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PGCE 2006
- Conference date: 27 Dec 2006 - 28 Dec 2006
- Location: Kuala Lumpur, Malaysia
- Published: 27 November 2006
1 - 50 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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3D Avo Volume Visualization in Identifying Hc Leads in Offshore Sarawak
A qualitative 3D Amplitude Variation vs Offset (AVO) analysis was applied in a 500 kmsq area offshore West Baram Delta. The primary objective was to predict presence of deep prospects within or below the overpressure regime in the area. The scope of work basically involves PreStack Depth Migrated velocity modeling where the velocity model was converted to time to be utilized as input velocity in generating the 3D AVO (Amplitude Variation v Offset) cubes. The velocity model was produced via a tomographic velocity modelling process, while standard 3D seismic reprocessing was applied to generate selected AVO volumes/cubes. Several leads were identified from the 3D seismic AVO analysis where proven reservoirs/fields were used for validation of the method. Previous rock physics study shows that velocity (Vp) and density of hydrocarbons can be discriminated from wet sand and shale. Vp/Vs ratios of oil and gas sands were also significantly lower than the background. Thus, we predict a Class III AVO response for the hydrocarbon sands in this area. Based on geophysical overpressure study done at a well location, we infer either a Class II “normal” (Small negative impedance with large positive gradient) or Class II “positive” (Small positive impedance with large positive gradient and polarity change) for overpressured reservoirs. The leads/prospects were identified based on strong amplitude anomalies correlated between the Far Angle, PxG and Difference AVO attributes volumes following extensive analysis and utilization of the 3D volume visualization capabilities in the Petronas Visualization Center. The strong AVO anomalies observed on the PxG and Difference attributes conform with the fault delineations and structure. Classic Class III AVO responses are observed from the Petronas Research processed 3D AVO cubes. As a result, several new leads/prospects have now been identified for further analysis and/or validation by PCSB including several deep prospects in the overpressure regime.
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Correlation of Discontinuous Deltaic Sands Using Well-Log Facies and Sequence Stratigraphy (Lower Miocene, Cycle Iii, Offshore Balingian Province, Sarawak)
By M.C. BuddingWell-to-well correlation of sandstones and shales from environments between high and low-stand shorelines can be problematic in the Sarawak offshore. A technique was developed for adjusting the diagnostic content of conventional well logs to the equirements of geologists. A log-facies scheme was made by calibrating an overlay of Gamma Ray and Sonic logs to lithofacies and biostratigraphic characteristics. Nine log-facies were distinguished by using a combination of six criteria: V-shale, Interval velocity, Sonic- Gamma Ray separation, vertical trends in the separation and unit thickness. Characteristic facies associations were identified via up-scaling, by analyzing recurring sequential patterns in six wells using Markov-chain techniques. Five key facies associations could be distinguished: marine shale, regressive shoreline, coastal plain, incised valley, and transgressive shoreline. Contrary to the discontinuous sands and shales from the original logs, these associations can be readily correlated between wells. This allowed recognition of key bounding surfaces, identification of fault cut-outs and eventually the construction of a stratification framework for 3D modeling.
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Integrating Biostratigraphy with Seismic for Sequence Stratigraphic Interpretation in The Malay Basin
Authors Shamsudin Jirin and Robert J. MorleyBiostratigraphy is routinely run on most wells in the Malay Basin, but it’s value in interpreting sequence stratigraphic succession has not been fully assessed. For the first time, biostratigraphy has been fully integrated with seismic to construct a regional sequence stratigraphic succession of the Oligocene to Pliocene sediments of the basin. A comprehensive biostratigraphic database from over 40 wells has been reviewed within a regional seismic grid. The data shows that most of the biostratigraphic assemblages are driven by sequence stratigraphic processes that are largely attributed to sea level and climatic changes. The lowstand systems tract can be differentiated from the transgressive and highstand systems tracts by the low proportion of mangrove-derived pollen (especially Rhizophora type), the high represenation of dry-cool palynomorph elements, and in many instances pollen the presence of acmes of pollen from an unusual type of peat swamp, termed ‘Kerapah’ swamp. The transgressive surface is often marked by an increase in foraminiferal abundance, and coincides at the onset of increasing mangrove-derived pollen. The transgressive systems tract is generally characterized by the increased abundance of mangrove-derived pollen coinciding with the main period of sea level rise. The maximum flooding surface is often differentiated by an acme of foraminifera and nannofossils. In outer shelf and upper bathyal environments, the maximum flooding surface is often indicated by an acme of deep and/or cold water of foraminifera. Within the highstand systems tract, pollen suggesting a warm and wet climate tends to dominate, and benthic milioliid foraminifera may be common. Through properly assessing the above biostratigraphic parameters, major sequence stratigraphic stratal surfaces and their associated system tracts can be recognized on Biostratigraphic data alone. These surfaces are positioned into a seismic framework by determining their fit with stratal termination patterns of onlap and downlap. By holding a workshop session in a workstation environment, horizons with anomalies between seismic and biostratigraphy can be adjusted iteratively. Typically, both disciplines contribute more or less equally to positioning stratal surfaces and constructing the sequence stratigraphic model. Currently 21 sequences (third and fourth order) are recognised in the Malay Basin based on the strengths of both seismic and biostratigraphy. This review demonstrates that the sequence biostratigraphigraphic approach, integrated with seismic sequence stratigraphy provides a more robust sequence stratigraphy than that obtained when using either discipline on its own. It is strongly recommended that future Malay Basin sequence interpretation should be conducted as a joint process with respect to the interpretation of sequence stratigraphic surfaces; with the integration of biostratigraphic and seismic data taking place in a workstation environment. Both disciplines can add value to the other if used together.
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Formation of Co2 in Sedimentary Basins and Assessment of Co2 Risk in Gas Prospects
Authors Cathles Lawrence M. III and Schoell MartinThe unexpected occurrence of CO2 in gas reservoirs is a major risk in exploration for natural gas, particularly in SE Asia. The fundamental processes of CO2 formation in sedimentary basins are still a matter of dispute. Many explorationists assume that “carbonates in the basement” at high temperatures are the major source of CO2 in Tertiary basins although solid carbonates could only produce any CO2 at contact metamorphic temperatures above 700oC. However, basin-fill sediments in Tertiary basins contain abundant carbonate and silicate species that react at temperatures above 320oC to form CO2 (Figure 1). Based on this concept we have developed a complete model of CO2 generation, migration in which high mole fraction CO2 gas is generated by the breakdown of siderite (FeCO3) and magnesite (MgCO3) only where, parts of the basin are being heated above ~330°C (CO2 Kitchen). CO2 reacts with Fe-, Mg-, and Ca-silicates as it migrates upward and away from its source kitchen. Near the kitchen, where all the above silicates have been destroyed by previous packets of migrating CO2, gas moves upward without lowering its CO2 mole fraction. Further out, where Fe- and Mg silicates are still present in the sediments, the fugacity of CO2 is lowered to buffed levels described by Smith and Ehrenberg (1989). In this zone reservoirs will have mole fractions CO2 of a few percent at 200°C. Still further from the source (or at the same location but earlier in the basin's history) where Ca-silicates are encountered, CO2 concentrations fall nearly an order of magnitude below the Fe- and Mgsilicate buffered levels. The lowering of CO2 mole fraction by reaction with and titration by Fe-, Mg-, and Casilicates must occur along a "regional" migration path rather than "locally" within a reservoir because local reduction of high CO2 gas concentrations would result in more intense carbonate precipitation than is generally observed. A model of CO2 generation and "regional" CO2 titration has been constructed and integrated into a conventional basin model. Application of the model is illustrated by computing CO2 generation in three transects in the Malay Basin.
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Surface Geochemistry as an Exploration Tool in Frontier Areas Case Study From Offshore Brunei
Authors Malvin Bjorøy and Ian L. FerridaySurface geochemical prospecting involves the search for near-surface or surface anomalies of hydrocarbons, which could indicate the occurrence of petroleum accumulations in the sub-surface. The methodology, as applied in offshore basins, covers a range of techniques, from observation of visible oil seepage at the surface to detection of micro-seeps in near surface sediments using sensitive analytical techniques, Since most rock types are not totally impervious to hydrocarbons, both light and heavy hydrocarbons
will migrate upwards, from either mature source rocks or reservoirs, to near surface sediments. While the methodology for surface geochemical surveys is the subject of continuous development, the current, most favoured practice is to detect possible migration pathways from the deep to the near-surface with the aid of seismic data, often together with remote sensing data (satellite imaging etc). The expression of such pathways at the surface is then the focus of surface geochemical prospecting grids. Most articles concentrate on the analysis of the samples and integration of the geochemical data with the geological framework. It is, however, important that the samples are collected properly and that the samples are preserved in such a way that the original hydrocarbon assemblage present in the samples when they are brought onboard are preserved for analysis, i.e. care must be taken that there is no bacterial activity after the samples are collected and before they are analysed. Another important factor when undertaking surface geochemical studies is cost. In all such studies, sampling constitutes by far the greatest cost. It is therefore important that the methods used for sampling are streamlined for the purpose, i.e. that methods are not used merely because they give apparently impressive results without increasing the quality of the samples. It is very easy to double the sampling cost by using expensive techniques which do not enhance the quality of the samples. A surface geochemical study was undertaken over the deep water areas offshore Brunei in 2001 on behalf of the Petroleum Unit of Brunei. The selection of samples was partly based on a 3D survey undertaken over a part of the study area closest to shore and partly based on a regional 2D survey for the part of the area
furthest from shore. A total of 200 first priority sample locations and 13 second priority sample locations were selected, Figure 1. A total of 203 sample locations were sampled resulting in 189 recovered cores with enough material for geochemical analyses, i.e. there was good material from the anoxic part of the sedimentary sequence. A total of 10 locations were not sampled due to equipment problems. The average water depth was 1640 m and the average number of cores collected per day was 16. A 4 m core barrel was used for all the sample stations. The average core length was 3.2 m, including the cores that had very short length, or none due to hard seafloor/rocks. By using the USBL system, all the samples were collected within a radius of 25 m from the target. The average distance from the target was 6.4 m. Details regarding the sampling are shown in Table 1. Three of the cores contained gas hydrates, which were collected for analysis. One of the cores contained oil, which was running out of the core liner after the core had been brought up on deck. A strong smell of hydrocarbons was detected in approximately 20 cores. Samples from the anoxic part of the cores were collected, put in pre cleaned cans, flushed with nitrogen, sealed and frozen to -80 oC within minutes after
the cores were brought on deck. After the survey was completed the samples were packed into special cooler boxes with dry ice for transport to the laboratory. A complete geochemical analysis program was undertaken, i.e. headspace gas, occluded gas, adsorbed gas, TOC and TC of clay fraction, solvent extraction, GC analysis of EOM, TSF of EOM plus GC-IRMS of gases and GC-MS of EOM of the samples which showed signs of petrogenic hydrocarbons. The abundance of gases in the headspace gas, the occluded gas and the adsorbed gas are lower than what is normally found in other studied areas, e.g. the North Atlantic and the Barents Sea, (Bjorøy and Ferriday, 2002). The abundance of adsorbed gas is particularly low. Similar low abundance of adsorbed gas was also found in other areas of the South China Sea, Abrams, (1996). This was interpreted to signify that there were no active seeps in the area by this author. This is not correct for the area we have studied. Our study showed that the percentage of clay in the < 63 μm fraction is far lower for the offshore Brunei samples than was found for samples in other areas, i.e. the North Atlantic and the Barents Sea samples. The reason for the lower abundance of adsorbed gaseous hydrocarbons is the low clay content in these samples. A number of samples showed active seepage of gaseous hydrocarbons. Before the survey was undertaken, the general belief was that the deep water area offshore Brunei would be a gas province at best. None of the analyzed samples in this study contained dry petrogenic gas. The samples with petrogenic gas contained oil-associated gas based on the composition and isotope values of the gases. A number of hydrocarbons seeps were detected in the survey area, ranging from light oil- to
condensate-associated, with varying degrees of biodegradation, and including seeps where hydrates were observed in the shallow cores. A total of 40 samples contained seeped liquid hydrocarbons, biodegraded or partly biodegraded, based on the GC analyses. Some of the analyzed samples contained that large abundances of liquid hydrocarbons that they are classified as representing megaseeps, i.e. the samples are in the close vicinity of a conduit where hydrocarbons are actively seeping to the surface. Some of these samples were already described as containing live oil during the sampling. The analyses of the solvent extracts show the samples to contain seeped liquid hydrocarbons with maturities from the lower oil window to the condensate window. Selected gas chromatograms are shown in Figure 2. The gas chromatograms of another group of samples showed these to contain a large unresolved envelope, representing biodegraded hydrocarbons. The seeped hydrocarbons in these samples were partly masked in the gas chromatograms by hydrocarbons originating from recent organic material (ROM). This is interpreted to represent old seeps which are not active any more. From the variation in GC-MS data, the light oils are proposed to have been generated in a deltaic / terrestrial source rock similar to known Brunei oils, with the possibility of two facies / formation variations contributing in different parts of the area. A map showing seeped hydrocarbons is shown in Figure 3.
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Optical Sensor and Accelerometer Revolution for Seismic Monitoring and Acquisition
Authors Jan W. Schoolmeesters and Steve Maas and Rune TenghamnFiber optic sensor systems have been under development for many years. PGS has produced prototype seismic equipment to demonstrate the optical technology. In 2003 and 2004 a 4C seabed cable has been successfully demonstrated during field operations in the North Sea. Data collected from the field tests have proven the prototype optical system meets the performance required of the deepwater seismic operation. Presently a new 4C seabed system, based on a fiber optic high sensitivity accelerometer, is under development. This new system is an excellent fit for conventional 4C seismic operations but would be the preferred solution for permanently installed reservoir monitoring systems. Some of the advantages we expect to realize from an optical system include: no in-sea electronics, improved reliability, lighter weight, significantly reduced deployed system cost and improved operational safety.
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Lithology and Fluid Uncertainties from Deterministic Inversion
More LessDeterministic simultaneous inversion provides us with a representation of the subsurface in terms of P-impedance and S-impedance. In the case where we have excellent results it can still prove difficult to interpret these impedances in terms of lithologies and fluids for a number of reasons. Often the properties of the rocks are not unique indicators of the type of rock or fluid even when the beds are fully resolved. When the beds are below seismic resolution there is even more uncertainty. Under such conditions of overlapping properties and sub-resolution beds, it is often recommended that some form of geostatistical inversion is considered to quantify and reduce the uncertainty. However, such inversions are often difficult and time consuming. It is often advantageous to have an estimate of uncertainty without having to go to a full geostatistical inversion. There are various methods to convert a combination of P-impedance and S-impedance to lithology probability. However, the implementation of such methods can be hampered by a lack of control data. In this paper we present a method based on geostatistical simulation to enhance the input data and provide a guide to the interpretation of the estimated probabilities.
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Resolving Fault Shadow Problem by Fault Constrained Tomography
More LessFault Shadows manifest a serious challenge to successful seismic imaging. The major part of this problem is caused by rapid lateral velocity changes within fault zones. Seismic rays traveling through fault areas experience geometrical and traveltime distortions which result in poor seismic images and nonhyperbolic moveout anomalies in areas below such fault planes (Fault Shadow Zones). Fault Constrained Tomography (FCT) is a special depth processing technique developed to solve this problem by building
detailed high resolution interval velocity model for such zones. Combined with Pre-Stack Depth Migration (PSDM) this technique allows to remove Fault Shadow distortions from seismic images.
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Towed-Streamer Multi Azimuth
Authors Terry Allen, C. Page, E. Fromyr, R.V. Borselen, J. Keggin, W. Rietveld and T. ManningThe streamer Multi Azimuth technique is an extension of conventional marine towed-streamer acquisition method. It is an attempt to overcome the lack of uniform illumination of the target due to irregular and complex target geology or a complex overburden. While this technique has not been in general use, an increase in the past few years has led to some impressive comparisons (see Kravik et al). As a result of increased use, several key aspects have been adopted for success and are discussed here. In addition, a few data examples are included to demonstrate benefits of this technique.
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Improving Seismic Discontinuity Attributes
More LessSeismic discontinuity is the most important reflection pattern attribute. Discontinuity quantifies the degree to which a seismic trace differs from its neighbors, and identifies breaks in the continuity of seismic reflections that are due to faults, diapers, channels, stratigraphic pinchouts, processing artifacts, or noise. Discontinuity attributes have become essential aids in the interpretation of seismic data for structure as well as stratigraphy. Though continuity computations have a long history in seismic data processing, it was only in 1995 when the first practical discontinuity (or continuity or coherence) attribute was introduced for 3D seismic data interpretation. The original discontinuity method employed two orthogonal cross-correlations with a 3 trace operator. Other methods soon appeared based on semblance, covariance, and image processing edge detection. Enthusiastic claims have been made for the superiority of one particular method over competing methods, but the differences between them owe as much or more to algorithmic details as to fundamentals of the discontinuity computation. In particular, the analysis window size and shape has a large influence on both the quality of the attribute and the computation time. For the same analysis window, methods based on correlation, semblance, principal components, and weighted correlation produce discontinuity attributes that are often indistinguishable. This is not surprising, as these common methods all treat discontinuity as a ratio of discontinuous energy to total energy, and differ only in how they define discontinuous energy. Most methods for discontinuity computation implicitly assume flat data and so tend to perform poorly in areas of steep dip. The standard solution is to determine the dominant dip in the analysis window first, and then to compute discontinuity along this dominant dip. This step often involves considerably more effort than the discontinuity computation itself. While it successfully reduces noise in the discontinuity attributes caused by reflection dip, it also degrades the imaging of small discontinuities to the extent that these discontinuities influence the dip estimation. Nonlinear methods show promise for better estimating the reflection dip in the presence of faults and other discontinuities, but their computational cost is so much greater that at present they are often impractical for routine application. Current efforts to improve discontinuity attributes involve either pre-processing of the seismic data to better condition it for attribute computations, or post-processing of the discontinuity attributes themselves. The methods used are primarily 2D and 3D filters that remove noise and sharpen the seismic data or discontinuity attribute. Postprocessing methods are general in that they can be applied to any discontinuity attribute, though they may be tailored to enhance fault or stratigraphic discontinuities at the expense of other discontinuities. Computationally inexpensive 2D image processing techniques, such as Laplacian operators or Kuwahara filters applied along time slices or along the reflection dip are effective at enhancing the resolution of discontinuity attributes, though they may perform poorly on standard seismic data. Three-dimensional filters employing principal component analysis or some other transform method are more powerful and produce superior results, but require much more computation time. Post-processing with 3D filters is likely to yield the greatest improvement in discontinuity attributes in the near future.
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Application of an Integrated Approach for the Characterization of a Naturally Fractured Reservoir in the West Siberian Basement
Authors Abdel M. Zellou, O. Pinous and E.P.Sokolov and Gary RobinsonStatic modeling of naturally fractured reservoirs is a recurring challenge to many oil and gas companies seeking to manage and develop fractured reservoirs. Several techniques relying on curvature only or on one seismic attribute have been applied in the past to match past production and pressure history that have been proven unreliable. This paper describes the application of the Continuous Fracture Modeling (CFM) approach to improve the simulation of a fractured basement reservoir using seismically driven reservoir characterization. The Maloichskoe field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast. It was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties of the matrix are generally negligible, and the production potential of wells is mostly associated with natural fractures and vugs.
The presented study was our first project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs processing, 2) Spectral imaging and high-resolution inversion of the seismic data, 3) structural analysis of the field, 4) construction of the reservoir properties model, 5) construction of the fracture distribution model using the Continuous
Fracture Modeling approach (CFM). The final geologic model served as a basis to select the locations for the new wells. The new locations were proposed in the zones with the most intensive development of a network of natural fractures (according to the model). The drilling was associated with significant losses of drilling mud that was an indirect indication of presence of significantly fractured zones. The wellbore image FMS that was recorded in the well, showed a good level of correspondence between the model forecast and the actual result. The well contains interval of numerous fractures and large vugs. Eventually, the well showed a good production results and currently is one of the best producers in the field. As such, we recommend application of the described integrated approach for modeling complex fractured reservoirs in the other fields of Russian Federation.
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Spatial and Temporal Variations in Reservoir Geomechanics that Impact Production, Eor, Co2 Sequestration Operations and Field-Wide Well Placement; Case Studies from Southeast Asia
Authors David Castillo, Juergen Streit and Adrian White and Andrew BrehmThere is an arsenal of sophisticated engineering and reservoir tools available to E&P operators designed to serve one primary purpose; maximize production, minimize drilling problems and predict reservoir performance. The purpose of this paper is not to review these sophisticated tools, but rather to add an important factor when faced to evaluate when to use these advanced technologies. In brief, one needs to consider the dynamic characteristics of the earth, specifically, the earth’s stress field operating in your assets.
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Jerneh Full Field Studies – an Integrated Approach to the Identification of New Development Opportunities
By Fariz FahmiThe ExxonMobil-operated Jerneh field is the largest non-associated gas field in the Malay Basin. The field was discovered by the Jerneh-1A well in 1969, and production commenced from the Jerneh-A platform i 1991. Depletion mechanism is via natural depletion with the Miocene primary reservoirs now up to 80% depleted. A multi-disciplinary team was formed in 2003 to study available field performance data and identify further development opportunities. This paper outlines the integrated approach taken by the geoscientists and engineers in the study team to mature new drilling opportunities. Three different types of development opportunities were generated by the team and formed the basis for the 2006 drilling program: 1. Additional resources in the western part of Jerneh were identified through field-wide stratigraphic remapping, incorporating recently re-processed 3D seismic data and integrating available production data. 2. Crestal locations with under-filled reservoirs, together with depleted reservoirs containing gas trapped by GWC movement were identified during recent drilling and logging programs. 3. Re-evaluation of petrophysical analyses shows higher gas saturations in several of Jerneh’s “minor” reservoirs. This has resulted in attractive infill opportunities in these marginal quality reservoirs. The study resulted in an appraisal well and a five-well infill drilling program for 2006. The appraisal well (Jerneh-6) has already confirmed sufficient resources in the western area of the field to justify a new production platform for an additional six development wells. The infill drilling program is ongoing with 3 out of 5 wells completed, with results to date meeting expectations. The application of ExxonMobil’s Fracture Closure Stress (FCS) drilling technique was instrumental in the successful drilling of the recent appraisal and development wells. This technique enabled the successful penetration of multiple severely pressure drawn-down reservoirs without significant fluid losses. The key to the success of the Jerneh Field Study was the multi-disciplinary integration of available geoscience and engineering data. Close collaboration among all the team members was essential in identifying further development opportunities in this mature field environment. A more comprehensive understanding of
the reservoirs was achieved, and forms the basis for Jerneh’s future development plans, including the upcoming Jerneh-B development project.
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Marine Survey Design for Rich-Azimuth Seismic Using Surface Streamers
Authors M.S. Howard and N. MoldoveanuBy combining multi-azimuth and wide-azimuth acquisition methods, we have designed a richazimuth seismic survey for a sub-salt illumination problem at the Shenzi field in the Gulf of Mexico. The survey uses a master vessel with ten 7000 m streamers and two additional source vessels to make two passes in each of three different sailing directions. This gives full-azimuth illumination beyond 6000 m of sourcereceiver offset with rich coverage beyond 8000 m. The expected duration is about 50% longer than a
narrow-azimuth survey requiring infill and undershooting. Our survey requires two source vessels during the entire survey, whereas a standard survey uses one while undershooting. Shooting during the turns expands the coverage area significantly at little cost.
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Integrated Approach to Building a Basin Model for the Red Series, South Caspian Basin
More LessThe Red Series is the most important stratigraphic interval in the South Caspian Basin and plays a significant role in hydrocarbon exploration and production in the region. The Upper Miocene –Pliocene sediments hosts about 80 % of recoverable hydrocarbon reserves in Turkmenistan. In Azerbaijan, to the west of the South Caspian Sea, the equivalent aged section of Red Series is called Productive Series. Over 95% of Azerbaijan’s discovered hydrocarbons are accumulated in Productive Series rocks. Petronas Carigali (T) Overseas Sdn. Bhd. is the operator of Block 1, located in the northeastern part of the South Caspian Sea (Figure 1). To date PC(T)SB has drilled 9 exploration wells in this block since 1999 with substantial oil and gas discoveries. The main exploration target in this block is the Red Series. In 2005 PCSB embarked on a study to building the basin model for the Red Series in the South Caspian Basin. This study is an integrated approach comprising remote sensing analysis, gravity and magnetic interpretation, seismic interpretation, structural reconstruction, sequence stratigraphy, basin modeling, fieldstudy and lab analysis. The aim of the study is to understand the basin formation and processes, the petroleum system, the basin fill model and it is composition in terms of source rock, seal and reservoir distribution. The study is also aimed to facilitate the interpretation of Block-1 offshore Turkmenistan and to reconcile various conflicting models that has been proposed previously on the deposition of the Red Series in the region. This paper discusses the findings of the study. The team concludes that the Red Series were deposited as a prograding delta in the early Miocene to Pliocene times. The Paleo Amu Darya river was the main source for the deposition of the Red Series and transported sediments from the northeast into the South Caspian basin (Figure 2). Rapid sediment influx with differential compaction in the Middle to Late Pliocene generated growth faulting and mud volcanism in the area, which is typical for deltaic settings (Figure 3). While the main sedimentation from Paleo Amu Darya to the southwest into the basin, Block-1 is interpreted to be located at the edge or distal part of the delta. This explained why many wells drilled in Block 1 encountered thick shale
sections in the middle and upper part of the Red Series. The hydrocarbon bearing reservoir sands at the base of the Red Series in Block-1 were believed to be derived from the Paleo Volga river to the northwest of the area with lesser influence from the Paleo Amu Darya. Petroleum systems modeling suggest that the Maykop is the main source rock of the South Caspian Basin and results of 2D migration modeling indicate that the Apsheron Sill is being charged from kitchen areas to the north and south of it.
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Impact of Regional Tectonics on Structure Development in Pm309, Eastern Malay Basin
Authors Anuar B.A. Aziz and S.M. Yu and A. Rahman B. M. EusoffMovement and collision of the Indian-Australian plate on the Eurasian plate has played a major role on the formation of the structural style seen in the Tertiary basins throughout Southeast Asia. The December 2004 earthquake, off northern Sumatra in the Indian Ocean confirmed the high mobility of the plates. The earthquake not only brought about the catastrophic tsunamis that devastated large area of South and Southeast Asia, but its geological effect has also been felt in the eastern Malay Basin in PM309. Geodetic measurement recorded in one of the platform reveals that there has been some lateral displacement. Although the displacement is small and does not impact the structural integrity of the facilities, over geological time, the collective displacements of the collisions has considerable imprint on the geological structures in the sedimentary basins of the area. Based on analogy to plasticene modeling work carried out by Tapponier et. al. (1982), indentation of the hard Indian sub-plate into the soft Eurasian plate, not only caused the deformation and uplift of the Himalaya Range, but also resulted in the extrusion of Indo-China sub-block between the Red River Fault and Three Pagodas Pass Fault. The southeast movement on the Indo-China sub-block in conjunction with the northward movement of the Indian-Australian plate to the west of Sumatra and in the Andaman Sea has caused the presence of a right lateral wrench couple in the region. From the experimental work of Harding (1974), a wrench couple would result in the formation of a set of stress fields that can be depicted on a strain ellipsoid inclined to its direction of wrenching. Compression or folding will be set up in the shorten axis while extension or normal faulting will occur in the lengthen axis of the strain ellipsoid. Further, there will be two sets of strike slip faults formed, a synthetic right lateral set at an oblique angle and its conjugate antithetic left lateral set at near-perpendicular to the wrench direction. Work carried out by PCSB has revealed the presence of a series of grabens and half grabens bounded by N-S striking faults in the Malay Basin. Block PM309 is located in the Eastern Graben of the Malay Basin (Suhaileen 2006, personal comm.). Recent 3D seismic surveys acquired in PM309 have better our understanding on the fault systems in PM309 and the eastern Malay Basin. Within Block PM309, interpretation of the seismic data not only confirms the presence of major compressional features running in the east west direction which form the traps of the many large oil and gas fields in the Malay Basin, it also shows the presence of a system of strike slip faults in the area set up as a result of the right lateral couple directed to the area. The right lateral synthetic strike slip faults predicted in the strain ellipsoid, is represented
by the NW-SE right strike slip faults present in the western part PM309. Its antithetic NE-SW left lateral strike slip faults is present in the eastern part of the block. A set of N-S faults is also prominent in the western part of the block, its origin probably extensional, as predicted in the strain ellipsoid, but over geological time, has seen reactivation and taking up some of the right lateral movement and imparting the NW-SE orientation of the Malay Basin.
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Orogeny in Action: Tectonic Evolution and Stratigraphy of Sabah, Seismic and Outcrop Evidence
More LessThe diverse structural trend and depositional framework of Sabah (North Borneo) were contributed by several regional tectonic events occurred since the early Tertiary. The diverse and complex structure resulted from several episodes of deformation. 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). The Late Eocene tectonic deformation is characterized by folding and thrusting of basement rock and older paleogene sediments i.e. Rajang-older Crocker fold-thrust belts. The Paleogene regional tectonic setting of Sabah seems to be very complex with southeasterly subduction in the NW Borneo, and extension in the SE in the Celebes Sea and Makassar Strait (Hall 1996, 1997). The Paleogene appears to be a period of continued deposition of deep marine turbidites. The probable Late Eocene regional uplift was suggested by Hutchison (1996) as the Sarawak Orogeny which is related to the collision of the Luconia Continental Block. The palaeontologically dated Upper Eocene unconformity is found only in the onshore Sarawak area (Tatau Horst) between the Tatau and Belaga Formations (Wolfenden 1960, Haile and Ho 1991, Hutchison 1996). The Early Miocene (BMU, 22-20Ma) deformation is interpreted to mark a major tectonic event, causing formation of the mélanges, major uplift and erosion which produced the Base Miocene Unconformity (BMU). This was followed by a change in depositional environment from deep-water to a shallow deltaic setting (Balaguru 2001, Balaguru et al. 2003, Van Hattam 2005). Patches of limestone (Burdigalian age)
formed during this uplift. This tectonic event is related to subduction and collision of the Dangerous Ground Continental Block to the NW Borneo and referred as the ‘Sabah Orogeny’ (Hutchison 1996). This uplift has particular significance since it provided a nearby and abundant sediment source from the Middle Miocene onwards which explains the tremendous thickness of rapidly deposited Middle to Upper Miocene sediments found in the surrounding basins. This unconformity which should be the real deep regional unconformity is here been referred as pre-DRU (Deep Regional Unconformity) to avoid any confusion. The Late Early Miocene (~19-20Ma) marked the NW-SE direction of rifting of the Sulu Sea interpreted to have rejuvenated the Central Sabah Basin with regional extension and subsidence, and initiated rift basins as part of the formation of the Sulu Sea in a back arc setting (Balaguru et al. 2003 and 2004, Nichols et al. 1990). The rift basin with coeval onshore extension became depocentre for the Stage III deltaicshallow marine deposition of the Tanjong Formation in the east and Meligan/Setap Shale Formation in the west of Sabah. Middle Miocene collision of another arc-continent collision in the northern Borneo between the Cagayan Arc and Palawan micro continental block (Rangin 1991) caused another Middle Miocene Unconformity (MMU, 15.5Ma) has been referred to mark the Deep Regional Unconformity (DRU) in Sabah. This deformation caused inversion of the early Middle Miocene sediments. The early Late Miocene Kinabalu emplacement plausibly marks the Intermediate Regional Unconformity (IRU, 10.6Ma) in Sabah. The Late Miocene (SRU, 8.6Ma) tectonic event marks another major folding and uplift which can be correlated as the Shallow Regional Unconformity (SRU) of this region (Bol and Van Hoorn 1980, Levell 1987). This latest phase of major tectonic event caused by NW-SE trending strike-slip faulting and transpressional fault movement in this region (Balaguru et al. 2003). Continuous transpressional movement resulted in major structural inversion and uplift most of the southern and eastern parts of Sabah where the Miocene strata now are exposed onland with a highest point at 1500 m (Gunung Lotung) above the sea level. This event is here termed the Meliau Orogeny. The transpressional movement along the major strike-slip faults in this region would better explain the structural development in these areas. It probably continued during the Late Pliocene and another unconformity can be picked at 5.2Ma, and is possibly related to propagation of deformation from Sulawesi towards NW Sabah. The Late Pliocene strike-slip deformation is regionally significant and occurred at similar time as important deformation in NE Kalimantan, Sulawesi and NW Sabah. This transpressional movement is interpreted to be the cause of the major orogenic deformation, uplift and final structural development in Sabah region and possibly continued to the present day. Young extension in Sabah is indicated by the presence of post-inversion extensional faults. Extensional faults commonly occur within the Upper Neogene to Plio-Pleistocene sediments. These faults are interpreted to be significant as they caused a repetition of sequence and indicates a period of relaxation during the Quaternary after the major transpressional tectonic event and uplift. The latest extensional faults have modified the older strike-slip related structures within the Neogene sediments and possibly have widened the original synclines and the ‘circular basins’ which is a remnant of a large proto-basin (Balaguru et al. 2003).
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Beyond Kirchhoff: New Technologies for Improved Seismic Imaging
Authors Graham Hodgkiss and James SunThe Kirchhoff algorithm is a standard tool for imaging subsurface structures. These methods are efficient, versatile and can produce accurate images in moderately complex geology. As the drive to image hydrocarbon reservoirs moves to increasingly complex areas, the limitations of Kirchhoff algorithms become evident. Typically, these limitations include: use of single-arrival travel times, ray-paths computed with a high-frequency approximation, anti-alias filters that can only be correct for a single dip angle. These
limitations further complicate the demanding problem of preserving the amplitude response. The Kirchhoff algorithm can be enhanced; for example using multiple-arrival travel times or using band-limited travel times. However, such improvements can only incrementally improve the image quality and at great cost to algorithmic efficiency. Recent years have seen exciting developments in both imaging algorithms and computer hardware. These have lead to the implementation of alternative methods that can potentially overcome the limitations of Kirchhoff particularly those where multi-pathing is an issue. New imaging technologies based on solutions to the wave equation have provided significant improvements in areas with complex geology. For example, Wave Equation Migration (WEM) has become routine in areas such as sub-salt exploration in the Gulf of Mexico and is now also providing benefits in other exploration areas. Another technique, Beam Migration is based on wavefield continuation. The method retains strengths of Kirchhoff migration such as steep dip and anisotropy handling, but can also image multiple arrivals. Finally, a solution based on the full 2-way wave equation has recently been implemented. Although at an early stage of development, this Reverse Time Migration promises highest fidelity images in the most demanding situations. In this paper, we describe each of these migration methods and show examples of their use on synthetic and field data.
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A Comparison of Laminated Sand Analysis Methods – Resistivity Anisotropy and Enhanced Log Resolution from Borehole Image
Authors Michel Claverie, Hisham Azam and Richard Leech and Graeme Van DortLaminated and thinly-bedded sands have become an important target of exploration offshore Malaysia. In such reservoirs, the vertical resolution of standard logs is usually insufficient to allow the direct measurement of the properties of each individual thin bed. In particular, the resistivity of thin sands is reduced by the high conductivity of silt and clay laminations, and a conventional petrophysical analysis of these sequences may underestimate the hydrocarbon volumes. Solutions to this problem require to record high resolution logs, to further enhance log vertical resolution with special processing methods, and to use adapted interpretation methods. We describe in this paper 2 methods of Laminated Sand Analysis (LSA): • Resistivity Anisotropy: this method consists in the measurement of vertical and horizontal resistivities to calculate the true resistivity of the laminated sand and silt/clay layers. The volumes of hydrocarbon in the sand and the silt/clay fractions are summed up to obtain the total hydrocarbon volume in the
laminated sand. • Log resolution enhanced by borehole image: this method uses bed geometry information from a high resolution borehole resistivity image to invert for the true log responses in each layer. The high resolution squared logs are processed in a petrophysical solver to calculate the various reservoir properties, including the hydrocarbon volume of each individual thin bed. These 2 methods of Laminated Sand Analysis are performed on log data from Malaysia, and the results are compared to a conventional evaluation. The range of application of these methods is discussed in relation to the geometry and texture of thin beds.
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Rock-Matrix Adsorption Effect on Hydrocarbon Expulsion in Masjid-E-Solieman Oilfield, Sw Iran
Authors B. Alizadeh and S.H. Hosseini and H. GhalavandThe analysis of organic materials in sedimentary source rock is critical to interpreting their geology and petroleum-generation potential. The most readily available data on such organic materials are obtained by whole-rock Rock-Eval pyrolysis. For present study Masjid-e-Soleiman (MIS) oilfield in SW Iran, which is the first oilfield discovered in Middle East, was selected. Out of 314 producing wells drilled so far, 11 wells are drilled deep to the Sargelu Fm. at the depth of 15000 ft. Sargelu Fm. belongs to Middle Jurassic period with 200m thickness and comprises rich carbonaceous shales. Kerogen present in the studied Fm. as the major organic component is analyzed by Rock-Eval pyrolysis. Plotting the data on graph of S2 vs. Total Organic Carbon (TOC), and determining the regression equation is the best method for determining the true average hydrogen index and measuring the adsorption of hydrocarbon by the rock matrix. Such a plot also indicates the type of kerogen present and avoids the problem of increasing hydrogen index with total organic carbon content. With the S2 vs. TOC diagram, the organic component of different suites of samples may be compared and their petroleum generation potential established. Here the diagram is used to evaluate the sedimentary
environments and petroleum potential of the Jurassic carbonaceous shales of MIS oilfield in Zagros basin of Iran. The results reveal that comprised organic matter is of type III-IV mixed kerogen. This indicates oxidizing environment of deposition and explains the reason of high gas generation potential of the oilfield. The regression line in the S2 vs. TOC diagram which should pass the origin, has got either negative or very small intercept on the x-axis. This means that there is very low adsorption effect of rock matrix and this confirms and authenticates the carbonaceous nature of the studied shales. The amount of TOC was as high as 11.33 wt%. Major part of the organic content is inert due to terrestrial environment of deposition, at the same time high gas generation potential of this formation is due to its very high TOC content.
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Reservoir Properties and Depositional Environment of The Group M Cored Interval in Ledang Tengah, Block Pm309, Malay Basin
The early Oligocene Group M sandstone is relatively under explored in the Malay Basin but as exploration matures, the M group sandstones will be increasingly be targeted. The M group reservoirs in the Ledang-Anoa Field will be the oldest clastic reservoir in the Malay Basin to be developed. The Group M sequence forms part of the rift sequence and have been interpreted to be deposited within a continental setting in an alluvial-lacustrine environment. To determine the depositional environment, reservoir quality and identify the controlling factors in the reservoir quality variations, several cores were taken from the lower part of Group M, informally named as M40, M60 and M70 sandstones from the Ledang Tengah ST-1 well. From core descriptions and facies analysis work, supplemented by wireline log interpretations, the depositional system is interpreted to be a braid delta of McPherson et. al (1987). The braid delta system is characterised by progradation of a braided fluvial system into a lake. Depositional environments within this braid delta system composed of braided fluvial channels and in-channel bars, lacustrine mouthbars, palaeosols and open lacustrine muds. The almost complete absence of scour and fill structures (except for the base of the M70 core) that are common in many fluvial deposits is unusual and would suggest channel widening rather than channel incision as the main sedimentary response to fluctuating flow conditions. The sand bodies are thus likely to be aerially extensive and sheetform in geometry. Limited core and cutting samples have been analysed palynologically. In general, palynoligical recoveries were poor although samples were generally rich in organic debris. Terrigenous miospore assemblages were dominated by freshwater herbaceous swamps and cosmopolitan pollens. Mangrove taxa and savannah grassland pollens were rare. The high abundance of organis debris and highly degraded humic material indicated persistent soil erosion and deposition in a stagnant water, with brief periods of increased
freshwater run-offs marked by influx of freshwater algae and increase in miospores abundance and diversity. The absence of hinterland pollen species generally confirmed the reduced freshwater circulation and transport. Variations in reservoir quality in the cored section is controlled by primary factors, with sandstone grain size and clay content the dominant factors. However, the sandstones are generally texturally and compositionally immature. Although quartz and carbonate cements are present, the presence of authigenic kaolinite and to a lesser extent illite the results of secondary diagenesis, destroyed the primary permeability and rendered the quality of the sandstone reservoir poor. The best quality reservoir is associated with the coarsest grained and the more massive portions of the channel fill and delta mouthbar sandstones.
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Sequence Stratigraphy of Blocks 102 & 106, Song Hong Basin, Vietnam
Authors Jaafar Unir and Othman Ali MahmudBlocks 102 & 106 are located in the Song Hong Basin, offshore Northern Vietnam in a water depth of 25 to 30 meters (Figure 1). Petronas Carigali Oversea Sdn. Bhd. (PCOSB) is the operator with a 50% interest. Other partners are PIDC (20%), SPC (20%) and ATIP (10%). Two dry wells have been drilled in Block 102 by the previous operator. In 2003 PCOSB drilled Yen-Tu 1X well in Block 106 with minor oil and gas discoveries and second well drilled in middle 2006 turned out to be dry well. A working petroleum system is believed to be present in the basin with couple of minor discoveries have been made in Blocks 102 & 106 and surroundings. As proven by the discovery of Yen Tu 1X and B10-STB-1X, source rock potential has the least risk. The lacustrine shale
deposited in the Oligocene syn-rift setting is believed to be the main potential for oil prone source rock. In addition, the early Miocene shallow marine shale and coal shows a good potential in generating oil and gas. In April 2006 XTG/XBS, PCSB carry out
Sequence Stratigraphic Study of Blocks 102 & 106 with the objective to understand the tectonic setting, basin formation, depositional model and the petroleum system of the area. In addition, this study aimed to answer the issue of correlation between Pretertiary Carbonate penetrated by Yen Tu 1X well and the exposed carbonate hills in Ha Long Bay (Figure 2). The correlation is crucial to establish analogue to the subsurface carbonate reservoir in Blocks 102 & 106. Plate tectonic reconstruction and geodynamic evolution shows that the Song Hong basin is a rift basin that formed in the late Eocene/Oligocene time. The basin formation and evolution is very closely related to the strike slip movements of the Red River Fault Zone. The basin has undergone a series of compressional and inversions events that provides the main structural framework for hydrocarbon trapping mechanism in the area. The study has identified eight sequence boundaries that separated the depositional package into eight sequences (Figure 3). The first package in the early Oligocene sequence is believed to be deposited in the lacustrine setting that provides the main potential source rock in the area. Seismic data and mapping shows that quite widespread of lacustrine setting during the early stage of the rifting that sufficient enough to have big lakes with low energy environment to be conducive for the deposition of good source rocks. The sediment inputs for lacustrine setting interpreted to be sourced from a multiple directions. However, during the early to late Miocene the deposition was controlled by marginal to shallow marine environments with the main sediment supply comes from the Red River in the northwest.
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Submarine Mass-Transport Deposits in The Semantan Formation (Triassic), Central Peninsular Malaysia
By Mazlan MadonTriassic sedimentary rocks in the Central Belt of Peninsular Malaysia represent syn-orogenic sedimentation associated with the eastward-subduction and closure of the Palaeo-Tethys Ocean. This deepmarine “flysch” succession, of middle-upper Triassic age, is mapped as the Semantan Formation over much of central Pahang. The Semantan Formation consists of predominantly thin-bedded sandstone-mudstone facies, deposited in mud-dominated submarine fan systems. Individual turbidite beds are rarely thicker than 1 metre thick. Relatively fresh exposures of the Semantan Formation along the Karak-Kuantan Highway have given new insights into the sedimentary processes in the Triassic flysch basin. A change from distal to proximal facies eastwards between Karak and Maran indicate west-facing, active continental shelf-slope sedimentation. Hence, outcrops between Karak and Temerloh, east of the Bentong-Raub suture is characterized by “classical” flysch-like, thinly-bedded sandstone-mudstone facies, but west of Temerloh, and nearer to the paleo-shelf and slope, more sandy facies and thick-bedded turbidites occur. A fine example of proximal deep-marine facies association in the Semantan Formation is exposed at the Chenor Junction (Exit 821), kilometer 139 along the highway. South- and north-facing cuts on either side of the highway reveal interesting sedimentary features, which include large slide blocks (megaclasts), slumps, debris flow deposits, and associated syn-sedimentary thrust faults and glide surfaces. These features are strongly indicative of large-scale submarine mass-transport processes on the paleo-slope of the Triassic active margin. The Chenor mass-transport complex is made up of zones of incoherent slump deposits intercalated with well-bedded turbidite/debrite facies. In the lower part of the succession, there are at least two large blocks or megaclasts of sandstone-mudstone facies, measuring several metres in size, are encased in silty matrix. Along with other smaller sandstone blocks, these megaclasts are interpreted as slide blocks derived from slope failure up-dip of the basin plain. The internally stratified sandstone-mudstone blocks are strongly deformed internally by numerous meso-scale normal faults, which are evidently formed by ravitationally induced extensional deformation. Plastic deformation is also evident from the slump-related soft-sediment folds within the muddy matrix. Besides the chaotic “broken beds” and slump blocks, there are gravity-induced structural features such as rotational slumps, glide surfaces, thrust faults and associated soft-sediment folds. The slump folds and thrusts show vergence to the west, in the opposite sense to the tectonic vergence observed at other outcrops. A few of the well-stratified units show strongly inclined stratal surfaces, which may be attributed to lateral accretion of turbidite sand-lobes. Several sets of these inclined surfaces are bounded by erosional surfaces, which could have resulted from different episodes of turbidity flow. The association of incoherent mass-flow units with the better-stratified deposits reflects the close spatial and temporal relationship between submarine mass-transport processes and turbidity flows on the active Triassic paleo-slope and basin plain.
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Seismic Rock Physics of The Miocene Carbonates: A Case Study from The Central Luconia Province, Sarawak
Due to increasing importance of oil and gas recovery and the growing realization that Luconia carbonate reservoirs are more heterogeneous than assumed in the past, rock physics analysis was employed to get better understanding on the relationship between the seismic properties of reservoir rocks (i.e velocity, density, rigidity) and their production properties (i.e facies, porosity, fluid type and saturation, pressure). Based on the analysis of 40 selected core samples from two fields in Central Luconia Province, the
followings conclusions can be drawn: 1. For general discrimination of tight and more porous facies, the best elastic property to be used is Lambda-Mu-Rho and Vp. Tighter facies associates with higher Lambda-Mu-Rho and Vp. Conversely more porous facies associates with lower Lambda-Mu-Rho and Vp. 2. For details facies-based discrimination of the porosity types (i.e chalky/mouldic limestone, sucrosic dolomite, argillaceous shale, tight limestone), the best elastic property to be used is Mu, Rho, SImpedance
and Vs. Log data cross-plot analysis shows that the use of Vp, AI and density are also possible but with more ambiguity. 3. For lithological discrimination, the Vp, AI and density can be used. However, the best result is obtained when S-Impedance, Mu or Mu-Rho are assigned. 4. For brine, oil and gas pore-fluid discrimination, the best elastic properties are Mu and Mu-Rho. Brine has the biggest Mu and Mu-Rho values, followed by oil and gas. 5. The type of matrix is generally calcite, whereas dolomite acts as grains. The abundance of pore types in descending orders is mouldic, vuggy, intercrystalline and fracture pores. 6. For pore and effective pressures identification and monitoring, the most sensitive elastic property is Vp. The presence of two gradients of pressure changes indicates the possibility of dual porosity. 7. For porosity determination, Vp and AI can be used. Bigger porosity associates with lower Vp and AI. Conversely, lower porosity associates with bigger Vp and AI. The Vp and AI can be obtained by applying Post Stack AI Inversion. 8. The time-lapse seismic analysis shows that time lapse seismic is feasible to be employed to monitor the changes of water saturation and pore pressure. The decrease of water saturation degree and the increase of pore pressure will slower the seismic wave velocity, extend the travel time and decrease the amplitude of first break. 9. Log cross-plot analysis reveals that Vp and AI can be used to discriminate lithology and pore fluids. The Vp and AI of carbonates are higher than the shales. The Vp and AI of water are higher than the gas 10. AVO analysis shows that Vp-Vs relationship is linear and the best-fit equation lines will be different at different pressure conditions. Increase of pore pressure will decrease the Vp and Vs linearly. Conversely the increase of overburden pressure will linearly increase the Vp and Vs. The Vp-Vs gradient change resulting from the change of pore pressure is bigger than the change due to overburden pressure. 11. AVO class cross-plot analysis shows that the type of carbonate AVO is class III. However, brine and gas condition cannot be discriminated using AVO intercept and gradient since their values are overlapped.
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Regional Controls on Carbonate Developments in Central Luconia, Offshore Sarawak
Authors M. Razali Che Kob and M. Yamin AliThe Central Luconia province in the offshore NW Sarawak is a stable platform, flanked by two areas of active deltaic sedimentations. It is characterized by extensive development of carbonate which started in the Early Miocene through Late Miocene. Up to present, more than 200 Miocene carbonate build-ups have been mapped and some 70 have been tested (Hutchison, 2005; Vahrenkamp et al, 2004, Epting, 1980). The Central Luconia is part of the present-day Sunda platform, and forms its NE shelf edge. It is
located in an intermediate position between areas of subsidence and faulting in the north and zones of pronounced compressional tectonic in the south. It is separated from the Baram delta province by a shear zone associated with the West Baram Line in the NE, and to the SW is the Penian High. Together with other structural provinces of Sarawak, the Central Luconia is believed to be an integral part of the Sundaland and is interpreted to be underlain by the continental basement (Hutchison, 2005). The Sarawak basin as a whole was formed as a result of NW-SE trending right-lateral fault movement during the late Oligocene-Miocene times (Ismail, 1997). This dextral movement is thought to be responsible for creating the NW-SE trending paleo-highs and lows and had also positioned the paleo-coastline in the same trend. However, due to fluctuating nature of the sea levels and tectonic tilting, these coastlines appeared curvy during most of the lowstand sea level phases. Structurally, the Central Luconia appears to have been rotated in counter-clockwise direction. The block is bounded by shear zones, associated with a dextral-wrench movement along the West Balingian line. Beside this, a few dextral-wrench faults propagated in the same trend were described by Ismail (1997),
namely, the Mukah Line, Igan-Oya line and others. It is likely that the Central Luconia formed the central part of the rotated blocks. Recent study on regional seismic lines indicates that the Central Luconia has undergone extension during Middle Miocene and was followed by continuous compressional phase for most of the Middle to Late Miocene. During the extensional and the subsequent isostatic readjustments, the Central Luconia was a depression bounded by the uplifted regions which formed the basin edges in the SW, south and SE. Areas in proximity to the main uplifted region in the east were dominated by clastics, whereas, the carbonate occurred on the rifted margin in the west associated with the rising of sea levels. The subsequent compressional tectonic had resulted in inversion and folding of the basin-fill strata. This phase was responsible for elevating the Central Luconia region and characterizing it with widespread presences of tight anticlinal folds. These folds formed the ideal sites for widespread carbonate growth during high sea level phases of the latest Middle Miocene to Late Miocene. The fluctuating low sea level phase of the Late Miocene had punctuated the buildups by karstified surfaces that indicate subaerial exposures and had demised some of it. With exception of a few buildups, most were drowned during the major sea level rise at the base of Pliocene.
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Lithology Discrimination through Velocity Analysis – A Solution trough Method
In this paper, we have implemented the technique to a study area that was located in deep water and seven geological stratigraphic units were used for velocity analysis. Issue arises when we tried to tie the stratigraphic units to well markers. A thin stratigraphic unit is prominent in the seismic section but not being interpreted in the well as a unit (Figure 2). We expect that this thin layer will create variations in the provelocity analysis within the target location. Due to the variations, checkshot seemed to be inaccurate in
further calibrating for time-to-depth conversion below the thin sedimentary layer. A study of solution trough has been applied with the composite displays of the solution troughs indicate that within the top and the second uppermost units, there is clearly inconsistency in stratigraphic unit parameters.
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Drilling of Deep-Seated Reservoir in High Pressure Regime in the North of Malay Basin
More LessPMU Petronas has taken initiative drilling wells in high exploration risk areas such as deep-seated high pressure and high temperature (HPHT) reservoirs, since 1996. PMU drilling campaign in the deep-seated and high pressures wells has resulted a few field discoveries, such as Bergading Deep, Sepat Deep and Guling Deep-1 wells. The challenges of drilling deep-seated and high pressure wells gives us a significant experiences in predicting the abnormal pressures and handling the well operations especially while drilling through the critical zones within the leak-off pressure limits. (figure 1). In drilling high-pressure wells in Malay basin, we had an experiences of having severe losses of the mud, well kicks and operational difficulties such as stuck pipes, hole stability and hole caving while drilling of the well. Of course, surrounding well information such as formation pressures, velocity, well logs will help geologist and drilling engineer in designing the well, determined mud recipes, bit types and prediction of pore pressure. All these preparations are very important, prior to drill and while drilling the well to ensure the success of drilling and safety of the personnel onboard. In the drilling of deep reservoir well, pressure prediction is very important to be carried out. The data from nearby wells has to analyze in predicting abnormal pressure such as seismic velocity, formation pressures from RFT/ MDT, mud weight were used from nearby wells, porosity, density and well log curves. The good data would predict the presence of abnormal pressure based on the deviation on porosity trend, density and reversal of velocity data with the increase of depth. The understanding of the mechanisms of overpressure is very crucial in predicting the overpressure pressures. The mechanisms of abnormal pressure in Malay basin were observed mainly due to the following reasons;
i) Under compaction or overburden – at the center of the basin
ii) Uplift – tectonic compression and structural inversion
iii) Inflation or late over pressuring – at the basin flank
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The West Crocker Formation Outcrop at Kingfisher-Sulaman, Kota Kinabalu: Sedimentary Features and Facies Succession
More LessA section of the West Crocker Formation (Oligocene-Lower Miocene) is spectacularly exposed at the Kingfisher-Sulaman residential district, along Jalan Sulaman, north of Kota Kinabalu in West Sabah. The ground clearing for the development project has exposed more than 200 m of deep-marine succession. This outcrop is one of many exposures that are the subject of an ongoing collaborative research by Petronas Research and Universiti Sains Malaysia. Some preliminary findings are presented in a separate presentation at this conference (Mohd Nizam et al., 2006). This poster is pictorial tour of the outcrop, arguably one of the best exposures of the West Crocker Formation. Over 230 m of steeply dipping, medium to thick-bedded sandstone and mudstone are exposed on the cut slopes of this outcrop. The sandstone facies is predominantly fine grained, though some are medium to coarse, and even pebbly (granular) in places. The beds range from a few 10s of metres to more than 30 m thick. Many have sharp tops and bases, the latter often erosive. Internally they appear to be structureless, though faint consolidation lamination or dish structures are quite common. Some beds have well-developed load and flame structures. Flute marks and rip-up clasts are also common, indicative of the erosive nature of the depositing flows. There are some thin turbidite units (< 1 m) with graded bedding and Bouma subdivisions, but these do not appear to be very common. A most spectacular feature of this outcrop is the occurrence of a slump interval at the top of the succession, consisting of several large (metre-scale) sandstone blocks “floating” in a muddy matrix. The succession may be subdivided into four main intervals, comprising coarsening-upward and fining-upward parasequences. The lowermost interval, comprising five fining-upward cycles, represents eposits of a channel complex. This is overlain by a sand-dominated interval interpreted to be middle to lower fan lobe complex. The third interval is a simple, fining-upward parasequence, which is thought to have been deposited within the upper fan/slope channel. The uppermost interval is mud-dominated and characterized by the presence of large sandstone blocks in shale, which is interpreted to represent muddy inter-channel/slope deposit. Most of the sandstone units in the Kingfisher-Sulaman outcrop were probably deposited as highdensity flows (debrites) rather than turbidites. The sandy nature of the succession and the preponderance of debrites and slump features suggest that the succession represents part of mass-transport complex in a slope or base-of-slope setting.
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Low Co2 Potential Hydrocarbon Block Sk 301, Rajang Delta, Offshore Sarawak
More LessBlock SK 301 is open block, located in the Rajang Delta shelf, offshore Sarawak, East Malaysia PMU offers an opportunity to acquire interest of this highly prospective block. This presents a chance to acquire a position in one of the most dynamic, rapidly-expanding theatres of SE Asian E&P, in the virtually unexplored, large Rajang Delta which contains only four exploration wells and one delineation well within a 8164 sq.km area. One of the wells (L4-1x, Shell, 1970) is a proven gas discovery, with reserves estimated to be in the order of several hundred BCFG and which also has the potential for oil, as both L4-1x and delineation well Hibiskus-1 (Idemitsu, 1988) had oil shows. Last contract terms handed by YPF Repsol Malaysia were improved during the late 90’s by Petronas, and together with potential access to nearby producing infrastructure and with benign operating conditions and shallow water depths (+/-100 -150 m), the area has favorable economics. I2 wells drilled by YPF Repsol (Sook-1/st and Laya–1, 2003) penetrated good gas shows in undeveloped sands.
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Sedimentary Facies and Depositional Framework of the Tertiary West Crocker Formation around Kota Kinabalu, Sabah
Authors Nizam A. Bakar and Abdul Hadi Abd Rahman and Mazlan MadonThe Oligo-Miocene West Crocker Formation in Sabah has been interpreted as part of an extensive, unconfined submarine fan system, but a detailed description of the sedimentary facies are lacking. This paper describes the sedimentary facies and their relationships, based on a study of eight major outcrops of the West Crocker around Kota Kinabalu, Sabah. Seven sedimentary facies have been identified. Facies A - pebbly, medium-to coarse-grained, amalgamated sandstone. This facies consists of poorly sorted, massive (structureless) sandstone beds with thicknesses ranging from 1 to 38 m. This facies generally have a very high sandstone-to-shale ratio. The bases of sand commonly have flame and load structures. Mud clasts and rip-up clasts are common, with rare carbonaceous and sandstone clasts. Facies B - fine- to coarse-grained sandstone, generally massive, moderately to poorly sorted, and has post-depositional dewatering structures, e.g. dish structures and pipe marks. It has a lower sandstone-to-shale ratio compared to Facies A. Rip-up mudclasts and sole marks, such as flute and tool marks, are common at the base of this facies. (iii) Facies C - composed of sharp-based, graded beds, which may form complete Bouma sequences. The sandstones are commonly laminated or crosslaminated. (iv) Facies D - parallel laminated, very fine- to medium-grained sandstone, and shale. It may be organized into Bouma sequences, but with the Ta division absent. (v) Facies E - fine- to coarse-grained thinbedded sandstones, occasionally with climbing ripples, lenticular bedding, and intraformational rip-up clasts. Trace fossils are common, and include Nereites, Spirorhaphe, Megagrapton, Paleodictyon, Cosmorhaphe and Helminthoida. (vi) Facies F - “chaotic” shale-rich units with slumped beds and syn-sedimentary folds; and (vii) Facies G - consist of fine-grained, pelagic and hemipelagic deposits. These facies are organized in facies associations that represent different deposits of the submarine fan system. These are: (i) slope deposits – dominated by facies F and G, with subordinate facies A and B; (ii) channel-fill deposits - generally showing upward-thinning and upward-fining packages, in which facies A, B, C and D are dominant, with minor occurrences of facies E and F; (iii) levee or overbank deposits - dominated by shale with very thinly bedded sandstone, showing thinning-upward packages and dominated by facies E and G, with minor facies F; and (iv) lobes or sheet sands – comprising coarsening-upward packages, 15-30 m
thick, and are characterized by facies A, B, E, and G, with minor Facies F.
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