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PGCE 2011
- Conference date: 07 Mar 2011 - 08 Mar 2011
- Location: Kuala Lumpur, Malaysia
- Published: 03 July 2011
61 - 80 of 104 results
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An Organic Geochemical Approach to Address Stratigraphic Issues: A Case Study of the Layang-Layangan Beds, Labuan Island, Nw Sabah Basin
Authors Patrick Gou and Wan Hasiah AbdullahThe three main geological units on Labuan Island which is located within the NW Sabah Basin include the Temburong, Setap Shale and Belait Formations. The Temburong Formation (deep marine turbidites) is the oldest, followed by Setap Shale (outer neritic to littoral) and Belait Formations (fluvial and shallow marine). The sediments are generally divided into two phases of sediment deposition by a major unconformity known as the Lower Miocene Te5 unconformity (after Brondijk, 1962), or more popularly referred to in the petroleum industry as the Deep Regional Unconformity, or DRU (Levell, 1987). This study is centred on the Layang-Layangan Beds that lie beneath the sandstone and conglomerate ridge of the fluvial Lower Belait Formation. Previous authors have assigned the Layang-Layangan Beds to all of the three major geological formations on Labuan Island; Belait Formation (Wilson & Wong, 1964; Lee, 1977; Albaghdady et al., 2003), Setap Shale Formation (Liechti et al., 1960), and Temburong Formation (Madon, 1994). This confusion is not surprising as the Tertiary sediments in the NW Borneo region can be very difficult to tell apart based on field observations or conventional geological methods alone. Geochemical results from the analyses of the Labuan sediments, which included thermal maturity related-data derived from Source Rock Analyzer (SRA), organic petrography and gas chromatography-mass spectrometry (GC-MS) were able characterise the different sediments as each of them have significant differences in their geochemical properties to produce unique geochemical profiles. The Layang-Layangan Beds display similarities in its geochemical profile with the overlying Belait Formation, while the Temburong Formation has a different and distinct geochemical profile
compared to the Layang-Layangan Beds and Belait Formation. However, the Setap Shale and Temburong Formations are geochemically quite similar to a certain extent. Consequently, the existence of the DRU on Labuan Island that is thought to separate the
Layang-Layangan Beds and the Lower Belait Formation is put into question since this regional unconformity surface is supposed to represent a drastic change in depositional environment (deep marine to fluvial), which appears to be a lot more subtle and gradual as indicated by the geochemistry data. The geochemical analysis workflow to characterise outcrop geology as demonstrated in this study is relatively cheap and simple, and should be considered when other geological methods do not give convincing results. In addition to that, it serves as a good and reliable independent method to verify ambiguous geological interpretations.
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Sedimentology of Laayoune-Dakhla Area Western Sahara Desert, South Morocco
Authors Zulfiqar Ali and Zainal Abidin B. JuniDirection des Resources Hydrauliques (DRH) drilled water well in Boujdour N° ANGER 1181/120, located at approximately 2.7 km in the North-East of Boujdour and at 50-100 m in the east of the Laâyoune-Boujdour road; Western Sahara Desert, Morocco. On test oil was encountered along with water, as a direct result PETRONAS Carigali Morocco Sdn Bhd. in collaboration with state owned oil company ONHYM decided to evaluate this area geologically for its hydrocarbon potential. The aims and objectives of the study were to carryout detailed sedimentological and basin modelling study to determine the depositional environment of expected reservoirs, hydrocarbon generation, migration and accumulation within reservoir horizons. But here we will discuss only
sedimentology of the basin that will explain reservoir characterisation, distribution and geometry within the study area. Sedimentological investigation was planned in onshore Laayoune-Tarfaya area, in-order to understand the reservoir distribution, facies interpretation and depositional environment of major synrift and post rift mega sequences.
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Echinoderm Palaeoecology from Fragments: A tool for Facies Recognition in Mesozoic Carbonate Sequences
More LessEchinoderms such as crinoids (sea lilies), are a major component of the marine benthos from the late Palaeozoic onwards, where they occurred in such high number so as to be rock forming. On death echinoderms will typically disarticulate into many thousands of ossicles which are considered by many palaeontologists to be indeterminate (Benton and Simms 1995). Research into Mesozoic fossil crinoids has demonstrated that there is currently a lack of understanding of their environmental palaeoecology. This is in part due to taxonomy based soley on exceptionally preserved whole specimens. Thus it has become necessary to consider fragmentary ossicles in defining a more representative palaeoecology. Bulk sampling (10 to 40 kg) of Middle Jurassic (Bathonian) carbonate and muddy sediments of England, where marine environments ranging from open shelf to lagoon are represented, has yielded numerous crinoid ossicles. Extensive work on exceptionally preserved Middle Jurassic crinoids from northern Switzerland and British Lower Jurassic has enabled identification of crinoid ossicles from the English Bathonian to generic level (Hess 1975). Results indicate that the colonisation patterns of crinoids are strongly influenced by facies type, allowing the community structure of the crinoids to be clearly defined in ecosystems delineated by substrate type and degree of marine connection. Thus distinct crinoid communities, based on the presence and absence of generic indicators, can be deduced (Hunter & Underwood 2009). After being successfully developed, the ‘crinoid model’ was taken a stage further, with its application to three more echinoderm groups: echinoids (sea urchins), asteroids (starfish) and ophiuroids (brittlestars). Previously it was noted that lack of homology in the ossicles made identification beyond family level problematic within these groups. As with the crinoids, examination of complete specimens in museum collections has allowed the recognition of diagnostic ossicles that can identify tests, spines and marginal plates to generic level. These new data has allowed the construction of a model for echinoderm palaeoecology across marginal marine environments. The application of this model to marine environments outside the British Jurassic, such as the Middle Jurassic of France and the Western Interior, USA, has demonstrated that factors such as substrate and marine connection (salinity) have a greater bias than palaeogeographical and stratigraphic controls. I propose that the small size of these echinoderm micro-fragments and the large number found preserved, means that they can be used as tool for facies recognition alongside other more traditional fossil groups, such as foraminifera and ostracods and are far more informative than many other macrofossils currently used.
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A Geochemical Overview of Selected Palaeozoic and Mesozoic Petroleum Source Rock Analogues from Outcrop Studies, Peninsular Malaysia
More LessWith petroleum resources on the decline, oil and gas companies worldwide including Malaysia are on the lookout for unconventional petroleum accumulations. Part of this effort includes looking at older and deeper petroleum source rock intervals that could have generated hydrocarbons earlier that subsequently accumulated in older and deeper reservoir intervals. In Peninsular Malaysia, two main Tertiary petroleum systems exist (Madon et al., 2006; Tan, 2009). Madon et al. (1999) identified the Groups L and K lacustrine shales (Upper Oligocene-Lower Miocene), and Groups I and H fluvio-deltaic shales and carbonaceous/coaly shales (Lower-Middle Miocene) as the main petroleum source rock intervals for the Malay Basin. Deeper units such as sediments from Group M and pre-Group M (syn-rift) sediments are also believed to contribute to the petroleum system. The 2005 discovery in the south western part of the Malay Basin by the exploration well Anding Utara-1 penetrated a 220 m oil column in metamorphic rocks (Shahar, 2005). This is significant as it indicates the possibility of having hydrocarbon accumulations in older rocks. Such play is commonly referred to as the fractured basement play. It is believed that the Penyu Basin, which lies to the south of the Malay Basin, could potentially have similar plays as the basement there mainly consists of metamorphosed basalts and weathered tuffs (Fanani et al., 2006). However, the hydrocarbons for these fractured reservoirs, which are on basement highs are thought to be sourced from younger sedimentary rocks that are positioned lower/deeper in grabens. This study will evaluate the potential of older (i.e. Mesozoic and Palaeozoic) petroleum source rocks based on geochemical analysis of outcrop samples from Peninsular Malaysia. As the fractured basement play involves reservoir rocks that are of Cretaceous age or older, it is interesting to see if any organic-rich intervals from the Palaeozoic or Lower Mesozoic in Peninsular Malaysia could have contributed to earlier hydrocarbon generation.
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A New Approach and Prospectivity of Sand Injectite in Malaysia
Authors Askury Abd Kadir and Tengku Amran Bin Tengku MohdIn recent years, there has been increased interest in sandstone injectite features as a significant source for reserve calculation. Sand injectites are classified into ‘intrusive’ bodies, which result from the remobilization and injection of sand into fractures due to factors such as overpressure, hydrocarbon migration, diagenesis and seismicity. Their occurrences are in the form of sandstone dykes (discordant to bedding) and sills (concordant to bedding) structures. Typically, such fractures are in sedimentary strata. The development of technology and knowledge led the recognition of injectites as an attractive exploration targets with huge significance when planning and optimizing hydrocarbon recovery. They have long been considered mere geological oddities and often being
misinterpreted (Figure 1) for insignificant features as their thickness is beyond the resolution of conventional seismic data. Outcrop observation and subsurface exploration including cores, wellbore image logs and seismic sections (Figure 2) are typically utilized to recognize their assemblages and features. The objective of the study is to gain better understanding on the features and characteristics of injected sands as a new prospective fluid conduit in reservoirs as well as their mechanics, implications and challenges. This preliminary study has been conducted based on literature review of published papers, journals, books and other resources, which are gathered, analyzed and revised in accordance to the relevance of the project. Three case studies were analyzed on Gryphon, Volund and Alba Fields highlighting their successful explorations in terms of injectite styles and significance for exploration and production. The results provide better understanding on injectite features which contribute additional reserves, improve the connectivity between reservoir layers and are characterized by chaotically distributed, unconsolidated sands with high porosity and permeability, forming excellent pay zone. Injectite explorations in Gryphon, Volund and Alba fields showed their characteristics as good quality reservoirs which may not be simply ignored for future exploration targets. Do we have sand injectites in Malaysia? Perhaps, we need to re-examine an oil-prune formations in Malaysia which is more emphasis on sand injectite conceptual.
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Basin Modeling of Malay Basin Eastern Flank for Prediction of Source Rock Potential
Authors Ku Rafidah Ku Shafie and Lakhdar BenchillaThe offshore eastern flank of Malay Basin is considered a challenging phenomenon for petroleum exploration in the synrift plays. The large amount of quality data from Petronas provides an opportunity to reduce the uncertainty in geological risks to exploration success in these deep plays. The application of basin modeling technique such as PetroMod in petroleum exploration giving us the ability to illustrate petroleum generation history of potential source rocks in our study area. The 1-D basin modeling was carried out on 12 calibration wells in the eastern flank of Malay Basin with an objective to investigate the presence of mature source rock and hydrocarbon charging in the study area. The red-dotted box in Figure 1 shows the location of the study area where the
structural setting is severely affected by the tectonic evolution of the basin. Temperature data for calibration of present-day temperatures in the wells were obtained from the log header and the data were generally of good quality. Those data were corrected using
published methods, and results were generally consistent and reasonable. Most of the wells drilled in this block have penetrated the K and L groups and a few wells have penetrated the basement. Models were constructed within the PetroMod software program in the stan¬dard ways. The stratigraphy within each well was constructed as burial history by using the top formation depth and age. The deposition of all the stratigraphy in this area is based on the Regional Malay Basin Stratigraphic Chart (Figure 2).
Two source rocks were considered in this study: the Group L-Shale deposited during synrift episodes are widely interpreted as offshore lacustrine and the Group I that was deposited in the fluvial-deltaic environments (Madon et al., 1999). Hydrocarbon generation in Group L-Shale source rocks was modeled using Pepper and Corvi (1995) _TI(C), which should be appropriate for these source rocks. The Group L-Shale source rock was generated at 12.5Ma and significant oil generation was initiated at around 10.5Ma. The expulsion of large amounts of oil began at about the same time of the oil generation. This has allowed the oil to be trapped in the entire formation group (Epic Study, 1994).
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Prospectivity in the Slope Break Belts of Malay Basin Western Margin
Authors Ji Ping and Zuliyana IbrarimMalay Basin Western margin covers about 5000 km2, mainly with the steep monocline (up to 6 degree) tectonic background, which is different from other area of Malay Basin. In the Late Oligocene to Early Miocene syn-rift extension phase, Groups M, L and K were deposited in an alluvial-lacustrine setting. The slope break belts associated with fan system deposits make them a promising exploration area. The slope break belt consists of three main parts: slope, slope break and slope-toe. It can be originally because of tectonic, deposition and erosion. There are multi belts in the Western margin. And the results of the deposition are the basin floor fan, slope fan, subaqueous fan and other gravity flow fans. Lacustrine shales of M, L and K Groups are the main source rock in the area. The sandy fan bodies consist the high quality reservoirs. Lacustrine shales provide the top seal. Up-dip seal can be controlled by juxtaposition of sand against incised valley, palaeo-cliff, fault and sand pinch out. The key element and the risk is the up-dip sealing of the trap. Exploration history demonstrates the slope break belt is a good prospective area in Malay Basin. The exploration approach is also discussed, especially the geophysical studies.
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Some Differentiating Field Characteristics between the Belait & Lambir formations, North Sarawak.
Authors Mohd Syamim Ramli and E. PadmanabhanSimilarities between the general appearances of the Belait and Lambir Formation in the field have led to difficulties in distinguishing one from another. This differentiation is important as there is an ongoing E&P in this part of Sarawak. Selected outcrops from the northern and central Sarawak have been analyzed in the field to evaluate the difference between these Formations. Field observation suggested that there are at least eight differentiating characteristics between these Formations. In terms of sedimentary features, presence of asymmetrical ripple marks on the Belait Formation indicates a fluviatile environment whereas on the Lambir Formation, symmetrical ripple marks are much more common features. Cross-beddings on the Lambir Formation are also
abundantly found but it is not encountered in the Belait Formation. Fossil burrows of Ophiomorpha Nodosa are also common in the Lambir Formation but to a lesser extend in the Belait. Flow patterns features such as mud- and/or sand-filled channels are also a characteristics of the Belait Formation. Conglomerates of the Belait Formation can be found on the southern part of Sarawak. In terms of bedding and stratigraphy, heterolithics sequences are widely encountered in the Belait Formation outcrops, but rarely in the Lambir Formations. Observations on the proportions of sand and clay in these heterolithics sequences between the two Formations suggest that the Belait Formation possess a much sandier sequence. Presence of carbonaceous shales are also common in the Belait Formation whereas massive sandstones are more often encountered in the Lambir Formation. Despite these general differentitating characteristics, distinguishing some of the outcrops are still difficult as these features may not be present in all outcrops.
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Deep Overpressured Play: Second Lifeline for West Baram Delta, East Malaysia
Authors M. Hafizan Abdul Wahab and Jennifer Chin Li YenYear 2010 marks 100 years of exploration activities in the West Baram Delta offshore Sarawak, one of the most prolific deltas in Southeast Asia. Ever since, a total of more than 50 exploration wells have been drilled targeting the conventional Middle Miocene Topset Clastic Play. The declining trend in both exploration success and production rates in recent years is alarming, hence the increased urgency of testing a new play concept. The deepest well drilled recently entered an overpresurred zone at depth of about 4km, with hydrocarbons still being encountered at the last penetrated reservoir. This success has triggered numerous ideas for the new potential hydrocarbon play type in the much deeper and severe overpressured reservoirs. At these depths reservoir quality is the main risk associated with this new play. The biggest challenge for the exploration is associated with predicting the onset and magnitude of the overpressures as these have direct impact on in-place gas volumes, well design, and well deliverability.
This paper will discuss the new ideas behind evaluating the trap effectiveness, seal capacity, and reservoir quality of this overpressured play. With a renewed exploration campaign targeting the deep overpressured play it is believed the West Baram Delta HC province can be rejuvenated.
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Structural Styles of the North West Sabah and West Sulawesi Fold Thrust Belt Regions and its Implication to the Petroleum System – A Comparison
Authors Nor Farhana Nor Azidin, Allagu Balaguru and Nasaruddin AhmadOffshore North West (NW) Sabah and West Sulawesi are located in highly complex fold and thrust belts within the Sundaland plate. NW Sabah hydrocarbon exploration started in 1897 with the drilling of the Menombok-1 well. The first seismic data in the West Sulawesi were acquired in 1968. In term of geological structural evolutions in NW Sabah and West Sulawesi both areas have experienced several phases of deformation from Paleocene until Pleistocene.
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Study of Upscaling Permeability from Thin Sections Using 3D Pore Space Image and Pore Network Modeling
Authors Luluan A. Lubis and Zuhar Zahir Tuan HarithDigital rock physics technology has effectively proved in reducing time and cost to predict physical properties of reservoir rocks. However, most of the predictions are at pore-scale level. In this study we address our research on predicting permeability at core-scale. The study carries out numerical simulation on three-dimensional (3D) pore space images to predict permeability at porescale. A digital volume required for this numerical simulation is obtained from thin section images. From these images we reconstruct 3D pore space images using multiple-point statistics (MPS). Permeability from several pore space images are used to predict permeability at core-scale by using upscaling methods (arithmetic, geometric and harmonic method). The results from these predictions are expected to match well with the experiment.
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Characterizing and Modeling Natural Fracture Networks in a Tight Carbonate Reservoir in the Middle East
Fractured reservoirs are challenging to handle because of a high level of heterogeneity (Nelson, R., 2001; Bourbiaux, B. et al., 2005). In particular, natural fracture networks have a significant impact on the reservoir performance as they affect well productivity (Narr, W. et al., 2006). Therefore, understanding their significance through fracture characterization is helpful in well placement and field development. This paper presents an overview of efforts in building a 3D stochastic fracture model for reservoir characterization of a Middle Eastern tight carbonate field. This model is generated in FracaFlowTM through the analysis and integration of well data pertaining to fractures like cores (including oriented core), bore hole images (BHI), well logs, mud losses, production logging and well test data together with 3D Q-Seismic data [structural and seismic attributes and seismic facies analyses (Abdul, J.A. et al., 2010)]. The impact of lithology on fracture occurrence was quantified based on rock-typing and
distributed in a 3D geological model using a high resolution sequence stratigraphic framework. The length, dip angle and orientation of fractures as well as the shale content of the facies where they are present were defined to sort the tectonic fractures from the non-tectonic ones. It was found that multiple sub-vertical sets of diffuse fractures are generally associated with cleaner limestone units. Altogether, three sets of diffuse fractures were identified from borehole image data: N20°E, EW and N170°E. Large-scale fracture corridors, including sub-seismic faults identified from seismic analysis, were calibrated with core and BHI fractures through fracture data analysis workflows. The model finally incorporates two scales of tectonic fractures: diffuse fractures and large-scale fractures that have a direct bearing on well and field production behavior. The fracture calibration was also performed using the dynamic data set such as production log and well production data. Permeability at wells was computed in the DFN (Discrete Fracture
Network) model and matched with the real build-up data. These data were then used to propagate 3D fracture properties (fracture porosity, fracture permeability and equivalent block size or shape factor) in the upscaled geological model for constructing a full reservoir simulation model. The model proved to be very reliable as few changes of the fracture properties were needed to obtain a good history match.
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Kerogen Kinetics in Petroleum Systems Analysis: A Case Study Using Coaly Source Rocks from Malaysian Onshore Basins
Authors Peter Abolins and Wan Hasiah AbdullahKerogen kinetics, when incorporated into a petroleum systems model, play a key role in defined the timing of hydrocarbon generation, the composition of hydrocarbons generated, and hence the phase of hydrocarbons in the subsurface. Such roles and applications are discussed in various papers such as Pepper and Corvi (1995), di Primio and Horsfield (2006), and Stainforth (2009). In this study, bulk kerogen kinetics were derived for a selection of coal samples from the Malaysian onshore Tertiary basins of Batu Arang, Bintulu, Merit-Pila and Mukah-Balingian. These coals possess % vitrinite reflectance (%Ro) in the range of 0.42-0.60% thus are thermally immature to early mature for hydrocarbon generation. These coals are expected to have fair to good petroleum generating potential based on the HI values that ranges from about 100 to 500 mgHc/gTOC. Petrographically, these coals are observed to be dominated by vitrinite macerals with common occurrence of liptinitic kerogen (10-40% by volume).
The aim of this study is twofold. Firstly to compare the personalised bulk kinetics acquired here with those currently available from published literature. Secondly is to illustrate the impact of different kerogen kinetics and geochemical parameters in the context of petroleum system analysis that is commonly used in oil and gas exploration, specifically on the timing, quantity and type of hydrocarbon generated. This is achieved by incorporating the personalised kinetics and other geochemical parameters acquired here into simple generic 1D and 2D basin models constructed using the PetroMod software suite.
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Continuous Isotope Logging in Real Time While Drilling
Authors Martin Niemann, Jerome Breviere and Shell FEAST TeamStable carbon isotope (δ13C) values for light hydrocarbons (HC) are routinely used to characterise both the geochemical and geological systems encountered in the sub-surface; providing information on the HC source, thermal maturity and the occurrence of in-reservoir secondary processes (Whiticar, 1994) . Until now δ13C ratios of light HC’s are obtained from spot samples collected at the well site (Isotubes, gas bags, Vaccutainers, etc.) and analyzed off line. Depending on the geographic location of the well the reporting of gas isotope data might occur either weeks or months after samples are collected. In the latter instance the usefulness of the data for field development decisions is significantly reduced. Recent improvements in mud logging techniques now provide a tool for the continuous logging of methane (C1) stable carbon isotope values in real time while drilling. Such data provides a much higher vertical resolution with measurements every second with a typical accuracy of ±1‰. It is anticipated that δ13C measurements of ethane (C2) and propane (C3), as well as δD-C1 in real time will follow in the near future. Geoservices Isotope Logging is coupled with the Geoservices FLAIR system that provides quantitative analyses of C1 to C5 (HC’s from formation) and semi-quantitative analyses of HC’s up to octane and light aromatics (Breviere et al., 2002; McKinney et al., 2007) in order to enhance the interpretational potential of stable isotope values . The extraction of gaseous HC’s from the drilling fluid takes place as close to the bell nipple as possible under fully controlled conditions, including stable mud and air flows, stable temperature and stable pressure. The compositional analysis (FLAIR) is performed with a gas chromatographmass spectrometer (GC-MS), whereas the isotopic analysis is performed simultaneously by near infrared absorption spectroscopy. The application of this technology on a drilling site is new and field tests have shown that this technology is extremely robust and stable and performs well under
the harsh conditions on an offshore drilling site. Field tests have been performed throughout the world in order to test performance for different geological systems and especially different drilling conditions (encompassing variations for both oil and water based drilling muds, as well as differences in drill bit types). Results were compared with both Isotube data and WFT/DST gas samples. Comparison of Isotube and WFT/DST data revealed a good match, within the accuracy limitations of the Isotope Logging equipment. Further comparison indicated that the continuous character of Isotope Logging data reveals a much higher variability and complexity of δ13C-C1 depth profiles than previously observed with Isotube or Vaccutainer samples. These latter samples are only spot samples with an insufficient depth resolution to detect small scale variations and features. The high resolution of Isotope Logging real time data provides the means for in depth analysis of encountered fluids and their geological habitat, but also represents an interpretational challenge. Isotope Logging was successfully applied to delineate reservoir connectivity and compartmentalization, provided information about possible biodegradation processes within an oilcolumn and provided successfully real time information to decipher the nature of HC’s encountered in the subsurface. This presentation will provide an overview about this new well site service and discusses case studies focussing on reservoir compartmentalization and fluid separation based on
δ13C-C1 where compositional data are inconclusive.
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Litho-Facies Mapping for Qualitative Evaluation of Caprock Seal Capacity in Northeast Central Luconia Province, Offshore, Sarawak
Authors Shakila Mustaffa, Che Shaari Abdullah and Hamdan MohamadThe Miocene age Cycle IV equivalent carbonate pinnacles in Central Luconia Province Offshore Sarawak are very prolific hydrocarbon play type. However the petroleum system elements effectiveness for such play type proved highly variable for different pinnacles. The caprock facies identification and mapping highlighted in this project is an attempt to relate qualitatively the sealing rock facies type to the hydrocarbon column length preservation within the pinnacles. Interpreting seismic reflection pattern and calibrating with the well lithology profile are techniques used to classify the facies types and delineate the area of occurrence. The interval defined as caprock in this project is restricted to the stratigraphic interval spanning Cycle IV to Cycle VI (Figure 1.1). The
relative spatial distribution of the pinnacles encapsulated by distal pro-delta facies of hemi pelagic fine detritus indicated high likeliness of having hydrocarbon pool with significant column height compared with the pinnacles encapsulated by proximal delta facies.
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Integration of Fluid Inclusion Stratigraphy (FIS) in the Petroleum System Analysis of a Frontier Area in Sarawak Offshore Basin, Malaysia
More LessThe present study integrates the results of FIS into the petroleum system analysis of the North Luconia province and brings out a better understanding of the hydrocarbon generation and migration. FIS results also serves as a calibration to supplement the 3D geochemical basin modeling of the frontier deepwater offshore Sarawak basin. FIS technology is a rapid geochemical analytical technique that involves the automated analysis of volatile compounds trapped within micron-sized cavities in rock material taken from well cuttings, core or outcrop samples. These “fluid inclusions” are representative samples of subsurface fluids and are not subjected to fractionation during sampling or evaporative loss during sample storage for any length of time. Drilled cutting samples at equally spaced intervals from five offset wells analyzed to identify for any hydrocarbon presence. The FIS results in general indicate dry gas and some intermittent wet gas response anomalies in most of the wells. Anomalies are stronger in the pre-MMU section compared to the weak anomalies observed in post-MMU sequence in the wells. Well B shows gas-range hydrocarbon through most of the section with some intermittent wet gas spectra at several intervals. Thin sections show rare, blue-fluorescent, moderate gravity light oil inclusions in carbonate. Well C data reveals hydrocarbon anomalies in several zones with dry to wet gas responses, which is also proven by analysis of MDT gas samples. Well D indicates notable wet gas spectra near the bottom of the section with no visible liquid hydrocarbon inclusions or stain. Well E shows dry gas responses through most of the section with intermittent thin wet gas. Thin section of rare, blue blue-fluorescent, moderate gravity light oil inclusions is identified in sandstones. Well A contains very scarce low gas anomalies throughout the whole section and thin sections contain no visible liquid hydrocarbon inclusions or stain.
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Effective Reservoir Fluid Sampling Supports Reservoir Characterization
Authors Rahimah Abd Karim, Pedro Elias Paris Acuna, Wa Wee Wei and Sammy HaddadGood quality reservoir fluid samples are critical to ensure the accuracy of the captured fluid composition and thus accurate key reservoir fluid properties’ description, namely GOR, saturation pressure, density, and viscosity. Reliable characterization of reservoir fluid properties during the early stages of exploration and development is critical for understanding fluid composition, estimating reserves, and optimizing production or completion strategies.
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Geochemistry of Gas and Condensate in the Surma Basin, Bangladesh
The Surma basin, which contains very thick Cenozoic sediments more than 20km, produces more than 95% of gases and condensates in Bangladesh. The producing reservoirs of gases and condensates are fluvial deltaic to estuarine sandstones in the Middle to Late Miocene Bokabil and Bhuban Formations of the Surma Group, which are located below the regional seal in anticlinal structures formed in the late Pliocene and Pleistocene age. To understand the petroleum system in the Surma basin more clearly, we performed geochemical analysis for condensate and gas samples which are taken from wells in the major fields in the Surma basin.
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Representative Fluid Samples for Reservoir Fluid Evaluation and Flow Assurance Analyses: South East Asia Field
Authors Michael Tighe, Sammy Haddad and Lee Chin LimRepresentative fluid samples are essential to achieving high quality PVT and flow assurance lab analyses. This is especially important when downhole samples are acquired in an oil base mud (OBM) environment. These high quality samples are also needed to better understand reservoir and fluid behavior throughout the field life. This work presents a case study of an offshore field in East Asia that required high quality reservoir oil fluid samples for detailed PVT and flow assurance analyses. An oil bearing sand was
discovered during the development drilling phase of a predominantly gas bearing reservoir environment. It was required to take low contamination samples from this zone during the development drilling phase without compromising the primary well objective of completion as a gas producer. As such, samples had to be taken on wireline in an oil based mud (OBM) environment. Accordingly a carefully planned methodology and technology was planned and used to achieve the goal of obtaining reservoir fluid samples.
Samples acquired from a previous well in the field using traditional openhole wireline formation testing technology and methods resulted in relatively high contamination levels. High levels of OBM filtrate contamination typically have detrimental effects on the PVT analyses quality for both gas and oil samples. Rig time, cost and sticking risk also limited the time allowed for the wireline formation tester to stay stationary at a sampling depth. As a result, a decision was made to utilize a new sampling technology that allows the obtaining of low level contamination while minimizing sampling station and rig time. To achieve this goal, the job was carefully designed and monitored by operating company and service company experts in real time to ensure the required results. The sampling technology, method and field and laboratory results are presented in this work [1, 2, 3].
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A Comparison Between 1D and 3D Basin Simulations of Thermal Evolution and Hydrocarbon Generation - A Case Study in the South Malay Basin, Offshore Peninsular Malaysia
Authors Azlina Anuar and M. Jamaal HoesniOne of the first steps when undertaking a basin modeling project is to define the thermal evolution of the study area via 1D thermal calibration. The resulting thermal model, often defined by heat flow maps, is then applied to subsequent 2D and 3D simulations. This study offers a comparison between 1D and 3D thermal modelling of the South Malay Basin and illustrates the need to recalibrate the 1D thermal model before its application to a full 3D block simulation. A systematic approach towards determining the top-of basement heat flow in the South Malay Basin was adopted, taking into account the three main heat sources of the basin: asthenospheric heat (-factor dependent in rift settings) and radiogenic heat production from the crust as well as the sediments. Using basin modeling software, the heat flow variations through geologic time were determined by means of vitrinite reflectance (from standard measurement and FAMM methods) and measured present-day temperature data (from drill stem and production tests)
as the main calibration points. Three top-of-basement heat flow maps for the different stages of the South Malay Basin development, namely the pre-rift, post rift, and the pre-inversion and folding phases were initially defined via 1D thermal calibration (Anuar et al, 2009). Having established the 1D-heat flow distribution patterns through time by incorporating the relevant stretching factors as determined by Madon & Watts (1998), these maps were then used as input for the 3D maturity modeling.
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