan
Authors James Will Udo Agany and Hamdan MohamadThe Muglad Rift Basin of the interior Sudan forms an important part of the West and Central African Rift System. It is characterized by thick non-marine clastic sequences of Late Jurassic/Early Cretaceous to Tertiary age. So far, well penetration is restricted to the Tertiary section in the deepest parts of the basin. However, more than 15 km of sedimentary section have been inferred from seismic data in the main trough.
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The Prospectivity Of Stratigraphic Traps In Group I Interval, Serok - Laba Barat Area, Block PM 324, Malay Basin
More LessThe Serok – Laba Barat area covers 20km x 20km, is located in open block PM 324 and geologically situated in the central part of the Malay Basin. It is made up of two east-west trending main culminations dissected by north-south trending sealing faults which were sites for typical fault-dependent plays exemplified by its three major discoveries: Serok (1979), Laba (1979), Laba Barat (1990). These discoveries proved significant hydrocarbon accumulations at mainly Groups E, F and H intervals. However most, if not all, of the previous wells drilled in the area did not adequately test the Group I section where nevertheless oil shows were observed.
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Basin Modelling and Petroleum System Analysis of Southern Sulu Sea - East Sabah Basin
By Chan Eng HoeThis paper presents the results basin modelling work done on the southern portion of Sulu Sea – East Sabah Basin. The study area straddles across the international boundary separating Malaysia and Philippine. A compilation of the seismic data, laboratories data and well data was prepared for the project under the agreement of both sides including but not limited to vitrinite reflectance data, temperature data and lithology data etc.
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Application of Development While Exploring (DWE) Approach in Marginal Fields Development in PCPPOC’s Block SK 305, Offshore Sarawak, Malaysia
Authors Foo Wah Yang, Azlan Ghazali, Medy Kurniawan and Bui Ngoc QuangPCPP Operating Company Sdn. Bhd. (PCPPOC), the Joint Operating Company of Sarawak Block SK305 PSC, is owned by a Consortium of Tripartite National Oil Companies, namely PETRONAS Carigali Sdn. Bhd. of Malaysia, PERTAMINA of Indonesia and PVEP of Vietnam.
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Utilizing Sequence Stratigraphic Concepts to Define New Plays in NW Sabah Basin
Authors Edy Kurniawan, Nurita Bt Ridwan and Robert Wong Hin FattNW Sabah basin, located in offshore of northwestern Sabah continental margin, is one of the most prolific hydrocarbon producing basins in Malaysia. The basin has been explored the last 110 years since the first exploration well Menombok-1 was drilled in 1897. The sequence stratigraphic study for NW Sabah Basin was conducted since first March 2007 in conjunction with basin evaluation study for this area. The main objective is to identify new hydrocarbon plays and leads other than the conventional play type in the study area with seismic sequence stratigraphic application.
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Using Core and Log Data to Link Depositional Environment with Oil System in Siliciclastic Reservoirs: Case Study from Muglad Basin, Sudan
Authors Yasir Mohamed Abdalla Ghorashi and Saif El Islam SulimanMuglad basin is the major part of Sudan rift system, which in turn, is a main component of West and Central Africa Rift-related System (WCARS). Sedimentary sequences of Muglad rift basin consist of nonmarine sequences of lacustrine and fluvial/alluvial facies of early Cretaceous to late Tertiary age directly rested upon the Precambrian basement. Muglad basin had passed through three sedimentary cycles. First sedimentary cycle began from early Cretaceous and its termination is marked, stratigraphically, by basin wide deposition of the thick sandstone of the Bentiu Formation. Second sedimentary cycle, occurred in late Cretaceous and seen in the widespread deposition of lacustrine and flood plain claystones and siltstones.
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Depositional Setting and History of Cored Intervals RS 8 Reservoir Block 1, South Caspian Sea, Turkmenistan
Authors David Ince, Gordon Yeomans and Graham BlackbournPETRONAS Carigali Sdn. Bhd. has been actively exploring and developing the Block 1 area of the Central Caspian Sea, Offshore Turkmenistan for the past 10 years and to date has drilled 16 wells of which five have been cored, providing a near complete coverage of the RS8 reservoir section. The information derived form analysis of the cores provides invaluable control over the static and dynamic models developed to assess reserves and predict likely reservoir behaviour.
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A Geocellular Modeling Approach to Characterization of Fluvial Stacked Reservoirs – Northern Fields, Block PM-3 CAA, Malay Basin
More Less3D geocellular modeling is becoming commonplace in today's sub-surface workflows. This short paper outlines, with examples, an approach to modeling reservoir morphology from seismic data and limited well information in the pre-development phase of a project.
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Sequence of Slope Instability and Healing: Key to Predicting Deep-Water Reservoir Distribution in NW Borneo
Drilling results in deep-water Sabah acreage have proved the presence of sizeable turbidite reservoirs in the NW Borneo basin-slope environment. The reservoir distribution and quality, however, show significant spatial and temporal variation. Spatial Heterogeneity is related to different source terrains, shelf dynamics and the location of entry points into the upper slope. The temporal heterogeneity is ultimately linked to the episodes of tectonic deformation and subsequent geomorphologic healing by gravity flow deposition.
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Seismically Driven Reservoir Characterization Using an Innovative Integrated Approach: Application to a Fractured Reservoir
Authors Abdel M Zellou, Soren Christensen, Tanja Ebbe Dalgaard and Gary RobinsonThis paper presents an innovative integrated workflow applied to the characterization of a fractured chalk reservoir in the Danish North Sea. The methodology uses simultaneous integration of geophysical, geological and engineering data to produce an improved reservoir description. Integrating dynamic flow data with the geophysical and geologic information in 3D, reservoir properties - porosity and effective permeability- are generated using artificial intelligence tools. The strength of this technique lies in the fact that property modeling is not constrained to match upscaled well data and consequently these data serve to validate the outcome.
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The West Crocker Formation (Early Oligocene to Middle Miocene) in the Kota Kinabalu Area, Sabah: Facies, Sedimentary Processes and Depositional Setting
Authors Nizam A. Bakar, Abdul Hadi Abd Rahman and Mazlan MadonThe West Crocker Formation in Kota Kinabalu area in Sabah is one of the best exposed examples of deepwater sedimentary sequence in Malaysia. This paper describes and documents the detailed facies characteristics and sedimentology of outcrops, and proposes a depositional framework for the West Crocker Formation in the Kota Kinabalu area.
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Structural Evolution of Mehar/Mazarani Fold Belt Area, Pakistan
Authors Shamim Haider Ali and Ramly ManjaPCPL is the operator of the Mehar Block since 29th December 1999. The area in geological terms represents the first line of fold belt coming out of foredeep to the east. The current interpretation of the Kirthar Fold Belt (KFB) is of thick-skinned tectonics involving preexisting extensional faults developed during late cretaceous times (Dr. J Warburton, Nov. 2000)and Mehar - Mazarani Fold Belt (MMFB) is part of the KFB . However, in order to develop a better understanding of the evolution of the MMFB, it is desirable to develop an understanding of the configuration of the basement and overlying sediments through times. An attempt is being made to integrate surface geology, well data, 2D seismic data and other parts of the Pakistan basin as analogue to build a model that would help in understanding the relationship between the structural geology and stratigraphy of area through time. This would eventually help in determining new Play fairway of this area.
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Mid-Miocene Unconformity
More LessThe Mid-Miocene Unconformity (MMU) is recognized throughout the South China Sea passive margin. It marks the end of rifting that created the marginal basin. It is understood to represent the break-up unconformity when active rifting gave way to sea-floor spreading in the contiguous southwest extension of the abyssal plain. Anomalies are not constrained in this part of the abyssal plain because the oceanic domain is very narrow and the magnetic anomalies not well expressed. However, magnetic anomaly 5c, whose age is estimated at 16.6 Ma, has been identified 300 km NE of the wedge-shaped SW extension of the oceanic area (Huchon et al., 2001). There is no direct drilling evidence of the age of the MMU.
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The Palaeotopographic and Palaeodrainage Evolution of the South China Sea Hinterlands from the Late Cretaceous to Recent
Authors Paul Markwick and Kerri WilsonThe tectonic complexity of Southeast Asia is clearly expressed in the modern hinterland topography and drainage of the region. Consequently, as the underlying tectonics has evolved, so to has the landscape. This has had major implications for the character and flux of clastics into downstream basins through time, which in turn affects hydrocarbon potential at the basin to prospect scale. In order to help understand this complicated history, we have compiled a series of detailed plate tectonic and palaeoenvironmental reconstructions for the South China Sea region. Upon these maps we have built models of the palaeolandscape and palaeodrainage basins and river systems. The methodologies used in the mapping integrate a re-examination of the underlying structure and tectonics using GETECH’s in-house gravity and magnetic data and expertise, with detailed palaeoenvironmental mapping that distinguishes between sediment source areas (regions above contemporary base-level, sensu Wheeler, 1964) and depositional sites (areas below contemporary base-level). By mapping regional base-level, we implicitly include an understanding of the dynamics of the landscape and the boundary conditions (climate, vegetation, rock type, etc). The method also provides the means whereby we can link the maps directly to sequence stratigraphy, with the ultimate aim of developing fully dynamic palaeolandscape models. Topography is then added to these maps through comparison with the elevational distribution of comparable Recent tectonic regimes, fission track, hypsometric analysis and other palaeoaltimetry, sedimentological and provenance data where available. For Indochina and South China, the maps reveal a complicated history of uplift, erosion and river capture that is manifest in the changing sediment fluxes to the offshore basins, with major rivers such as the Mekong, Red and Pearl only developing their modern topology by the Late Miocene. This talk will discuss the methods used to generate the maps and show some examples of this work. We will also demonstrate how we are developing methods to provide detailed insights into sediment generation and distribution through the petroliferous basins of SE Asia.
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Pore Pressure Prediction as a Prospecting Tool, Input to Risk, Volumes and Field Development
Authors John Paul Brown and Suriani Sulaiman MustahimTraditionally, pore pressure predictions calculated from offset wells and interval velocity data have been used almost exclusively to design well casings and drilling mud weight programs. However, a pore pressure prediction also contains valuable information on how oil, gas and water is behaving in the subsurface and importantly how fluid pressures will effect top seals, fault seals and column heights in hydrocarbon prospects. PETRONAS Carigali have begun to use pore pressure as a critical input to pre-drill prospect
evaluation by combining fault and horizon information, derived from geological maps, with an understanding of how fluid migration and pore pressures, derived from pore pressure predictions, can affect trap risk and volumes. The use of pore pressure predictions as an primary exploration tool has the advantage that it does not require any additional computational work since a pore pressure prediction must be produced in order to design a well. The key change is a modification to the existing exploration workflow so that pore pressures are calculated during the initial exploration stage which allows them to be combined with mapped horizon and fault data to produce integrated geo-pressure / geometric trap scenarios.
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Sedimentological Analysis of an Early Miocene Tide-Influenced Deltaic/Coastal Plain System: Cycle II, Balingian Province, Offshore Sarawak
More LessThe Balingian Province of northwest Borneo contains a wide range of hydrocarbon-bearing reservoirs, with production dominantly from Early Miocene coastal to lower coastal plain sand bodies. Previous studies have interpreted these deposits as being part of a fluvial-dominated coastal system (Almond et al., 1990). However, this study highlights the widespread occurrence of tidal indicators in the Balingian Province, suggesting a more strongly tide-influenced coastal regime. The occurrence of marine-influenced
organic-rich sediments, in particular mangrove-derived coal deposits (Wan Hasiah, 2003), also supports the tide-influenced coastal regime for the Balingian Province.
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Growing Evidence of Active Deformation in the Malay Basin Region
By H.D. TjiaVery young crustal movements in the Malay basin region point to the possibility of reactivation of regional faults in the basin that may compromise their sealing integrity. In addition, active or reactivated faults that are rooted in the pre-Tertiary basement and reach up close to the base of Quaternary seabed sediments of the basin pose obvious hazards to offshore installations.
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Climate Stratigraphy – A New Approach in Near-Synchronous Subsurface Correlation
By S. Djin NioAs oil and gas E&P is moving towards more mature phases, innovative new approaches are needed in petroleum geology. To find additional reserves in mature exploration areas and to improve production in existing fields, a better understanding of the spatial distribution and time-stratigraphic framework of the potential reservoirs and seals is needed. To meet these challenges, existing conventional stratigraphic methods have been improved and new stratigraphic concepts have been developed during the last decade. Amongst one of the most important concepts which have been proposed by the Exxon school a decade ago was sequence stratigraphy. Nowadays, sequence stratigraphy is widely applied in subsurface correlations and is becoming a routine practice. Sequence stratigraphy can best be seen as the delineation and correlation of changes in depositional trends that are generated during a base level cycle (see Embry, 2002). Despite the constant modification and improvement of the sequence stratigraphic concept, it did not reach an important objective – the construction of a near- synchronous stratigraphic correlation framework. One of the main reasons is the strongly model-driven approach of sequence stratigraphy which is preventing to construct an objective and reproducible correlation framework.
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Carbon Dioxide (CO2) Distribution in the Sarawak Basin, and Its Relationship with Entrapment
Authors Mansor Ahmad and Mohd Irwani SadiCarbon dioxide content in both associated and non-associated gases in Sarawak Basin fields varies up to a maximum of 90%. High CO2 content in natural gas reduces the economic value by lowering the saleable gas volume, as well as reducing the BTU content. In addition, special infrastructures are required to develop and process gas accumulations containing high CO2. Understanding the likely geological parameters that control CO2 regional distribution patterns will assist explorationist in targeting prospects with a lower CO2 content. General current understanding on the CO2 distribution in a basin are, CO2 percentage increases with depth and high percentage CO2 accumulation are of inorganic origin and tend to be associated with structures with deep seated faults to facilitate CO2 migration up dip from basement. However, we observe that CO2 percentage varies vertically in a field and does not necessarily increases with depth and could also decreases with depth. CO2 of same inorganic origin are present in several reservoirs of a field; and yet one reservoir may have very low CO2 compared to the other reservoirs. Field observations in the Sarawak Basin CO2 distribution are: 1) Depth of accumulation and origin of CO2 does not influence the percentage distribution.
2) Geometry of traps and seal effectiveness dictates how much CO2 the reservoir can hold. These scenarios are also observed in Sarawak Basin. Major marine transgressive shale provides good and effective top seal. Thus reefal carbonate terminated by drowning can support higher gas column with low CO2 content.
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Geomechanical Considerations Regarding EOR Efficiency and CO2 Sequestration
Authors David Castillo and David Bowling and Sunil NathAn accurate geomechanical assessment of the subsurface is vitally important when designing, executing and monitoring Enhanced Oil Recovery and CO2 Sequestration Operations. Detailed knowledge of the earth’s current stresses and pressures active in the reservoir (and overburden) provides valuable information for understanding how the reservoir (and overburden) will respond to injecting gases or fluids into reservoir rocks. The stresses operating in the area play an important role in inducing, preventing and controlling hydraulic fracturing (depending on the application). Controlling and containing hydraulic fractures is important for ensuring that the injected gases or fluids are contained within the reservoir during EOR operations. However, in some highly faulted environments, hydraulic fractures have been known to reactivate natural fractures or a faults which has resulted in fluids migrating away from the intended reservoir and minimizing production efficiencies. A case study will be presented in which primary production-induced stress changes were not considered when designing and executing EOR operations which significantly reduced the production performance. Efficient CO2 capture and containment will likely produce for our global societies important
environmental dividends. Geologic concerns include the selection of a suitable reservoir, the preservation of an impermeable top seal and prevention of fault and/or natural fracture reactivation that could breach the CO2 reservoir and cause unplanned leakage. Using a well-constrained geomechanical model it is possible to design a CO2 sequestration program that maximizes the long-term containment of CO2. Presented is a systematic workflow for analyzing in situ data to constrain the geomechanical model and use it to optimize CO2 containment in the context of cap rock integrity, fault leakage integrity and natural fracture stability.
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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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The Application of CSEM (Controlled Source Electromagnetic) Technology as a Tool to Complement 3D Seismic Interpretation and Avo Analysis in a Deepwater Prospect: A Case Study on Prospect B, Block 2F, Offshore Sarawak
By Wong Eng YaoThe Controlled Source Electromagnetic (CSEM) method has emerged into the oil and gas exploration industry, especially in deepwater exploration, and provides geoscientists another tool to assess a prospect by looking at another physical property, i.e. resistivity, besides acoustic properties that can be derived from seismic and AVO analysis. In this context, CSEM technology is no doubt a tool to complement seismic interpretation and AVO analysis by offering an independent data set to exploration work. However, as the technology is purely based on resistivity contrast down-earth, there is still room for debate as to whether or not the technology is capable enough to help in delineating the true geology of an area. This paper presents the result of a 2D CSEM survey over Prospect B of Block 2F, Rajang Delta, offshore Sarawak. The 3D seismic of the prospect shows a high amplitude anomaly at both crest and flanks of the structure (Figure 1); while AVO analysis over the crest of the structure gives a Class III AVO response which hints at an existence of a gas cap (Figure 2). The CSEM response displays a positive magnitude buildup which indicates a resistive body lying beneath (Figure 3). The question left here is the geological model that would explain all the responses obtained whilst honoring the geological (stratigraphic) information from wells drilled in the area before; Whether what lies beneath is truly a sizeable and quality gas reservoir, or, considering the limited resolution of seismic and stacking response of CSEM technology, just thinly-bedded siltstones that wouldn’t bring much excitement. A discussion will be presented in this paper based on the Depth Migration result of CSEM method.
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Recent CSEM Learnings in Deepwater Borneo
Authors Matthew Choo, Chester Young, Ling Chin Tiong and James Beer and Peter ShinerControlled Source Electromagnetic (CSEM) is an emerging technology with the potential to provide detailed resistivity images of the subsurface. In the context of exploration in DW Borneo, given the potential to directly image the high-resistivity zones associated with hydrocarbon pay, the technology was regarded as the ideal tool to reduce one of the most significant exploration risks in the basin – seal failure. A number of significant early successes over DW Borneo’s toe-thrust anticline plays confirmed the potential promise of the technology as an exploration tool in the basin. Following on this string of successes, CSEM data was acquired over a number of similar structures in 2006. Application of industry-standard processing and interpretive techniques on the data revealed an encouraging CSEM anomaly. However, proprietary inversion techniques indicated the possible presence of a shallow surface resistive body, while hinting at the presence of slightly elevated resistivities at depth. An exploration well campaign was carried out over the prospect late in 2006, but rather than encountering the expected hydrocarbon pay, the well encountered a near surface and resistive hydrate layer. Good quality but waterbearing reservoir was encountered at the target depth. This disappointment was the first CSEM negative test in the basin and highlights the need for further development of processing and interpretation methodologies. This paper will present the key CSEM experiences in DW Borneo to date, highlighting on the pros and cons of a still promising and evolving technology in what is still a challenging area.
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CSEM Pilot Survey in Southeast Asia: Challenges and Takeaways
Controlled Source Electro-Magnetic (CSEM) surveys have proved to be useful in de-risking the hydrocarbon prospects in the deep water environment, due to their capability to distinguish between the brine and hydrocarbon saturated reservoirs. However, the interpretation of CSEM response in marginal water depths and complex geological setups remains challenging due to the interference of airwave with electromagnetic field and the background resistivity variations. In the year 2006, PETRONAS conducted a pilot CSEM survey in one of its offshore block in Southeast Asia. The survey was aimed to understand the key risks of the two hydrocarbon prospects identified in the area and to evaluate the strengths and limitations of the CSEM technique for its future application in shallow water depths and complex geological setups.
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Channel Chasing in Malay Basin Using Mega Merged Data
More LessIn 2005, the Basin Studies Group of PRAM, PMU merged 29 3D dataset of the South Eastern part of the Malay Basin. The 3D dataset for the merging ranges from vintage data of 1995 to 2004 covering an areas of approximately of 20,000 sq km with a volume of 1.7 Terra byte of data (Figure 1). The Regional Study of the Malay Basin was carried out by utilizing the 3D Mega Merged Seismic data. With the huge volume of data involved, new technology of hardware and software was applied to handle the data. 3D volume interpretation software and a high end machine (i.e. 128G Machine) is required to do structural and horizons interpretation for the purpose of evaluating any new leads and prospects available in the entire South eastern part of the Malay Basin. By leveraging and integrating the rich information content of geophysical and geological data of the Malay Basin, near field opportunities of new play type and leads/ prospects will be able to be identified/emerged from the study. Malay Basin is a mature basin in terms of exploration activities in Malaysia and one of the objective of the Mega merge project is to carry out a seismic modeling on regional scale to define regions of common response i.e. channel, point bar. Total of ten (10) horizons tops (D, E, F, H, I, J, K, L, M & Basement) and almost 400 faults were interpreted on the mega merge seismic cube. Forty (40) control wells were also used as formation tops for calibration. Fifteen (15) Regional 2D RC lines were also incorporated in the study for areas where no overlapping of the 3D seismic. Extensive attribute works i.e. Spectral Decomposition, Sweetness, Amplitude Extraction, Reflection Strength has been carried out to identify potential stratigraphic leads and prospect and possible fracture basement. Multiple and stack channels trending from different levels can be observed from the attributes work generated. Most of the channels identified are from Group E, F, I and H of the Lower to Middle Miocene trending NE – SW direction (Figure 2 & Figure 3). Majority of channels presents are observed in Block PM 309 and PM 312 and others are seen in most of the PM Blocks
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Innovative Frontier Exploration Using Seismic and SeaSeep Data, Indonesia: Implications for Malaysia
More LessMost of the world’s oil was discovered using onshore surface maps and seeps. Within the past few years, technologies developed for conventional marine hydrographic surveys and anti-submarine warfare have been upgraded, modified, and integrated for offshore petroleum exploration and in particular, deepwater (400– 3,500m) exploration. Very high resolution maps of the sea bottom and zones of oil and gas seepage may be identified using a vessel traveling at 10 knots and surveying a swath of about 4 km. Similar advances in subsea positioning enable accurately-navigated piston-core to sample features we identified on sea-bottom map. These cores can be subjected to modern geochemical analysis and therefore locations of thermogenic hydrocarbon charge may
be identified. In December 2006, TGS-NOPEC commenced the world’s largest multibeam and the world’s first non-exclusive SeaSeepTM survey as part of an innovative exploration program in the offshore frontier basins of Indonesia. The program was underwritten by Black Gold Energy and co-sponsored by Joint Study partner MIGAS.
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Time-Lapse Seismic Modelling in Malay Basin
More LessTime-Lapse seismic has become as an important petroleum reservoir monitoring and management tools since its successful application in 1990s. The fundamental principle underlying the time-lapse seismic is simple, that is, the changes in reservoir parameters or properties are directly related to the differences in seismic response between the monitor and the base surveys. In reality however, the application is not that simple. There are many issues needed to be understood and considered before concluding any differences observed are due to changes in reservoir properties and not due to other factors such as seismic acquisition parameters and seismic processing artifacts. Feasibility study prior to a full time-lapse seismic project is crucial in providing information that helps guide our expectations. Changes in fluid type and saturation may not necessarily be significant enough to induce a large impedance contrast and consequently detected by seismic signal. The reservoir pore-fluids, rock matrix and frame, and reservoir conditions need to be fully understood to ensure the success of any timelapse seismic study. There are many aspects of a time-lapse feasibility study that need to be considered such as seismic acquisition design, processing algorithm and parameters, reservoir production, reservoir fluid properties, reservoir rock properties, reservoir monitoring program, geomechanics, seismic modeling, etc. This paper will focus on the fluid properties and seismic modeling aspects of the feasibility which is thought able to give, if even not full, a sufficient understanding on how pore-fluid type and saturations in the reservoir with varying types and thicknesses of cap rock could affect the resultant seismic amplitude, the fundamental element of any time-lapse seismic study.
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Fit for Purpose Time Lapse Seismic at F6
Authors Elvis Chung and Paul HagueF6 is Shell’s largest gas field in the offshore Sarawak, with a GIIP (Gas Initially In-Place) of around 7Tcf (Trillion Cubic Feet). Production commenced in 1987 from a single platform located above the central pinnacle of the carbonate build-up. By 2006, 4Tcf had been produced, but scope for redevelopment still remains in the form of further drilling and late life compression. However, the biggest uncertainty is the strength of the aquifer and the movement of the GWC (Gas Water Contact). Pulsed neutron logging indicates a GWC rise near the main producing area beneath the platform but a large uncertainty remains towards the flanks. The first 3D seismic survey over F6 was acquired in 2002 (15 years after production start-up), which means there is no suitable pre-production 3D baseline survey. Prior to commitment to the project, a feasibility study was carried out within SSB (Sarawak Shell Berhad) using the 2002 dataset as the 3D baseline. The objectives were primarily, to determine if production-related sweep signals are observable on seismic and if so, when is the ideal time to carry out the monitor survey in order to impact business decisions. The feasibility studies showed that a time-lapse seismic response could be expected in 2006 but highlighted that the timelapse
signals on the flank may be weak to image. This is largely driven by the two different reservoir model inputs in the feasibility study, which could be a uniform rise of the GWC or cone-shape rise of the GWC. Both models also have significant impact on recoverable gas on the flanks as illustrated as in Figure 1. Finally, the changes in the velocity and impedance from both models were found to be small (<5%) and thus, requires good repeatability and good signal-to-noise ratio (S/N) seismic data in order to observe time-lapse signals. Considering the possibilities from the study and the business impact of additional recoverable volume at the flank, the time-lapse seismic was a timely exercise to help understand the extent of water influx and derisk future investment on the field.
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Large-Scale Pore Pressure Prediction after Pre-Stack Depth Migration in The Caspian Sea
More LessDespite all the difficulties, it seems that a successful attempt has been made in predicting the pressures in this difficult area. The main challenges are (1) the pressure compartmentalisation, (2) non pressure related influences on resistivity logs, (3) variable pressures, (4) sands and shales often not in pressure equilibrium and (5) an extremely difficult velocity and imaging environment. It is still required to undertake real time prediction of pore pressures while drilling. The current volumes can be used as a reference. Due to the challenges listed and the seismic limitations, there will always be an associated uncertainty and error with respect to the pressure predictions. But the best attempt has been made, and the PSDM has increased the accuracy and reliability of the velocity model. The pressure model used can be updated when new well data becomes available. Of vital importance and value is the combination of well mechanical and operational knowledge and seismic processing expertise.
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Reservoir Characterization and Monitoring Using Multi-Transient Electromagnetic (MTEM)
More LessThe Multi-Transient Electro-Magnetic (MTEM) method implements a current bi-pole source with a sequence of receiver stations that measure the resulting voltage. Source and receiver stations are located in a straight line similar to 2-D seismic. Onshore and offshore acquisition systems have been developed providing continuous coverage of the subsurface including the transition zone. The earth’s impulse response is obtained for each source receiver pair by deconvolving the received voltage for the input current. The source signal is a Pseudo Random Binary Series (PRBS) that combined with vertical stacking allows us to maximize S/N. The subsurface resistivity is evaluated from the very shallow sediments down to the target depth by continuously optimizing the acquisition parameters. This involves adjusting the length of the source bi-pole, the bandwidth of the source PRBS, and the sampling rate of the recorded signal to be optimal for each offset range. The method allows for real time monitoring of the signal and real time assessment of the subsurface resistivity. The final deliverables are 2-D depth sections inverted to resistivity along 2-D profiles.
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Oil and Gas Outlook: Acquiring a Clear Image of the Future
By Hovey CoxThe oil and gas industry, over its history, has seen times of great strength and long periods of weakness. It has also demonstrated a propensity for proving wrong those who try to predict its cycles and peaks. Over recent history we have experienced one of the greatest, if not the greatest, period of long-term economic growth worldwide. This expansion was literally powered by the relatively clean and inexpensive energy that fossil fuels, oil and gas in particular, provide. Over the past ten years, as economic development strengthened and energy consumption continued to climb, especially in the World’s emerging economies, several underlying factors in the energy landscape have started to challenge the oil and gas industry’s historic models. To meet the growing need for energy, E&P budgets increased across the industry focused primarily on production technology to optimize recovery from known assets. This reduced the risks associated with quarterly returns in the capital markets worldwide and at the same time increased depletion rates. When combined with flat-lining exploration spending and the resulting decrease in discovery rates, it also dramatically reduced spare capacity. Together these trends arguably, at least at the current time, moved the oil and gas marketplace from a supply-side to a demand-side driven market. Changes are needed. When the trends outlined above are compounded with: the growing geological and geopolitical complexities in our business, the rising concern worldwide over increasing energy costs and the industry’s environmental impact, it provides a clear opportunity to examine our current business as our historic models may not work as well in the future as the did in the past. We today, as an industry, sit at a unique place in history that suggests a review of possible directions and decisions. This presentation explores the current state of the industry along with its fundamental drivers to uncover the key challenges companies face today to successfully produce results tomorrow.
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Petroleum Geomechanics: From the Plate-Scale to the Reservoir-Scale
More LessThe last 10-15 years have seen an explosion in the application of present-day stress data to petroleum exploration and development-related issues. Borehole breakouts, zones of wellbore where the cross-sectional shape is enlarged and elliptical, were first-named and recognised as being due to present-day stresses in the late 1970s (Figure 1). However, even by the early 1990s, few in the oil industry were familiar with borehole breakouts. Now they are used routinely, along with other present-day stress data, to
○ evaluate fault reactivation and reservoir seals; ○ evaluate naturally fractured reservoirs; ○ assess wellbore stability, and; ○ plan fracture stimulation and water flooding operations. This talk will illustrate how the reservoir geomechanical model (present-day stress and strength data) is determined using logging and drilling data. It will discuss the plate-scale, regional and local tectonic controls on present-day stress with examples from Brunei and the North Sea. Finally it will illustrate the application of the geomechanical model to exploration and development, with examples from Brunei and the North Sea.
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Organic Facies Variation in Lacustrine Source Rocks in the Southern Malay Basin
Authors Abdul Jalil Muhamad and Awang Sapawi Awang JamilThis paper attempts to look at, in more detail, the source rock quality of the lacustrine shales within the Groups K, L and M in the southern flank of the Malay Basin. This study is made possible through the use of state-of-the-art linked-scan gas chromatography / mass spectrometry / mass spectrometry or GCMSMS to provide highly sensitive measurements of biomarkers which are typically in low concentrations in source rock extracts and oils, and especially so in condensates. Since only one well dataset is available, only the vertical variation in the source rock quality of the lacustrine shales is discussed. Stratigraphically, there is a noticeable change in the source rock quality within the three groups. In general, the TOC content of the lacustrine shale
sequences in Groups K, L and M range from 0.35 to 2.00 wt% (Fig. 1). Kerogen composition of these shales varies, showing mixtures of Type II and Type III indicating variable contributions from algal, bacterial and higher plant organic matter deposited in a highly to less oxidising environment (Fig. 2). This is indicated by hydrogen index (HI) values ranging from 137 to 403. Group L lacustrine shales seem to provide the best oilprone source rock with TOC values of 0.45 to 1.95 wt% and HI values in the range of 300 to 400 indicating predominantly Type II kerogens (Fig. 2).
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Lacustrine Oil Families in the Malay Basin
Authors Abdul Jalil Muhamad and Awang Sapawi Awang JamilThe oils and condensates of the Malay Basin are being generated by two main source rocks - lacustrine and fluvial-deltaic, with varying degrees of mixing between them. In addition, a recent study on the petroleum systems in the northern part of the Malay Basin has also shown that fluvial-marine source rocks could also generate these oils. The focus of this paper is on the lacustrine oils i.e. with respect to their biomarker characteristics and the possibility of grouping them into different oil families. The area of study is the Anding and adjacent fields located in the southern Malay Basin.
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Distal Turbidites of the Semantan Formation (Middle-Upper Triassic) in the Central Pahang, Peninsular Malaysia
More LessThe Semantan Formation has been interpreted as deep-marine deposits based on sedimentological and palaeontological studies (e.g. Metcalfe et al. 1982; Metcalfe & Azhar Haji Hussin, 1994; Mohd Shafeea Leman & Masatoshi Sone 2001). Convergence between the Eastmal/Indosinia and Sibumasu blocks during the late Triassic resulted in closure of the Paleo-Tethys Ocean (Hutchison, 1989). Remnants of this ocean are represented by the deep-marine deposits of the Semantan Formation (Middle to Upper Triassic) in the Central Belt of Peninsular Malaysia. Some outcrops of the Semantan Formation at SK Sri Tualang and Taman Mutiara, near Temerloh and along the Karak-Kuantan highway, were studied to gain a better understanding of the deep-marine sedimentary facies and sedimentation processes in the distal parts of submarine fans and basin plain environments (Figure 1).
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Turbidite, Debrite or Something in Between: Re-Thinking the West Crocker Formation
Authors Ku Rafidah Ku Shafie and Mazlan MadonThe Oligo-Miocene West Crocker Formation (WCF) of West Sabah is often referred to as a sand-rich turbidite system, and has been the subject of detailed sedimentological studies during the last few years. The essential features of the WCF sediments can be observed at outcrops scattered within driving distance from Kota Kinabalu (Fig. 1). For the most part, thickly bedded facies, representing the high-density, sandy turbidites is found in most of the outcrops studied, with the exception of Taman Maju, Sepangar (Fig. 1), where there are more of the “classical” flysch-like, thin-bedded turbidites. In general, the Crocker is sand-rich and very thickly bedded (> 1 m), commonly 1.5-3 m thick, while some may be up to 35 m. Based on the presence of subtle scour and
amalgamation surfaces, these thick beds were formed not by a single flow but multiple flow events. Internally, the thick beds, most of which are poorly sorted despite the overall normal grading, are characterized by faint low-angle laminations, resulting from traction, passing upwards into contorted bedding due either to deposition from a slurry, or to soft-sediment deformation and dewatering. Deposition from slurry involves rapid dumping of a dense muddy and water-saturated mass of sediment. Hence, in these types of beds at least, there is strong evidence for some form of high-density (sandy) turbidity flows, slurry, or both. Erosion at base of the flows, indicated by flute casts and various other sole marks are common. Well-developed load structures, including large ball-and-pillow (or “jam roll”) structure due to loading and sinking of these dense flows into water-saturated muddy substrate are indicative of the scale and dynamics of these flows.
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The Geographic and Stratigraphic Distribution of Cored-Sections in the Malay Basin
More LessThis paper shows the geographic and stratigraphic distribution of cored-sections based on the inventory of data from over two hundred wells (Chart 1, 2). These charts provide a quick assessment of the depth of well penetration and length of cored-section, stratigraphic tops, gross lithology and core availability within each stratigraphic unit.
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Temana: Old Field, New Ideas and New Insights
Temana Field is located approximately 30km offshore from Bintulu in water depth of about 90 feet and was discovered in 1962 by exploration well TE-1. Development commenced following commercial volume confirmation by appraisal wells TE-9 and TE-10 in 1972. The field is divided into three areas; Temana West, Central and East. For more than 35 years, the development concept in Temana has been driven by the presence of structural plays. Well locations being placed mostly in the crest of anticlines. Even though there was a belief that a stratigraphic component was involved in the trapping mechanism, the bold move to test this concept was deferred until recently. Approximately 90% of the field’s production is from the H and I series which are characterized by
Miocene aged fluvial sands. The I60/I65 series in particular are said to have been deposited in a lower coastal plain environment with tidal influence. Developing the Temana fields entails several challenges, mostly due to the field’s rather intricate structure, consisting of over 80 structurally and stratigraphically isolated reservoir compartments. Furthermore, the channelised I60/I65 sands results in several pinch-outs, limiting the sand distribution across the field and resulting in relatively thin reservoirs. A new appraisal well TE-72 was drilled in 2004 in the Temana Saddle area to test the seismic anomaly on a plunging anticline for the presence of a combination stratigraphic and structural play. This appraisal well was motivated by encouraging results from wells TE-54ST1 and TE-71 for the I60 reservoir, in which a similar amplitude anomaly response was proven as oil bearing (Figure 1). Although the amplitude anomaly was not conformable with the structure at TE-72 well location, the well penetrated 58ft of thick
blocky I65 sands, confirmed as hydrocarbon bearing. The sand is observed to be shaled-out in the up-dip offset wells (Figure 2). This pinching-out of the I65 sands towards the northeastern direction gives the reservoir the stratigraphic play needed to act as a trapping mechanism for the hydrocarbon accumulation. Following the success of TE-72, several geological and geophysical studies were undertaken including a fluid substitution study and a reservoir characterization study on acoustics impedance inversion
volumes (Figure 3 & 4). This led to the drilling of three development wells (TE-73ST1, TE-74ST2 and TE- 51ST2) in the Temana Saddle area in 2006/07 to delineate fluid contacts and provide drainage points for I65 reservoir. The success of the drilling campaign is reflected in the production figure whereby production from a single well could reach as high as 3600 bopd. The producing wells confirmed the geological model and further established the integrity of the trapping mechanism. The accomplishment of the Temana Drilling campaign triggered more interest to further dissect the field. Existing seismic cube was reprocessed and subsequently an AVO study was embarked to further delineate the hydrocarbon bearing sands. The discovery from the appraisal well and the success of the recent development campaign inspire a new paradigm in exploring the Temana Field and opening a new chapter of stratigraphic and structural play concept, hence giving a new direction of exploration towards the flank of the structure.
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Condensed Section Intervals within the Cycle II (Early Miocene) of the D35 Field, Balingian Province, Offshore Sarawak: Occurrence and Significance
More LessA marine condensed section is a thin stratigraphic interval characterized by very slow depositional rates (<1-10 mm/yr). The interval often comprises fine-grained sedimentary rocks characterized by the presence of highly radioactive and organic rich shales, glauconite, chemical sediments and hardgrounds/firmgrounds. The interval may be thoroughly bioturbated, variably fossiliferous and locally show concretionary cement. Condensed sections reflect particularly slow accumulation rates and thereby representing a significant pan of time within only a thin layer. Condensed sections commonly develop during transgressions, in such cases they may be connected with "maximum flooding surfaces" and form important sequence stratigraphic markers.
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Using Gravity Data to Help Identify and Differentiate Mobile Shale Bodies, Offshore Sabah
Authors S. J. Campbell and M. Lennane and S.E. PisapiaThe reliable identification and definition of shale diapirs is important to reduce exploration risk. This poster describes the work carried out to establish the degree to which these shale bodies can be identified using high resolution gravity data from offshore Sabah. Test models show that, assuming reasonable density contrasts, mobile shale bodies of a typical size and geometry would give a 2-3 mGal amplitude and 7 to 9 km wavelength gravity low response. Therefore they should be resolvable with good, high resolution gravity data. The picture, however, is complicated in this area by the presence of numerous large bathymetric canyons. The larger of these are shown to yield a similar gravity response as the possible shale diapir bodies, although the gravity effect of these bathymetric canyons can be diminished to some degree by the use of the Bouguer gravity anomaly. The mobile shale bodies manifest themselves on seismic data as disturbed zones, often with a distinct high impedance contrast on the top. These have been identified on several seismic sections and usually correspond directly with observed 1 to 2 mGal low anomalies in the Bouguer gravity profiles, which can be further highlighted by the use of careful filtering. This gravity response is observed irrespective of whether there is interference from the bathymetric canyons or not. Given that this characteristic gravity response is observed in several places, disturbed areas in the seismic where there is uncertainty can be verified by looking at the Bouguer anomaly profile. The poster shows that such an uncertain zone with this characteristic gravity response is confirmed as a shale diapir by viewing the cross-line trace. For disturbed areas on the seismic data that don’t correspond to this same gravity response, alternative explanations might be sought such as the existence of a gas chimney.
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Detection of 3D Distribution of Reservoir Sand Bodies by ANN– A Case Study in the North Malay Basin (1)–
More LessDetection of reservoir distribution in 3D is one of the most important tasks for petroleum exploration in the Malay Basin and Gulf of Thailand, where highly stratified thin sand reservoirs are distributed complicatedly. Geology Driven Integration (GDI)*1 is one of the most effective techniques utilized to analyze the seismic pattern and to predict reservoir distribution and lithologic change directly from seismic attributes applying Artificial Neural Network (ANN) method. This paper presents the case study in the North Malay
Basin which was carried out by JGI and CPOC in 2007.
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3D Basin Simulation Controlled by Capillary Threshold Pressure – A Case Study in the North Malay Basin (2)–
More LessThe relationship between capillary threshold pressure of seal formations and buoyancy of hydrocarbons is considered as one of the most important aspects for petroleum exploration (Sales, 1997; Nakayama and Sato, 2002). As high quality 3D seismic data is acquired in common, high resolution 3D basin simulation of capillary-dominated, multi-phase flow regimes is the effective technique to realize the generation, migration and accumulation of hydrocarbons in basin scale. This paper presents the case study of
3D basin simulation in the North Malay Basin which was carried out by JGI and CPOC in 2007.
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Two-Dimensional Stratigraphic Simulation of the Malay Basin
More LessStratigraphic simulation is a computer modelling technique that can be applied in petroleum exploration to understand the depositional geometries and architecture of a sedimentary basin. By making geologically reasonable assumptions about certain process parameters (e.g. sediment supply and tectonic subsidence rates), realistic stratigraphic geometries and attributes of sedimentary basins can be replicated by forward modelling. There are a number of proprietary and a few commercially available stratigraphic
simulation packages designed for this task; ranging from simple 1D to more sophisticated 3D techniques (Ku Rafidah & Mazlan Madon, 2007). In this study we have used SEDPAK™, a 2D modelling package developed by the Stratigraphic Modelling Group at the University of South Carolina (Kendall et al., 1991), to simulate the stratigraphic evolution of the Malay Basin, offshore Peninsular Malaysia. The objective of the study is to investigate the relative influence of the main factors that controlled sedimentation in the basin. In a previous study of overpressure development in the basin (Madon, 2007), subsidence and sedimentation (burial) rates were found to be the main controlling factors in overpressure development. In this study, SEDPAK™ was used to reconstruct a depositional history of the basin by varying the rates of tectonic subsidence, sediment supply and eustatic sea-level change. We have used an interpreted seismic section across the basin as a starting model (Figure 1) and, upon applying a time-depth conversion, constructed a geologic cross-section to be simulated. Based on the published geologic ages of the seismic horizons and the measured thicknesses of the stratigraphic units, their average sediment accumulation rates were derived along the profile as input to the simulation. Figure 2 shows the three main input parameters. The input value for the modelling parameters is varied by trial-and-error iteration until there was agreement between the model result and the observed geometries in the seismic depth-section.
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Advanced Mud Gas Logging Technology: Application for Fluid Identification and Characterisation, Offshore Sarawak, Malaysia
Authors Patrick Gou and Sven ScholtenConventional mud gas data has been available for a long time from mudlogging operations. For several reasons, it has been under-utilised for fluid characterisation, although still acquired routinely in the drilling of oil and gas wells. However, the introduction of some advanced mud gas logging methods like FLAIR (Fluid Logging and Analysis in Real-Time) by Geoservices have made near real-time geochemical analysis of mud gas data possible. Advanced mud gas logging is also referred as Gas While Drilling (GWD)
in some literature. This article will describe how such mud gas data are utilised to identify and characterise different fluid types encountered by wells drilled in Shell operations. Two wells drilled offshore Sarawak in 2006-2007 are presented as examples (see Figure 1). The first example is an appraisal well while the second is a development well. The appraisal well was drilled to appraise the stacked sand reservoirs of Late Miocene age within the Baram Delta Province while the development well was drilled to produce gas from a sour (high H2S and CO2) carbonate reservoir in the eastern part of Central Luconia Province.
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Developing Remaining Oil in K1.1 Sand Reservoir with Horizontal Well in Baram Field, Sarawak Basin
Baram field is located in Miri Sarawak Basin, East Malaysia. (Figure1).The field was discovered in 1963 and brought into production in 1969. In it’s nearly 40 year production period, optimal well placement is critical for drainage of the remaining reserves. The field was developed with 8 drilling platform, three surface facilities, and two compressor platforms. STOIIP was estimated at 1400 MMSTB with a EUR of 390 MMSTB from more than 170 wells. Some of the remaining reserves are left behind in the oil column <60 ft, reservoir thickness <20 ft, and dipping angle >4deg which was economically unattractive to be developed. This study is mainly focused on how to maximize oil recovery with respect to horizontal well in thin reservoir by using azimuthal geosteering technology. (Figure 2)
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Using Acoustic Impedance Data for Tabu Field Subsurface Mapping and Reservoir Characterization
More LessThe Tabu oil and gas field, located in the southeast part of the Malay basin, was discovered in 1978 by Esso Production Malaysia Inc with the drilling of the Tabu-1 well. Oil production commenced in 1986 and is currently producing from Tabu-A and Tabu-B platforms. A field study was conducted from 2004-2006 utilizing a recently acquired 3D seismic survey to exploit the non-associated gas (NAG) and gas-cap blowdown (GCBD) resource at Tabu. Accurate reservoir characterization is required for a successful development. For Tabu field, seismic inversion was carried out with the objective of improving reservoir characterization. Acoustic impedance inversion is a process of generating an acoustic impedance volume from the seismic reflection data. It has several advantages over a seismic reflectivity volume. The acoustic impedance data has improved resolution due to the contribution of very low frequencies from the well log data. Representing the subsurface as layers instead of layer interfaces by removing the complexity caused by the seismic wavelet, results in an improved link to the petrophysical properties of the subsurface formations. Seismic inversion was carried out using the JASON Constrained Sparse Spike inversion (CSSI) algorithm. High quality well ties are important for determining the low frequency acoustic impedance trend, seismic wavelet extraction, and inversion of the seismic trace. Careful selection of CSSI parameters and the merge point between the low-frequency model and the inverted band-limited acoustic impedance are required for a successful inversion. The results of the acoustic impedance volume have had a significant impact on the interpretation of the Tabu Lower "J" reservoirs, one of the key gas reservoirs. Improved reservoir characterization, including geometry and reservoir properties has resulted. Based on the results of the interpretation a seven well development of the reservoir was initiated. Initial drilling has confirmed the validity of the interpretation model.
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Borehole Images and VSPs as Aid to Attribute and Inversion Analysis
More LessBorehole images have inherent information on sedimentary structure and lithofacies that are typically used qualitatively. There are ways of unlocking this potential by doing a comprehensive facies analysis and obtaining quantitative outputs with new applications like neural network or multivariate histogram techniques. However even with these approaches the high-resolution quantitative facies data is still only at the borehole, capturing near-wellbore characteristics which are difficult to translate and propagate into the interwell space. Needed at this critical barrier, is a tool to tie-in high-resolution borehole image and log derived facies with something that will also have a correlation with attributes that characterize the interwell and 3D-space. We test rock-physics attributes like acoustic impedance and Poisson’s-ratio and attributes generated from vertical seismic profiles (VSP) as being the likely links between high-resolution near-borehole information and interwell/3D space represented by seismic data.
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Ichnofossils from the Tertiary Sediments of the West Crocker Formation in Kota Kinabalu Area, Sabah
Authors Nizam A. Bakar and Abdul Hadi Abd Rahman and Mazlan MadonDetailed facies analysis on several well-exposed successions belonging to the West Crocker Formation reveals well-preserved trace fossils, which has not previously described. The ichnofossil assemblage in this area is associated with turbidite deposits, which indicates benthic or deep marine environments. They can be grouped into two different ichnofacies namely Zoophycos and Nereites.
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Facies Characteristics and Stratification of Debrites Within the West Crocker Formation (Early Oligocene to Middle Miocene), Kota Kinabalu, Sabah
Authors Nizam A. Bakar and Abdul Hadi Abd Rahman and Mazlan MadonThe West Crocker Formation in Sabah has always been referred to as sediments of turbidite systems. However, field observations have revealed the presence of thick sandstone bodies which display distinct facies characteristics such as very thick beds, poor sorting, lack of internal layering and sedimentary structures, randomly distributed mudclasts, loadcasted bases and irregular tops. These features reflect deposition by debris flow; hence, these deposits are debrites.
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Sedimentary Facies Characteristics and Reservoir Properties of Tertiary Sandstones in Sabah and Sarawak, East Malaysia
Authors Teoh Ying Jia and Abdul Hadi Abd RahmanSandstones are very important as reservoirs for oil and gas; more than 50% of the world’s petroleum reserve is estimated to occur in sandstones. Depositional environments, and thus facies characteristics, determine the overall reservoir properties of sandstones. The purpose of studying the reservoir sedimentological characteristics and petrophysical properties of Tertiary reservoir quality sandstones from Sabah and Sarawak is to investigate and determine the relationships between sedimentological and facies characteristics, and reservoir properties of the different types of sandstones.
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Anding Utara Fractured Basement Modeling an Integrated Workflow from Seismic-3D Static-Fracture Model
More LessThe Anding Utara Field located in PM 12 Block in production sub-block of Malong-Anding-Sotong within the Angsi-Duyong sub-basin of the South Malay Basin, offshore Peninsular Malaysia in area of water depth approximately 74 m with 4 wells drilled (Figure 1.0). The productive reservoir in Anding Utara Field is a fractured Jurassic Metamorphic Basement High within a pull-apart basin formed by extensional faulting during basin development. It is about 12 km long and 7 km wide. Correlation indicated that Anding Utara Jurassic Metamorphic Basement underlain by very thick Oligocene shale as a cap rock (Figure 2.0). The 3D fractured modeling was created using by collaborating well log, well tests, seismic attributes and outcrops analogs. The shared knowledge and flexible workflows have been conducted to get the best-fit model, manageable data and easier-way to be re-run. Dual Porosity and permeability modeling was generated for fracture and matrix properties (Figure 3.0). The fracture properties are divided into 2 major fracture sets; Distance to fault fracture set as representative for tectonic mechanic and bed contained fracture set as representative for stratigraphic mechanic (Figure 4.0). The matrix properties are developed in weathered basement. The matrix becomes the
major oil storage, while the open fracture becomes the oil flow conduit.
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Structural Style and Structural Evolution in the Hawke's Bay Region, New Zealand
More LessThis poster presents the analysis of regional 2D seismic lines across the Hawkes Bay region offshore east coast of the North Island of New Zealand. The study area is located in the outer forearc and contractional domain of the Hikurangi subduction complex. Detailed intrerpretation of long regional 2D seismic lines has indicated that the area underwent rifting in the Cretaceous, thermal sag and subsidence in the Paleogene, followed with contraction and thrusting in the early Miocene, extensional faulting in middle to late Miocene together with continued thrusting and inversion in the Pliocene to Present Day. Within the Neogene section three principal depositional sequences were identified representing growth strata deposited during different deformational phases - a syn-thrusting sequence, a syn-extensional sequence and a syn-inversional growth stratal sequence. Within the study area three tectono-sedimentary domains were identified based on the difference structural styles and sedimentary architectures. In the north the Raukumara Shelf is characterized by thrust fault-related folds, inverted extensional faults and gravitational sliding structures. In the central domain of Hawkes Bay itself, a series of Present Day active thrust faults occur associated with folds and inverted
extensional faults. The southern structural domain, the North Wairarapa Shelf, is characterized by thrust related folds and gravitational sliding structural elements. Fold amplification characteristics, overall shortening and thrust fault spacings indicate that the
shortening rates were relatively higher towards southwest of the study area. The extensional faulting in the Raukumara Shelf may indicate that subduction underplating and gravitational collapse of a supra-critical Coulomb wedge in this region.
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Controlled-Source Electromagnetic (Csem): Complementing AVO as Prospect Qualifier, Offshore Sabah, NW Borneo
Authors H. Maulana, S. Tanner and S. Algar and K. AzlanAmplitude versus Offset (AVO) analysis has been utilised to evaluate potentially hydrocarboninduced seismic amplitude variation with offset. One major uncertainty is that reservoirs with 10% gas saturation will have similar AVO responses to commercially saturated reservoirs (>60% hydrocarbon saturation). In frontier deepwater areas that lack of well control, an independent, non-seismic method like marine controlled-source electromagnetic (CSEM) survey becomes an important technique to assess the risk
of low saturation gas reservoirs. The CSEM measurement is sensitive to resistivity contrasts, it can potentially differentiate hydrocarbon saturated reservoirs (highly resistive) and the surrounding conductive sediments. Furthermore, it may also be able to discriminate reservoirs with commercial saturation (tens-thousands m resistivity) from those with residual saturation. Stochastic AVO modelling performed on Prospect X in Offshore Sabah, NW Borneo, indicates the presence of hydrocarbons as well as a chance of having low saturation gas. The CSEM interpretation on the Prospect X, however, reveals a 20-60% electric magnitude increase of the target response over a chosen background, which indicates a hydrocarbon-related resistive body. Further interpretation suggests that significantly thick sand with resistivity of 100 m is the most likely cause for the CSEM anomaly; hence, it derisks the possibility of low saturation gas being present in the prospect. The combined AVO-CSEM interpretation is a compelling prospect qualifier in the Sabah deepwater setting, where (1) drilling an expensive deepwater well is not justified based on amplitude anomaly alone, particularly when gas-charged siltstone and “fizz” gas reservoirs are common, (2) the absence of nonhydrocarbon highly resistive lithologies such as salts, volcanics, and thick limestones avoids misleading resistivity interpretations, (3) the water depth is sufficient to suppress the air-wave effect that might otherwise mask any potential highly resistive anomalies, and (4) the reservoir depth below seabed is suitable for this combined interpretation to be successful in finding commercially saturated hydrocarbon reservoirs.
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The Structural and Stratigraphic Evolution of Shale Detachment System in the Ceduna Basin, Australia
More LessThe Ceduna sub basin, part of the Bight basin, covers an area of 95,000 sq. km and is located at the southern margin of the Australian continent. The basin was formed by the Mid-Late Jurassic to Early Cretaceous separation of southern Australia from Antarctica. Four principal tectono-stratigraphic phase have been identified in the Ceduna Sub-Basin. Mid-Late Jurassic rifting was followed by two phases of post-rift thermal subsidence in the Cretaceous with southern margin breakup occurring in the Late Santonian. From the Late Cretaceous through the Cenozoic the passive margin phase was characterized by progradational sediment deposition from a major delta system – the Ceduna delta. Four episodes of thermal subsidence have been identified and these events are related to a massive sediment influx into the passive margin basin. Two major delta complexes have been identified. Rapid progradation of Turonian –Santonian and Campanian –Maastrictian deltas on the unconsolidated Albian deep marine shale have produced series of syn –depositional listric faults and shale detachment systems. Two episode of shale detachment systems have been recognized - a Mid Albian and a Late Santonian detachment systems. The Mid Albian event is more widespread than the late Santonian event which only dominated the outer margin of the delta. The Mid-Albian event produced a series of southward dipping listric fault systems which are associated with syn depositional growth sequences and contractional toe- thrust systems.
The Ceduna sub-basin shale detachment systems are characterized listric extensional growth faults and roll–over anticlines. Sediment depocentres are controlled by the syn–depositional fault structures with the initial sedimentation infilling the basin center followed by a shift to the outer delta margin after the basin center has been filled, together with reactivation of the fault along the delta margin. Sediment accumulation in the fault hanging-walls caused the propagation of growth faults, hanging wall rotation and the development of roll–over anticlines. Small scale roll-over anticlines dominate the western part of the study area and large scale anticlines dominate the middle sector of the basin.
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Integrated Fracture Evaluation af a Malaysian Basement Well Drilled with the Oil-Based Mud
Hydrocarbons discovered in the naturally fractured basement reservoir around the Malay basin are being explored for additional reserves for the Malaysian oil and gas industry. The fractured basement reservoirs are much more difficult and expensive to evaluate when compared to a conventional reservoir due to its challenging environment. Many new technology tools are target s for such reservoirs. However, the optimized formation evaluation program is required to obtain as much reservoir information to enable an
estimation of the most prospective hydrocarbon bearing intervals in this reservoir. This information is essential for field development decision in fractured basement reservoirs. This paper presents the challenges and results of the formation evaluation program in the fractured basement reservoir in Malaysia. This particular well example is a highly-deviated well drilled with oilbased mud (OBM) as it was believed that the borehole wall failures, formation damage and fracture damage which occurred in previous wells was due to being drilled with a water-based mud (WBM). Current image-based fracture evaluation techniques were developed for water-based mud systems. However, a comparatively limited fracture analysis can still be done with the Dual Oil-base MicroImager (OBMI2) in oil-based muds. There are inherent limitations that prevent interpreters from performing a full fracture analysis beyond fracture identification, orientation and fracture density quantification in OBMs. OBM makes differentiating between open and closed/healed fractures impossible as both appear as resistive events although one is filled with the OBM and the latter with resistive cement. This in turn prevents the calculation of fracture aperture and fracture porosity. This uncertainty can be fulfilled by combining the borehole image results with dual packer wireline formation tester (WFT), Sonic Scanner reflection imaging and Stoneley data. The borehole image was crucial in selecting testing zones for the dual packer WFT, and in turn the WFT results were especially helpful in determining whether fractures within a certain zone were open or healed (productive or not). Reservoir parameters and fluid sampling were obtained using the WFT. In addition, the combination of the borehole image and Stoneley was an important factor in reducing uncertainties. The Stoneley fracture analysis is intended to detect open fractures with significant fluid flow in/out of them. Also Borehole Acoustic Reflection Survey imaging delivers highresolution acoustic images around the wellbore to identify sub-seismic inter beds, faults or fractures far beyond the resolution obtained from any seismic surveys. Using a combination of data from all of these disciplines, the uncertainties of fracture analysis in OBM can be lessened and the resulting integrated solution giving significant value to the characterization of complex fractured reservoir.
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Trace Fossil or Soft Sediment Deformation? An Enigmatic Structure from the Balingian Cycle II Sequence, Offshore Sarawak
By David InceThe Early Miocene Cycle II interval in the D35 field contains the principal hydrocarbon bearing reservoirs. The majority of the Cycle II section however comprises a variety of mudstone facies and minor coal horizons. Recent analysis of the sedimentology and ichnology of these rocks has revealed a variety of distinctive trace fossil assemblages that reflect variations in salinity of the water column. As detailed in a parallel poster presentation the predominant facies is interpreted as having been deposited under brackish water conditions with somewhat restricted ichnofaunas reflecting this environmental stress. As well as the readily identified trace fossils that can be assigned to known Ichnogenera, there are structures of unknown origin that, to date, have not been recognized as trace fossils but are not satisfactorily explained by physical processes. The presentation describes these structures and presents the suggestions that have so far been advanced to explain their origin. A physical process involving loading of starved ripples has been put forward, however the viability of this process is unclear. An alternative interpretation is that the structure represents an organic trace reflecting an aspect of animal behaviour previously unrecognised in these sections. Evidence is
presented and the reader is encouraged to weigh and debate the options for interpretation.
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Trace Fossil Assemblages and Palaeoenvironmental Re-Evaluation \of Miocene Reservoir Intervals, Offshore Sarawak, Malaysia
Authors Kerrie L. Bann, David M. Ince and Abdul Hadi A. and Ahmad Munif B.This study integrates ichnology and sedimentology to re-define the palaeoenvironmenal and sequence stratigraphic interpretation of Miocene reservoir intervals in the D35 Field in Offshore Sarawak, Malaysia. The succession has been interpreted previously to reflect predominantly fluvial and lacustrine environments of deposition. Analysis of the trace fossil assemblages throughout the succession strongly suggests, however, that it is exceedingly difficult to reconcile the majority of these units with a fluvial and fresh water interpretation. Instead, the interval reflects a variety of lower coastal plain deposits, most of which were moderately to significantly affected by marine influence.
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Application of Walkaway VSP for Improved Seismic Imaging Beneath a Gas Cloud
More LessThe Vertical Seismic Profiling technique (VSP) has been widely used in oil and gas exploration in Malaysia over recent years. During 2007, a well was drilled to access the hydrocarbon prospect within a gas cloud area by Carigali and a walkaway VSP acquired over the area to delineate reservoirs underneath the gas cloud. VSP utilizes the advantage of placing the receivers in the ground that are close to the target reflectors and thus reduce seismic signal attenuation by half of that encountered by conventional surface seismic acquisition. The results show a much clearer image enabling the interpreter to define the top reservoirs which were not possible to track on the surface seismic. Based on these findings, the PCSB team decided to reevaluate the technical and economic impacts to the initial field development plan (FDP).
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Tectonic Evolution, Sedimentation and Chronostratigraphic Chart of Sabah, Malaysia
More LessA stratigraphic chart incorporating all the Tertiary tectonic evolution and sedimentation phases of the Sabah Basins (North Borneo) was constructed based on onshore and offshore exploration data. This chart reflects the most recent interpretations of Sabah stratigraphy and correlations of onshore and offshore areas of Sabah. It includes major lithostratigraphic units and biostratigraphic markers. The diverse structural trend and depositional framework of Sabah (North Borneo) were contributed by several regional tectonic events occurred since the early Tertiary. At least three major episodes were linked to NW-SE compressions coinciding with the ongoing subduction of the proto-South Chine Sea during the Late Eocene (Sarawak Orogeny), middle Early Miocene (22-20Ma, Sabah Orogeny-BMU) and early Middle Miocene (15.5Ma, MMU/DRU).
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A Comparison of Geochemical and Petrographic Features of Oil Prone Coals from the Balingian Province with those of the Malay Basin, Malaysia
Authors Peter Abolins and Wan Hasiah AbdullahThe role of coal as a source for oil continues to be debated in geochemical circles. This paper attempts to present the case for Malaysian Tertiary aged coals as a source rock for oil, as well as for gas. The Malay Basin of offshore Peninsular Malaysia and the Balingian Province of offshore Sarawak, are petroliferous Tertiary basins. Both basins are known to contain coal-bearing sequences of Lower Miocene age (Group I in the Malay Basin; Cycle II in the Balingian Province.) This paper compares and contrasts the respective geochemical and petrographic characteristics of the Balingian and Malay Basin coals with the purpose of assessing their oil generating capability and their source facies. The oil-prone nature of these coals can be envisaged visually under reflected light microscope, in particular using fluorescence mode visualization, and by evaluating their chemical composition in terms of hydrocarbon content. Based on the current investigation, it is most apparent that both sets of coals possess many similar oil-generative features, such as the extensive development of exsudatinite crack network, common occurrence of oil haze, significant occurrence of oil-prone liptinite macerals e.g. suberinite, including its derivatives, and show some common biomarker distributions. The use of biomarker distributions as an aid to correlating the coals to the oils of the respective basins is also demonstrated. Combined use of biomarker assemblages, calibrated with biostratigraphic data, helps constrain the source facies of produced oils. The application of detailed maceral analysis is described and is shown to be able to categorise the coal depositional settings of these basins into diferent sub environments.
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