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PGCE 2006
- Conference date: 27 Dec 2006 - 28 Dec 2006
- Location: Kuala Lumpur, Malaysia
- Published: 27 November 2006
1 - 20 of 60 results
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Pcsb Exploration Journey: Key Accomplishment to Date and Future Aspirations
More LessPetronas Carigali Sdn. Bhd., or more affectionally known as PCSB was incorporated on 11 May 1978. Little did anyone realised during that time, the small humble company with little experience and much less capabilities, would eventually grow to become a global player to be reckoned with. PCSB, being a wholly-owned subsidiary and operating arm of Petronas, was initially formed to increase Malaysian participation in the Exploration & Production (E&P) playing field by being involved in all aspects of oil and gas exploration, development and production. The PCSB exploration journey could be categorised into 4 main stages throughout its exceptional history. Despite starting from scratch, PCSB exploration division had strong aspirations and ambition. Within the first 10 years from 1978 to 1988, the foundation was laid to learn the ropes, gain experience, and acquire capabilities. Shell, BP and ESSO were PCSB’s main mentors during this period. The year 1989 marked the turning point for its challenging journey
when PCSB decided to leave its domestic comfort zone and took up the challenge to venture internationally, first as a partner then as an operator. The road to globalization began with its maiden E & P venture into Myanmar in 1990. One year later another milestone was achieved with the first overseas operatorship in Vietnam. That brave, albeit risky, decision to move beyond home was a stepping stone towards being a global champion. Having gained the confidence of host governments, NOCs, and other oil companies with PCSB’s exploration capabilities; and having established itself as a reliable operator and partner, the third stage of the exploration journey moved on to meet performance challenges. This 5-year period from 1995 transformed PCSB exploration to enhance operational excellence, be better partners, and trusted by host governments. Following that, PCSB’s exploration journey continued to build robust business, competitive advantage and pursue value and growth. Since its incorporation 28 years ago, to date PCSB exploration activities can be found in 23 countries with 69 blocks and operatorship in 34 exploration blocks. PCSB’s exploration journey will never end. It will respond and adapt to the everchanging E&P landscape and will continue to seek new playgrounds and achieve greater heights. Today’s PCSB will build and grow an even better legacy for future generation.
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Illumination of Vietnam Basement Fractures from 3D Seismic – A Methodology
More LessConventional 3D seismic attributes have been used to try identify faults and lineaments within granite or metamorphic basements. However, normal full stack seismic reflectivity has inherent noise and tuning effects contamination that complicates the visualization of subtle lineaments, faults and fractures. Empirically we found the acoustic impedance data derived from the far angle 3D seismic sub-stack was better than full stack seismic reflectivity to image the top basement reflection and better focus faults and image fractures. These localized areas of estimated higher fracture density are seen to be consistent with the interpretation of expected denser fracture areas from the convergence of the larger faults. The far angle seismic acoustic impedance data was processed through the dip and azimuth routine to enhance imaging fracture clusters and fracture trends. The illumination of such sets of fractures, faults and lineaments is facilitated by the use of selective color palette. These first results formed part of the input to new well trajectory design to encounter the basement faults and fractures optimally. The new wells’ FMI analyses confirmed the fracture azimuth sets as predicted.
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The Analysis of Controlled Source Electromagnetic Data for Prospect Evaluation in Block E, Sarawak, Malaysia
Authors Jonny Guddingsmo, Peter Van der Sman, John Voon, Matthew Choo and Kok and A. Yip-CheongThe controlled source electromagnetic method is increasingly used in petroleum exploration. However, interpretation and integration of CSEM data in the context of prospect evaluation is still quite a challenge. SSB recently acquired several 2D and 3D CSEM surveys in the E-block with state-of-the-art equipments. The survey covered an area of 2250 sq km by dropping 331 receivers and acquiring 582km of 2D, 364km of 3D and 635km of reconnaissance survey. The program is a compilation of operations and R&D
initiatives and targeted 10 prospects with up to three 2D lines and a single prospect with a dense grid of 2D lines complemented by a reconnaissance survey covering the entire survey area. Although all acquisition was executed in 2D, actual survey design was such that next to MT, also 3D CSEM data was collected. However, processing and interpretation of those data is the subject of a separate R&D effort and will not be discussed here. The subject of this paper centers on the conventional 2D CSEM data, their processing, interpretation and role in the context of prospect evaluation. Tying a CSEM response to a specific target is often confused by bathymetry and near-surface geology like gas-hydrates. The E-block survey is no exception. A methodology will be presented to make an inventory of these risks and how to significantly improve the confidence in the data by exploiting this knowledge in further processing and interpretation. A different, often ignored complication to the CSEM method are regional variations and trends that go undetected by a conventional, localized surveys and that may result in and misleading interpretations. We hope to demonstrate that by using the regional survey, trends and statistics the overall reliability of CSEM for prospect evaluation will further improve.
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A New 3D Seismic Stratigraphic Methodology Applied to Turbiditechannel Systems
Seismic stratigraphic interpretation is a powerful method for analyzing the depositional history of the subsurface. However, the lack of support of such interpretation methods in the state-of-the-art tools limits its application. A novel technology allowing a highly automated procedure for seismic stratigraphic interpretation is presented (figure 1). The technology includes an automated high resolution extraction step of all the stratigraphic primitives prior to the interactive session. The technology supports a “dual domain” concept that enables to interpret transparently in the seismic domain and the chronostratigraphic time domain. The interpreter controls this mapping by selecting the appropriate set of stratigraphic primitives to define this transformation. The high resolution extraction step, referred to as extrema classification in figure 1, is based on Borgos et al., 2005. The output from this classification results in extrema patches (figure 1) from which the stratigraphic primitives might be defined. The method can be extended to active tectonic basins by including fault patches in the mapping between the seismic domain and the chronostratigraphic time domain (Pederson et. al, 2005). Figure 1 illustrates how faults supplement extrema patches to define the geological model. In complex geological settings, as e.g. stacked turbidite channel systems, the application of seismic stratigraphic interpretation might reveal a better understanding of the depositional settings. To demonstrate the potential of the new methodology we have applied it to a case from offshore Brazil. The four extracted stratigraphic surfaces are built from merged extrema patches. The obtained stratigraphic primitives refine the geological model and allow accurately placing the compartment boundaries and identifying presence of hydrocarbons (figure 2).
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Improving Submarine Fan and Channel Interpretation using 3D Seismic Megasurveys
More LessThis paper demonstrates why a recent innovation using 3D seismic surveys is an exceptional tool for defining regional frameworks and play models. Traditionally, regional studies are based on 2D seismic interpretation and geological mapping, with subsequent input from prospect level 3D seismic data. However, improvements in hardware and software, together with technical advancements, now allow merging of contiguous 3D seismic datasets into one seamless MegaSurvey volume that may encompass an entire basin. Such coverage provides a consistent regional framework and perspective for detailed studies. It also provides a basis for high-grading plays and enables detailed assessment of critical elements within a petroleum system (e.g. fans and channels).
The PGS North Sea MegaSurvey, currently covers over 100,000 sq km. This coverage has enabled Paleocene fans to be fully imaged using seismic-volume attributes, which produced new play fairway concepts and increased regional understanding, thus rejuvenating interest in a mature basin. Similar megafeatures were identified in the PGS Dampier Sub-Basin MegaSurvey in Australia and the Campos Basin MegaSurvey in Brazil. In the Dampier Sub-Basin, feeder channels to the ~50 km long Angel fan system traversed the Lambert Shelf, along the Rosemary Fault Zone, and deposited sediments into the Lewis Trough during the Tithonian. Late Jurassic movement of the Rosemary Fault Zone had an impact on the depositional history of this fan system and hence on the critical elements of the associated petroleum system. In the Campos Basin, the Tertiary channel is ~100 km long. It lies adjacent to the producing fields of the Marlim complex. The MegaSurvey allows mega-channel and salt-induced structures to be interpreted with a high degree of confidence, thus reducing exploration risks in an ultra-deep water setting. These examples clearly illustrate the value of the “big picture” to explorationists and illustrate how MegaSurveys can provide an invaluable tool in stimulating activity in basins around the world.
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3D Seismic Imaging of Soft-Sediment Deformation Features in Sedimentary Basins, Offshore Norway: Implications for Exploration and Production
More LessLarge volumes of unconsolidated sediments can be remobilised by the migration of fluids through sedimentary basins. The occurrence and distribution of soft-sediment deformation features in sedimentary basins, therefore, can be used to help map the
occurrence and flow of basinal fluids. Based on the interpretation and visualisation of 3D seismic data, two case studies of the scale, geometry and distribution of soft-sediment deformation features are presented from the post-rift succession of the northern
North Sea basin (Fig. 1). Key seismic-stratigraphic features and the relationships between them were analysed using various volume and grid-based seismic attributes. It is demonstrated that in both examples numerous phases of soft-sediment deformation have occurred which can be related to a series of fluid flow processes. The results of this study, although based on examples from the North Sea, may have implications for the exploration and production of deepwater slope systems offshore NW Borneo.
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Hydrocarbon Prospectivity of East Central Luconia Carbonates, Sarawak
More LessSince the 1970’s, carbonate reservoirs were the main reservoir and contained the largest portion of the reserves in Central Luconia. During the third Petroleum Sharing Contract (PSC) round in 1995, less than 30% of the identified carbonate prospects had been drilled, and a similar situation remains today because of perceived risks. But previous historical carbonate exploration risks in the reefs located in Central Luconia Carbonates (CLC) have been challenged recently with new ideas proven successful with discoveries. Historically, the risks incorrectly downgraded the play, and can be summarized, viz.:
i. Carbonate reef pinnacles were thought to be small and contain limited hydrocarbon reserves;
ii. Most carbonates were over pressured and would have small gas columns;
iii. Many reefs contained high CO2 with significant H2S concentrations; and
iv. Thief sands breached the reservoir seal and increased exploration risk.
However, for the last few years several gas discoveries made, such as PC4, F2, F38, NC4 and Kanowit fields (Figure 1), contradicts the above reasons for downgrading the carbonate plays. Specifically, the 2006 well, called PC4.1, discovered more than 640 meters of gas column which is the longest single gas column penetrated to date in east Malaysia (Figure 2). The well was drilled under normal pressure conditions thus allowing a larger gas column (Figure 2). Also, low CO2 and minimal H2S contamination dispel previous contamination risks. The crestal seal breach via a trangressive lag deposit, or sand thief, exists in shallow carbonates areas in wells such as Tiong Mas-1, F39-1 (Tiong Gajah) and B16.1. This thief is present basin ward, but marine ward reefs were drowned earlier with thicker shales, so their seal integrity has not breached. These findings are significant. Challenging previous conceived risks has allowed the CLC exploration play to be high graded. In order to map the maximum gas column potential in the carbonates, future geological/geophysical understanding needs to be enhanced regarding thief sand distribution patterns both aerially and stratigraphically, as well as overpressure distribution and hydrocarbon seal capacity. Future 3D seismic will help mitigate the latter uncertainties, delineate with more clarity the reef pinnacles as well as biostromes and platform edges, and possibly dolomitization or recrystallization and dissolution enhancement of porosity in the carbonates. Basically, 3D will increase the possibility of finding more large reserve reefs with TCF potential and potentially thick oil rims. The main gas supply for Malaysia Liquid Natural Gas (MLNG) plants in Sarawak is produced from the CLC reservoirs. At present, only 45 gas fields have been discovered in CLC; but more than 100 identified prospects and leads at present remain to be drilled.
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Fractured Basement Plays, Penyu Basin, Malaysia
Authors F. Fanani, B. Boyce, R. Wong and A. Fahrul and C. AlwynThe Penyu Basin is located offshore 50 km west of Peninsula Malaysia and 40 km south of the prolific oil and gas fields of the Malay Basin. Located in open Block PM308, it covers 14,200 sq km and has water depths ranging 30 – 100 m. 12 exploration wells were drilled from 14,000 km 2D seismic. In 2004, Petronas Resource Assessment and Marketing (PRAM) acquired 660 square kilometers of 3D seismic over the Rhu structure and surrounding areas. The 3D seismic revealed various fracturing
basement highs, presumably analogous to the Anding Utara Malay Basin fractured basement oil discovery made in 2005. This new play type in the Penyu Basin opens a new frontier of untested basement plays – i.e. multiple basement targets from various structural styles. Crystalline basement in the Penyu are mainly fractured metamorphosed basalts and weathered tuffs. Regionally in SE Asia, basement fracturing is attributed to the Cretaceous tectonism, with possible overprints from Oligocene rifting, and later Miocene inversion. With 3D and 2D seismic, fractured basement leads were identified adjacent to Paleogene syn-rift hydrocarbon source kitchen.
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Soft-Sediment Deformation and Hydraulic Fracturing of Deep-Water Sediments: Examples from The West Crocker Formation (Oligocene-Lower Miocene), Sabah, Malaysia
More LessSoft-sediment deformation is a common feature of sedimentary rocks deposited under conditions of rapid burial. In the Lower Miocene West Crocker Formation, Kota Kinabalu area (West Sabah), soft-sediment deformational features occur in deep-marine sandstone, interpreted as submarine turbidites and debris flows. The structures include load moulds, flame structures, dish structures, and injection structures. Both sand and clay injectites, although mainly of mm to cm in scale, seem to be a common feature of the West Crocker Formation but have not been documented in the past. The occurrence of clastic injectites, especially of sand, in deep-marine sediment has received much attention lately because of their reservoir potential and impact on reservoir continuity.
Another interesting and distinctive feature of the West Crocker debrites is the occurrence of layerbound, bedding-normal fractures. These thin, often “hair-line” fractures are pervasive within individual sandstone beds but terminate in the shale beds above and below. Fracture spacing ranges from a few mm to 10’s of cm. They occur more commonly in the thicker (> 1 m) debrite beds, although some have been observed in beds that are less than 0.5 m thick. In the thicker beds, they are commonly associated with waterescape “dish” structures, and in places, clay injections at the base of the sand. These fractures are also cut by later, probably tectonic, faults. The soft-sediment deformational structures, such as load and flame structures, were evidently formed by gravitational loading of sand onto a fluidized muddy substrate, very commonly occur in the cm-thick shale partings between the massive sandstone beds. Injection structures are usually the result of instantaneous release of overpressure through the fracturing and re-mobilization of semi-consolidated sediment. The softsediment deformation features were formed at shallow burial depths (metres to tens of metres), when the sediment was still poorly consolidated. In contrast, the brittle deformation, however, which had led to fracturing, must have occurred after the sands had attained sufficient strength through consolidation and lithification at moderate burial depths (probably many hundreds of metres). In a compacting sedimentary basin, where the maximum principal horizontal stress (σ1) direction is essentially vertical, tensile hydraulic fractures may form at right angles to the minimum principal horizontal stress (σ3) direction, resulting in layerbound bedding-normal fractures. We envisage a post-depositional evolution for the West Crocker debrites as follows: (1) deposition (2) shallow burial and soft-sediment deformation (3) deep burial, sealing and overpressuring, (3) fracturing and injection.
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3D-Based Analysis of The Sumandak Complex: Significance to The Sediment Deposition in Offshore Nw Sabah
Authors Azli Abu Bakar and Christopher Jackson and Howard JohnsonThe Sumandak Complex consists of a series of oil and gas fields discovered in the Late Miocene Stage IVC sediments along the footwall of Morris fault located in the Samarang Sub-Block, offshore N orthwest Sabah, Malaysia (Figure ). This study aimed to use 3D seismic interpretation and visualisation combined with well data to; (i) understand the sub-regional scale sediment supply pathways into the study area, and (ii) determine the influence of active faulting on local depositional patterns.
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Controlling Factors in Clastic Reservoir Diagenesis Offshore Bintulu – Sarawak Basin
Authors Teguh Prasetyo and Andy FirthRock data from new well discoveries show that diagenetic factors such as pyrite, siderite, silica & ferroan-calcite/dolomite cementations, clay minerals (kaolinite, illite/smectite & chlorite) and compaction are the important controlling factors in reducing reservoir quality in Offshore Bintulu – Sarawak Basin. Pyrite and siderite are more abundant in shallow depths but their abundance decreases with the increasing depth (Fig.1). This phenomenon is because pyrite and siderite were formed as early diagenetic minerals in sandstone. The bulk rock volume of pyrite and siderite is small (<6%-10%). However these minerals reduce both pore space and pore throat size in the shallow section above 1500 mss. Quartz overgrowths are present from shallow to deep. Re-precipitation of quartz as overgrowths can occur at any depth but it is primarily controlled by pressure and temperature conditions. In the study area, the presence of quartz overgrowth(s) is more common in the deeper interval (Fig.2). In the deeper interval, reprecipitation of quartz as quartz overgrowths is a major agent of pore space and pore throat size reduction. Ferroan-dolomite starts to appear in the deeper over-pressured interval of the study area. The mineral is controlled by both the environment of deposition (the more proximal marine – the more abundant) and the pressure temperature conditions required to precipitating it. The bulk rock volume of ferroan dolomite is low (<6%) but it becomes increasingly important as an agent of the reduction of both pore space and pore throat size with depth (Fig.3). Within most of the study area sands, the proportion of clay is low (<20%). The predominant clay mineral of this fraction is illite+mica followed by kaolinite (Fig.4). The low abundance of pore bridging illite/smectite is evidence that the study area sands are at an early-mature stage of diagenesis. Clay minerals contribute to the reduction of both pore space and pore throat size. However because of its low abundance clay, whatever its form is not a major contribution to the reduction of pore space and pore throat size. Fig.5 shows that compaction is the most important controlling factor on the reservoir quality of the study area sands. At shallow depths, compaction is light. At deeper depths, compaction increasingly influences reservoir quality regardless of the facies. However the fine grain silty low energy facies exhibit a more rapid reduction in reservoir quality than the coarse high energy deposits. This paper describes the integration of core, petrography, XRD and mineralogy data from
SK309/SK311 new well discoveries in the study area. It attempts to contribute to an understanding of clastic reservoir diagenesis in an inverted coastal plain to shoreface depositional environments in Offshore Bintulu – Sarawak Basin.
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The Role of Sedimentology in Accurately Characterising Newly Discovered Reservoirs
Authors Duncan Barr and Tony KennairdEarly confirmation of depositional environment is essential if a new hydrocarbon play is to be properly understood and developed, as it is a major factor influencing the morphology, trend and continuity of a reservoir. Accurately predicting the reservoir morphology, trend and continuity limits the risk of drilling dry holes and leads to superior estimates of reservoir gross rock volume – probably the single most important factor when calculating hydrocarbon reserves. On the larger scale, regional seismic information is used to paint a broad picture of the reservoir, with more detail added as wireline log information comes to hand. The inferences drawn from these two methods of investigation should then be confirmed or refuted as quickly as possible by detailed sedimentological examination of the actual reservoir rock. This is best achieved by visual description of conventional core. The importance of sedimentological core description is highlighted in this paper by reviewing two case studies. The first study, completed in 2003, was conducted following the unexpected drilling of a dry hole. Sedimentological description of available core material led to a complete re-interpretation of the depositional environment, and consequent reassessment of reservoir trend and morphology. In the second study, completed in 2001, detailed core descriptions also caused a previously conceived, pessimistic geological model to be dismissed. The new model re-defined reservoir continuity and morphology, thereby adding substantially to estimated reserves.
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The Sequence Biostratigraphy and Chronostratigraphy of The Malay Basin
Authors Robert J. Morley and Shamsuddin JirinThrough a comprehensive review of biostratigraphic data from the Malay Basin, in relation to seismic data, it is demonstrated that a large proportion of the microfossil assemblage variation seen in the basin is driven by sequence stratigraphic processes. Sequence biostratigraphic signals fall into two types: 1) signals relating to sea and lake level change, such as abundance and diversity acmes of foraminifera and nannofossils, and acmes of mangrove pollen and lacustrine algae, and 2) palynomorph assemblage changes reflecting climate change, which would have paralleled changes in sea level. Biostratigraphic signals for each systems tract can be distinguished. The maximum flooding surface, separating the transgressive systems tract from the highstand, is generally marked by a foraminiferal (and sometimes nannofossil) abundance and diversity acme, whereas the highstand is generally characterised by pollen signals suggesting a warm and wet climate. The transgressive systems tract is invariably marked by an acme of mangrove (Rhizophora type) pollen, and the transgressive surface by an increase in abundance of marine microfossils. The lowstand is usually characterised by an acme of cool and/or seasonal climate pollen, although some for some lowstands the climate was cool but wet, and these are generally characterised by acmes of pollen from an unusual type of peat swamp. Lacustrine algal signals need to be used differently is sequence interpretation depending on the strength of marine influence. The succession has been divided into 21 sequences based on biostratigraphic signals alone. Fourteen of these are within seismic groups D-M. Sequences within seismic groups A-H can each be independently dated using mainly nannofossils which occur at the maximum flood, but for sequences within seismic groups I – M there are no reliable Malay Basin microfossil occurrences for which the age has been accurately established. However, within groups I through M, terrestrially derived palynomorphs are abundant, and by correlating using palynological zones into the West Natuna Basin, where good nannofossil control is available to the base of the Arang Formation at the base of the Early Miocene (tying the ‘PR’ Malay Basin palynological zones of Azmi et al (1996) into the West Natuna ‘P’ zones of Morley et al (2003), the succession can be accurately dated down to base Group J. The age for Groups K through to M is proposed by sequence correlation with the West Natuna Barat and Gabus Formations, for which the age has been proposed using climate signals alone, through comparison with the global oxygen isotope curve. The study indicates that the age of the Group J/K boundary (previously ~21.4 Ma) is underestimated, and that this boundary should coincide closely with base Early Miocene at 23.09 Ma.
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A New Chronosequence Stratigraphy for the Tertiary of Offshore Sabah and Sarawak, Northwest Borneo, Malaysia
More LessUnconformities and condensed sections are boundary events in sequence stratigraphy that represent discontinuities in deposition. These events can be detected using chronostratigraphy. Unconformities, for example, represent periods of geologic time not preserved in the rock record—a hiatus. Condensed sections, however, are thin rock intervals which comprise so much geologic time that they resemble hiatuses. Chronosequences are rock intervals bounded by hiatuses, regardless of their origins, and are the fundamental unit of chronosequence stratigraphy. Graphic correlation of biostratigraphic well data is a practical method of identifying hiatuses and chronosequences in the subsurface (Carney and Pierce, 1995). A graphic correlation plot relates rock thickness to geologic time--vertical thickness vs. horizontal geologic time. The line of correlation, drawn through microfossil datums, depicts geologic time in a rock section. Flat line segments, or terraces, signify periods of geologic time not preserved or highly condensed in sedimentary rock (hiatuses). Oblique line segments between terraces constitute chronosequences. Accumulation rates are directly proportional to the slope of line segments. Graphic correlation analysis of biostratigraphic data from the Upper Eocene-Quaternary section of 100+ wells in offshore Sabah and Sarawak has revealed the presence of at least 22 regional hiatuses, H05 to H180, that separate 23 chronosequences, S05 to S190. These hiatuses represent unconformities or highly condensed sections characterized by key microfossil datums (Figures 1-2). The hiatuses occur in both Sabah and Sarawak, and are very similar in timing and duration (Figures 3-4). This suggests that major tectonic/eustatic events during the Tertiary had a regional effect on deposition throughout NW offshore Borneo, and that an integrated Tertiary chronosequence stratigraphy for Sabah and Sarawak is possible. Some Upper Tertiary hiatuses coincide with regional seismic horizons (unconformities) on the Sabah shelf (Bol and van Hoorn, 1980; Levell, 1987) that appear related to tectonism (Meng, 1999; Madon et al., 1999; Balaguru et al., 2003). Graphic correlation, however, has defined additional hiatuses within the Tertiary that are beyond seismic definition. This enhanced stratigraphic resolution reveals that seismic horizons may merge and be misidentified unless verified by microfossils. Maps, basin and depositional models, source rock maturity, and the timing of structural deformation and hydrocarbon expulsion based on miscorrelated seismic horizons will be flawed and misleading. Although regional unconformities are common on the Sabah shelf, they decrease in duration offshore and off-structure and correlate to conformable beds or even condensed sections on highs in the outboard area.
Some hiatuses on the shelf, however, may represent widespread condensed sections produced by major eustatic transgressions, such as that of the early Pliocene. Chronosequence stratigraphy, integrated with seismic and geologic data, will be necessary to understand the complex Tertiary structure and stratigraphy of offshore NW Borneo.
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Chronostratigraphic Chart of The Sedimentary Basins of Malaysia
A stratigraphic chart incorporating all major Cenozoic Basins in Malaysia was constructed by Petronas. This chart reflects the most recent interpretations of Malaysian stratigraphy and correlations of east and west Malaysia. Our goals are to generate a comprehensive chronostratigraphic chart and increase the success rate of hydrocarbon exploration and production in Malaysia. The chart compares stratigraphy of eight major basins in Malaysia: Sabah, Sarawak, Malay, Penyu, Natuna, Straits of Melaka, Tarakan, and Sandakan Basin. It includes major lithostratigraphic units as well as biozonations and key biostratigraphic markers. In addition, three different geologic time scales were integrated with two eustatic sea level curves. The chart collates interpretations from hundreds of geoscientists who published within the last 50 years. Nomenclatures are referenced to the original author(s) as well as subsequent author(s) when possible, and in most cases have been reviewed by the source. This chart should
be considered a work-in-progress that will require future inputs.
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Facies Successions and Depositional Elements within the Oligocene-Miocene, Crocker Submarine Fan System, Nw Borneo, Sabah, Malaysia
More LessThe Oligocene to Early Miocene West Crocker Formation of Northwest Borneo represents a widespread, an unconfined basin-floor submarine fan complex that was deposited in an accretionary foredeep basin. The system covers more than 25,000 sq km, therefore rivals in terms of size and sediment volume many of the worlds largest modern and ancient turbidite-fan systems. The West Crocker Fm comprises at least 1,000 m of sandstone-dominated succession constructed of higher-frequency sequences.
Road cuts and construction areas provide exceptional vertical, but limited strike-extent exposures of the turbidite fan system, and provide the framework for interpreting the depositional mechanisms and elements. Vertical facies successions logged from key outcrop exposures record a complex basin-floor submarine fan system constructed of end-member deepwater depositional facies. 1) Sand-rich leveed channels transitional to low-sinuosity, sand-dominated channelised sheets/lobes and 2) mixed sand-rich to mud-rich leveed-channel, which may serve as updip feeder or bypass systems. The channel lobe complex is characterized by laterally shifting shallow channels, fining or thinningup (FU/TnU) sequences and by progradational, non-channelised lobe deposits, coarsening or thickening-up (CU/TkU), sequences. The resulting sandstone body is stacked multi-story and multi-lateral. Vertical facies successions are dominated by 5-15m-thick, FU/TnU sequences and, less commonly, by thinner 2-10m-thick, CU/TkU sequences. The major sandstone bodies are sharp-based, locally erosive and in places loaded. Facies are mainly S3-Ta turbidites of fine- to medium-grained sandstone, which are medium- to thick-bedded (up to 3m-thick), internally structureless or with a feint horizontal stratification, sometimes graded and occasionally associated with thin muddy debrite (debris-flowed) units. Slumps are present but rare. Leveed channel systems are recognized by overall fining or thinning-upward (FU/TnU) successions of aggradational/fill and lateral/spill of channel axis and margin facies, proximal levee and distal overbank levee facies; clay plugged avulsed channels and splays. These are resulted from the gradual lateral migration of a major, meandering channel system. The vertical facies trend reflects a gradual migration away from the sand supply system and displays a vertical stack of FU/TnU bed sets, with each succession displaying increasing distal characteristics upwards in parallel with decreasing in sand content and a general reduction in bed thickness towards the top. Individual channel complexes are between 15-60 meters thick and display net-to-gross of more than 80% sand. Sand-rich leveed-channel axis and terminal braid-plain channel facies consist of S3-Ta turbidite
mega-beds (2-3.5 meters thick) of medium to very coarse sand in massive poorly sorted, erosive bases, trough cross bedded, diffuse wavy parallel layered, hummocky aggradational in-phase bedforms, internal erosional surfaces or bed boundaries, planar grain-sorted parallel layered sheet bedforms with dewatering structures. The channel margin facies and braid-plain sheet facies consists of massive to diffusely laminated, coarse to medium sands with flow-stripped, ripple-laminated to debrite caps. Inter channel braid plain bars are constructed of shingled, lenticular bedforms and common debrite beds. Mixed sand-mud leveed channel complexes, up to 60 meters thick, grade upward from stacked multistory channel mega-beds to thinning and fining-upward proximal and distal levee facies characterized by flow-stripped ripple laminated (climbing and in-phase ripples). The outcrops under investigation provide a rare opportunity to study the detailed facies characteristics, sand body types and reservoir architecture within a Tertiary deepwater succession from SE Asia. They offer valuable insight into deepwater depositional systems during the early Tertiary evolution of NW Borneo. They may also serve as partial outcrop analogues for other deepwater, hydrocarbon-bearing reservoir systems, including some of those found in younger (Miocene-Pliocene) deepwater successions in both offshore NW Borneo (Sarawak, Brunei and Sabah) and E Borneo (Kalimantan).
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Tectonics, Seismic and Sequence Stratigraphy of Melut Rift Basin, Sudan
Authors Ahmed El-Tayeb and Othman Ali MahmudRecently, the fundamental principles of seismic and sequence stratigraphy have been applied to the analysis of rift basin fills formed in tectonically active settings. The spatial distribution and temporal evolution of depositional systems in such settings are considered to be significantly influenced by tectonics. Tectonism may be the major factor controlling stratigraphic and facies patterns by increase or decreases of accommodation space, alters depositional base level and thus, control the distribution of source areas. Fault movement and stage of basin development control the potential for erosion and the rate of sediment flux. It was the aim of this study to reveal a sequence stratigraphic framework of the Melut rift basin to obtain better understanding of the petroleum system origination and to substantiate plays delineation in different areas of the basin. The Melut basin exhibits typical rift extensional tectonic feature with strike-slip effects. Major fault trends throughout the basin are NW-SE to NNW-SSE, oblique to the main basin axis. The penetrated sedimentary infill of the basin is dominated by fluvial and lacustrine sandstone and mudstone of Upper Jurassic to Quaternary age. Distribution of the facies is likely to have been controlled by pulses of faultcontrolled subsidence followed by more prolonged episode of thermal subsidence. Identification of depositional environments and outlining the Low Stand, High Stand and Transgressive depositional systems tracts within an evolving rift basin implies that shale source rocks, sand reservoir rocks and shale sealing rocks distribution and their quality can be estimated in addition to defining sediments transportation pathways. Sequence stratigraphic understanding of the basin leads to depositional model construction; moreover, current techniques of basin analysis are initially associated with the tools of seismic and sequence stratigraphy. Reliability and predictive power of the depositional model is based on the body of knowledge already obtained from the modern and ancient rift basin analogous to Melut. Therefore, a scientific synthesis of analogous rift basins is considered as an important stage in developing the depositional model. The model should be able to enhance an ability to predict location, thickness and properties of the source rocks, sealing shales and the quality and maturity of reservoir sands. Melut rift basin depositional model, together with the analysis of the petroleum system elements, could be used for the construction of the geological model and the prediction of hydrocarbon occurrences in the basin, and thus, opened an opportunity to delineate the fairways of the sediment transportation into the local depocentres, and locating stratigraphic traps. This work concluded that development of the sequence systems tracts of Melut rift basin was dictated by the extensional tectonic events taken place from the late Jurassic to early Tertiary. Main source rock of Al Renk, Galhak formation were developed during early rift to rift climax stages in localized Major Fault Bounded basins, and deposited in deep-lacustrine settings. The main reservoir sands of Yabus and Samaa formation were developed during the second rift phase, partly in the progradational High Stand Systems Tracts and the lower part of the subsequent Transgressive Systems Tracts. Adar formation, as the regional top seal, represents the upper part of the Transgressive systems tracts, and was developed in late rifting time.
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Marginal Field Development Strategy: Malaysia Pm304 Cendor Field Success Story
Marginal fields are defined primarily by having either small reserves and/or reservoir constraints. Success in developing marginal fields has traditionally been achieved through a series of surface facilities and subsurface risk reduction exercises. While some oil companies appear to be less concerned about these issues due to the recent escalation in crude price, the success of any marginal field development can still be enhanced if every one of us are prepared to question the status quo of how we conduct our business; in particular, the so-called standard operating procedure (SOP). Even with crude oil price currently at elevated levels, an associated increase in the service sector and equipment costs has occurred such that potential profit margins are still difficult for marginal fields. More importantly the degree of risk is higher as the costs associated with failure are now significantly greater. Petrofac (PM 304 Malaysia) Ltd acquired the Cendor Development Subblocks on 6 May 2004 which includes the Cendor field. Cendor was defined as a marginal field due mainly to reservoir compartmentalization issues. Nevertheless, within 26 months from the asset purchase, this marginal field is currently producing. Petrofac have successfully developed the Peninsular Malaysia (PM-304) marginal Cendor field asset through the traditional risk reduction exercises but moreover, by assuming a ‘contractor mentality’ approach and work program where being safe, ‘on-time’, and ‘under-budget’ was an ever present operational directive that has permeated the subsurface effort as well as the operational aspects of the project. This approach is translated into daily business activities through: 1) Challenging the Standard Operating Procedure (SOP) via ‘Nice to have’ versus ‘Need to have’ mentality
2) Diversifying the risks and adopting ‘check and balance’ through partnerships 3) Employing the right person, for the right job, at the right time 4) Maximizing sim-ops operations, where applicable Marginal project development is like small project management – all of the same work needs to be done, but the margins for overrun in any one area are much tighter than on big projects. As such, project teams must arrive at ‘fit for purpose’ solutions in the tightest time frames possible – an integrated team approach
minimizing communication and contractual interfaces is vital. Equally important is the need for personnel who can think “across disciplines”. Petrofac’s internal in depth expertise and experience, especially in Facilities and Construction, and oil and gas field operations/management help in expediting the decisionmaking process. These aspects of marginal field development allowed key project decisions to be made well down the learning curve while still permitting key surface and subsurface risk reduction exercises to be successfully completed. The series of innovative risk reduction efforts, surface and subsurface, and operational mentality lead to PM-304 Cendor field receiving FDP approval in record time, delivering first oil within 26 months from project conception and only after 14 months from the FDP approval, and significantly under budget. Hence, it may be time for some companies and key individuals to challenge the relevance of each step of their standard operational procedures.
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Delivering Time-Lapse Seismic over a Carbonate Field, Offshore Sarawak, Malaysia
This paper presents Shell’s recent experience in delivering time-lapse seismic technology as a tool for reservoir management. The field is M4, a flat-top reefal carbonate buildup located offshore Sarawak. It was discovered in 1980 with a gas column of 170ft. The field has been producing since 2002, through 2 near horizontal wells located some 25 ft below the top of the reservoir, with strong aquifer drive. The existing 3D survey was acquired in 2001. Supported by the results of a feasibility study, a monitor or time-lapse 3D survey was acquired in 2005 to monitor the production-related effect within the reservoir. The multidisciplinary effort that is key to the success of the technology delivery will be addressed. The paper will discuss the components of the technology delivery, that is, the feasibility study, the planning and acquisition of the monitor survey and careful processing of both base and monitor surveys. The success will be further demonstrated by the excellent results, which will also be shared.
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Seismic Attributes: Adding a New Dimension in Prospect Evaluation & Reservoir Delineation
By Deva GhoshIn seismic interpretation a reflection is generally characterized by its arrival time and its reflection strength i.e amplitude. In terms of its wave component it can be represented by three important variables namely amplitude, phase and frequency. All other attributes are simply linear combination of these three. Each of these variables represents different attributes of the waveform and in geological terms brings out different aspects of the geologic feature.
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